bore hole seismic -Training-part one.pdf

March 22, 2018 | Author: Mohamed Ibrahim Shihataa | Category: Reflection Seismology, Waves, Reflection (Physics), Refraction, Polarization (Waves)
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Mohamed Shihataa SHAHIK 1/11/2015


Part I introduction for seismic bore hole Table of Contents Casing borne signal .......................................................................................................................................... 16 Tube wave arrivals ........................................................................................................................................... 17 Interface waves .............................................................................................................................................. 18 Borehole Seismic definition ............................................................................................................................. 19 Why borehole seismic? ................................................................................................................................... 19 More questions that BHS could answer: .................................................................................................... 22 Objectives of Well-Seismic Ties ....................................................................................................................... 23 Types of seismic borehole ............................................................................................................................... 25 Chapter 2: Acoustic well logging ......................................................................................................................... 27 Equipment and data acquisition...................................................................................................................... 27 A. Operations ............................................................................................................................................ 28 B. Calibration............................................................................................................................................. 28 C. Types of tool ......................................................................................................................................... 28 ..................................................................................................................................................................... 30 Different types of logging tools................................................................................................................... 30 Presentation of acoustic log data ................................................................................................................... 33 ( 1) propagation velocity, .......................................................................................................................... 35 (2) Attenuation, ........................................................................................................................................... 35 (3) Frequency ............................................................................................................................................... 35 A.

Estimation of velocity and integrated travel time (TTI)....................................................................... 35

Chapter 3: SEISMIC WELL SURVEYING................................................................................................................. 38 DATA ACQUISITION ......................................................................................................................................... 38 The well velocity survey technique ............................................................................................................. 38 Operation of a seismic well survey .............................................................................................................. 39 Check shot ....................................................................................................................................................... 40 Check shots notes ............................................................................................................................................ 41 Check Shot Surveys Interpretation .................................................................................................................. 41 Chapter 4: Vertical seismic profiling .................................................................................................................... 46 Introduction and history of VSPs ..................................................................................................................... 46 Vertical seismic profiles ................................................................................................................................... 47 VSP operations................................................................................................................................................. 48 VSP principles .................................................................................................................................................. 49 2

Identification and origin of primary reflections .......................................................................................... 49 Identification and origin of multiple reflections.......................................................................................... 50 VSP data Acquisition ........................................................................................................................................ 51 Field Equipment ........................................................................................................................................... 51 GENERAL REQUIREMENTS OF VSP RECEIVERS ............................................................................................ 59 MULTI-LEVEL RECEIVER ARRAYS .................................................................................................................. 65 Receiver choice notes: ................................................................................................................................. 68 Recording Equipment ...................................................................................................................................... 73 Why must there be these facilities? ............................................................................................................ 78 Sources ........................................................................................................................................................ 78 Onshore Sources.......................................................................................................................................... 87 Field Technique............................................................................................................................................ 92 Field Quality Control .................................................................................................................................... 95 CHAPTER 5 :VSP PROCESSING ........................................................................................................................... 103 VSP processing steps ......................................................................................................................................... 110 Data preparation and editing ........................................................................................................................ 111 ii) Use of source signature deconvolution for marine data ....................................................................... 112 (iii) Accurate alignment of records ............................................................................................................ 113 (iv) Summing ........................................................................................................................................... 114 (v) Amplitude recovery .............................................................................................................................. 115 (vi) Filtering ................................................................................................................................................ 115 Separation of upgoing and downgoing wavefields ....................................................................................... 117 Aliasing and VSP data ................................................................................................................................ 118 Wavefield separation methods.................................................................................................................. 121 Parametric wavefield separation............................................................................................................... 125 Wavefield separation in real data .............................................................................................................. 127 Noise and unwanted signal ........................................................................................................................... 138 (I) Mechanical/electrical ............................................................................................................................ 138 CHAPTER 6: ESPECIAL TOPICS…………………………………………………………………….…………………….….……………….……..142 Types of VSP surveys ......................................................................................................................................... 142 3-component processing ................................................................................................................................... 144 Imaging of VSP data ........................................................................................................................................... 147 Walkaway VSP surveys ...................................................................................................................................... 150 3D-VSP Surveys .......................................................................................................................................... 153 Shooting Patterns ...................................................................................................................................... 155 4D-VSP Surveys .......................................................................................................................................... 155 Interpretation of rig-source VSPs ...................................................................................................................... 156 3

Dipping reflectors and diffractions ................................................................................................................ 156 Identification and origin of primary reflections ........................................................................................ 158 Identification and origin of multiple reflections........................................................................................ 160 VSP - seismic comparisons............................................................................................................................. 161

Chapter 1 introduction Geophysical principles: Seismic method and response Introduction Conventional reflection seismic technology uses acoustic waves (“sound”) to image the subsurface • Conceptually, as shown below , we begin by generating a bang. The sound travels down into the earth, some of it gets reflected off buried interfaces, and we record the reflected energy (“echoes”). – The distance from the surface to buried horizons is measured in time – (Two-way traveltime - TWT). – If we know the velocity of sound in the propagating medium we can derive true depths –In practice we need to determine the optimal source of acoustic energy for the situation at hand, there is more than one interface in the subsurface and we need to repeat the exercise many times in order to generate a seismic profile or volume – Ship-towed airguns used at sea – Dynamite or vibroseis used on land

Figure.1: generation of seismic wave 4

Seismic Waves The principle of sound propagation, while it can be very complex, is familiar. Consider a pebble dropped in still water. When it hits the water’s surface, ripples can be seen propagating away from the center in circular patterns that get progressively larger in diameter (Figure 1). A close look shows that the water particles do not physically travel away from where the pebble was dropped. Instead they displace adjacent particles vertically then return to their original positions. The energy imparted to the water by the pebble’s dropping is transmitted along the surface of the water by continuous and progressive displacement of adjacent water particles. A similar process can be visualized in the vertical plane, indicating that wave propagation is a three dimensional phenomenon.( Gadallah and Fisher,2009).

Figure.2: example of generation of seismic wave when drop pebbles in water

Wave ray path In comparing seismic wave propagation to the wave generated around a pebble thrown in the water, replace the pebble with a device such as an explosive or vibrator that introduces energy into the ground. This energy initially propagates as expanding spherical shells through the earth. A photograph of the traveling wave motion taken at a particular time would show a connected set of disturbances a certain distance from the source. This leading edge of the energy is called a wave front. Many investigations of seismic wave propagation in three dimensions are best done by the use of wavefronts. Beginning at the source and connecting equivalent points on successive wave fronts by perpendicular lines, gives the directional description of wave propagation. The connecting lines form a ray, which is a simple representation of a threedimensional phenomenon. Remember, when we use a ray diagram we are referring to the wave propagation in that particular direction; that is, the wave fronts are perpendicular to the ray at all points (see Fig. 3).


Figure.3: example of generation ray path and waveform When we swim in sea we can feel the water wave push up and down (figure4). we can generated seismic wave like water wave ; geoscientist can uses sources for generated seismic wave that wave shut down into the earth that wave can measure after reflection from subsurface layers by geophones in land and hydrophone in sea .

Figure.4: example of water wave that push up and down.



Figure 5 steps for generation seismic wave, a) use sources to generate pulses ,b)seismic wave propagate the earth surface ,c) returned wave measures by receivers.

Types of Seismic Waves Sound propagates through the air as changes in air pressure. Air molecules are alternately compressed (compressions) and pulled apart (rarefactions) as sound travels through the air. This phenomenon is often called a sound wave but also as a compressional wave, a longitudinal wave, or a P-wave. Figure 6 shows three types of seismic wave, P-waves can propagate in solids, liquids, and gasses. There is another kind of seismic wave that propagates only in solids. This is called a shear wave or an S-wave. The latter term is preferred in this book. Motion induced by the S-wave is perpendicular to the direction of propagation, i.e. – up and down or side-to-side, Surface waves are another kind of seismic waves that exist at the boundary of the propagating medium. The Rayleigh wave is one kind of a surface wave. It exhibits a retrograde elliptical particle motion .

Figure.6: three types of seismic wave. Figure7 illustrates P-wave propagation. Darkened areas indicate compressions.The positions of the compression at times t1 through 6t1 are shown from top to bottom. Note that the pulse propagates a distance dp over a time of 6t1– t1= 5t1. The distance traveled divided by the time taken is the propagation velocity, symbolized Vp for P-waves


Figure.7: P wave propagation Figure 8 illustrates propagation of an S-wave pulse. Note that the S-wave propagates a distance ds in the time 5t1. The S-wave velocity, designated as Vs, is ds/5t1. Since ds is less than dp, it can be seen that Vs, < Vp. That is, S-waves propagate more slowly than Pwaves.

Figure.8: S wave propagations Figure 9 shows motion of a particle over one period as a Rayleigh waves propagates from left to right. The Rayleigh wave is often recorded on seismic records taken on land. It is then usually called ground roll. Love waves are similar surface wave in which the particle motion is similar to S-waves. However, Love wave motion is only parallel to the surface


Figure.9: surface wave propagations

Reflection and Refraction As a first departure from the simplest earth model, consider a layered earth. What happens when an incident compressional wave strikes a boundary between two media with different velocities of wave propagation and/or different densities? Answer: Part of the energy is reflected from the boundary and the rest is transmitted into the next layer. The sum of the reflected and transmitted amplitudes is equal to the incident amplitude. Figure.10: shows Interface Are the boundaries where the properties of the earth media change depend on Particle structure , different of Density (), Wave Velocity (V)

Interface 1

Interface 3

Figure.10: shows Interfaces between three layers.


The relative sizes of the transmitted and reflected amplitudes depend on the contrast in acoustic impedances of the rocks on each side of the interface. While it is difficult to precisely relate acoustic impedance to actual rock properties, usually the harder the rocks the larger the acoustic impedance at their interface. The following equation defines the reflection coefficient (RC) in terms of AI for normal incidence of a seismic pulse at an AI boundary:

The acoustic impedance of a rock is determined by multiplying its density by its P-wave velocity, i.e., V. Acoustic impedance is generally designated as Z. Consider a P-wave of amplitude A0 that is normally incident on an interface between two layers having seismic impedances (product of velocity and density) of Z1 and Z2 (See Figure.11). The result is a transmitted ray of amplitude A2 that travels on through the interface in the same direction as the incident ray, and a reflected ray of amplitude A1 that returns to the source along the path of the incident ray. The reflection coefficient R is the ratio of the amplitude A1 of the reflected ray to the amplitude Ao of the incident ray,

The magnitude and polarity of the reflection coefficient depends on the difference between seismic impedances of layers 1 and 2, Z1 and Z2. Large differences (Z2– Z1) in seismic impedances results in relatively large reflection coefficients. If the seismic impedance of layer 1 is larger than that of layer 2, the reflection coefficient is negative and the polarity of the reflected wave is reversed. Some Typical values of reflection coefficients for near-surface reflectors and some good subsurface reflectors are shown below:

Incident Energy

Reflected Energy A


V ρ1 1 V2 ρ2 10

Boundary/Reflector Normal

Refracted / Transmitted

Figure.11: reflection and transmitted waves

When a P-ray strikes an interface at an angle other than 90◦, reflected and transmitted P-rays are generated as in the case of normal incidence. In such cases, however, some of the incident P-wave energy is converted into reflected and transmitted Swaves (see Fig. 3.6). The resulting S-waves, called SV waves, are polarized in the vertical plane. The Zoeppritz’ equations are a relatively complex set of equations that allow calculation of the amplitudes of the two reflected and the two transmitted Basic waves as functions of the angle of incidence. The equations require P- and S-wave velocities (VP2, VS2, VP1, and VS1 in Figure.12) plus densities on both sides of the boundary. The S-waves that are called converted rays contain information that can help identify fractured zones in reservoir rocks but this book will discuss compressional waves.

Figure. 12: Reflection and refraction of an incident Pwave. VP2 > VS2 > VP1 >VS1 1.3.1Snell’s Law This relationship was originally developed in the study of optics. It does, however, apply equally well to seismic waves. Its major application is to determine angles of reflection and refraction from the incidence of seismic waves on layer boundaries at angles other than 90◦. Snell’s law of reflection states that the angle at which a ray is reflected is equal to the angle of incidence. Both the angle of incidence and the angle of reflection are measured from the normal to the boundary between two layers having different seismic impedances. The portion of incident energy that is transmitted through the boundary and into the second layer with changed direction of propagation is called a refracted ray. The direction of the refracted ray depends upon the ratio of the velocities in the two layers. If the velocity in layer 2 is faster than that of layer 1, 11

the refracted ray is bent toward the horizontal. If the velocity in layer 2 is slower than that of layer 1, the refracted ray is bent toward the vertical (Figure.13).

Sin A = Sin C Incide nt V1 V2

V1 V2 Reflecte d


Boundary/Reflect or

ρ2 Normal

Figure.13: Snell law explanation

Refracted / Transmitted Energy

Critical Angle and Head Waves When the P-wave velocity is higher in the underlying layer, the refracted P-ray is “bent” toward the boundary. As the angle of incidence increases the refracted P-ray will be bent to where it is just below and along the boundary, which means that the angle of refraction is 90◦. The particular angle of critical angle is equal to the ratio of velocities across the boundary or interface. This wave, known as a head wave, passes up obliquely through the upper layer

Figure.14: Critical refraction/head wave

The majority of seismic sources are designed to provide an energy pulse which propagates as a compressional (P) wave. VSPs, however, usually exhibit other wave types with distinctive event patterns. These need to be recognised either because they may provide additional useful information 12

concerning the geophysical or geological environment or because they may degrade the data with which one is trying to work. In the first category are various types of shear (S) or distortional waves and in the second are casing borne signals and tube waves which are dependent on the column of fluid in the borehole. These categories are not absolute, useful information can be gleaned from the observation of tube waves for example, likewise much of the shear wave activity in VSPs is not sufficiently consistent to enable its use in any analytical studies

Shear (S) waves. P-wave energy propagates with a particle motion that is coincident with the direction of propagation; S-wave energy particle motion is perpendicular to the direction of propagation. In the absence of an Swave energy source at the surface, any S-wave motion detected by the downhole geophone is a result of mode conversion at some interface from P- to S-wave, see figure 3.1. This conversion usually occurs as the energy passes through an acoustic impedance contrast somewhere between the source and the detector, although mode conversion on reflection is commonplace. The reverse mode conversion is also possible and hence a large family of wave patterns may be propagating in the subsurface. To further complicate matters, S-wave motions have both vertical and horizontal components which may themselves be subject to conversion. Observation of S-wave arrivals in VSP data sets is therefore sometimes complicated but can provide useful information about the formations surrounding the

Figure.15:seismic wave propagation


Increase in data resolution By definition:

P-wave velocity,



where:  = formation density rigidity modulus of the medium (shear = bulk of the medium = modulus)modulus (incompressibility)  For a rock  is positive and thus:

This implies


(For a fluid

 = 0 and so VS = 0)

Generally the S-wave velocity in a formation is 50% to 75% of the P-wave velocity. As a consequence of this at the same frequency the wavelength of the S-wave will be shorter than that of the P-waves. This leads one to the observation that for the same recorded bandwidth, a VSP S-wave image is capable of better resolution than the corresponding P- wave image. It is possible, therefore, that a more detailed study of the subsurface could be made using S rather than P- wave images. As with all such simple statements the practical aspects of this are not as simple as one might imagine and few VSPs contain sufficient mode-converted energy to provide a meaningful image over the majority of the well

Application of Vs wave 14

Detection of fracture zones Highly fractured rock attenuates seismic waves, particularly S-waves, and their velocities are strongly affected by lowering the rigidity or density of the medium. STEWART et al (1984), demonstrated an application of VSP data recorded before and after a hydraulic fracturing operation in Antrim oil shales in which they delineated the fracture zone near the borehole. They basically observed a difference in the arrival times of the P- and S-waves in the VSP before and after fracturing. Another property which can be made use of in this application is shear wave birefringence (shear wave splitting). A shear wave incident at a fractured zone, with a polarisation direction at an angle to the predominant direction of the fractures, will experience a partitioning of the energy into two components one parallel and one perpendicular to the fracture orientation. The propagation velocities of these two polarisations will be different, the polarisation parallel to the fractures being close to that of the rock matrix velocity, the other polarisation influenced to a greater extent by any fluid in the fractures. Observation of the two polarisation can lead to a determination of the predominant fracture orientation, and in reservoirs where the primary porosity and permeability are due to such micro-cracks, can lead to a determination of the direction of principle stress. This information can then be of use in the future development of the field.

2. Determination of lithological parameters Recording P- and S-waves during a VSP survey provides reliable measures of the formation interval velocities for each wave type. A direct application of this is that pore fluids have different effects on the two velocities as well as on the rock matrix density. It follows that if the ratio of P- to S-wave velocities can be derived from the VSP, the lithological parameter can be inferred or its equivalent expressed in terms of Poisson's ratio (ratio of the transverse contraction to longitudinal extension) which can be predicted as:


The ratio VP/VS is more reliable than the seismic P-wave interval velocities in identification of rock matrix type (carbonate or sandstone) and fluid saturation in the rock pores. This applies particularly to gas reservoirs.

Observation of anisotropy in the subsurface A medium which has the same physical properties regardless of the direction in which they are measured is termed an ISOTROPIC medium. If there is any variation of the physical property depending on direction then the medium is ANISOTROPIC. In terms of seismic energy propagation, anisotropy denotes a difference between the measured velocities parallel and normal to the bedding. A practical consideration arising from this is that the horizontally and vertically polarised S-waves (SH and SV components) have different velocities. If both wave types are present in the VSP and can be separated from one-another and the P-wave energy, information concerning the anisotropy can be obtained. Use of this data for this purpose is not something that is generally undertaken as the results are by no means clear in every case. This is particularly true if there is any shear wave splitting due to the presence of fractured zones as the two phenomena are not easily distinguishable one from the other. All the possibilities noted above are certainly of interest but do not form part of the general "production" environment of the VSP survey. In most cases one is preoccupied with the production of a P-wave reflection image and as such any Swave arrivals within the data are generally considered to be coherent noise, most of the processing of which is concerned with their removal from the data set. With this in mind, an important concern throughout all aspects of VSP processing and interpretation is the reduction of all unwanted wavefields. Two important "noise" arrivals are those supported by the casing in the well and the fluid column.

Casing borne signal This is the result of energy travelling either laterally or vertically from the source to the well exciting the metal casing set in the borehole to prevent its collapse. This excitation gives rise to the propagation of an extensional wave along the length of the casing. On the face of it, this would appear to be an enormous problem as most wells have at least one and as many as four or five strings of casing at the time the VSP is recorded. Fortunately there are several factors which minimise the effect of these types of arrival. Firstly the manner in which the casing is set has a great bearing on the incidence of casing arrivals. In the majority of wells the casing is cemented in place effectively bonding the steel to the formations, this cementing is also performed between successive strings of casing set one inside the other. If the cementing is performed such that the bond is good for all parts of the well then any excitation of the casing is almost immediately damped and energy does not propagate down the casing. This effect is also achieved for single strings if the formation "fills back" around the casing. The effect is most prevalent in the shallow sections of holes with multiple casing strings and is usually as a result of poorly cemented sections of casing. These are quite a common occurrence as financial constraints placed on the drilling operations usually mean only the minimum amount of cementing is performed. The casing arrivals are very easy to recognise as they propagate at a velocity characteristic of the steel of about 5300 m/s (17500 ft/s) and are generally high frequency events which occur before the expected seismic direct arrival time. These arrivals are usually of high amplitude and generally obscure the real seismic arrivals to the extent that if present on a geophone trace they will usually preclude its inclusion in any VSP processing. Because the casing signal travels at such high velocities 16

and rarely persists for more than 100 to 200 ms, the majority of VSPs exhibiting such arrivals are not affected over the area of interest, however, the conditions that permit the transmission of such arrivals may of themselves degrade the VSP data. Figure 3.2 illustrates a typical casing arrival, it also indicates that the arrivals are coherent between successive shots at a geophone level and therefore cannot be removed by summation.

Tube wave arrivals The tube wave is an energy mode that travels along the interface between the mud column and the borehole wall. This class of arrivals can have a severe interference effect and must be successfully dealt with in processing for any information to be derived from the part of the VSP affected in this manner. Tube waves as with casing arrivals have a characteristic velocity, generally less than 1500 m/s (5000 ft/s) although the absolute value is fluid dependent. There is little variation of the velocity as one progresses down the well, and the wavefield experiences no amplitude loss due to spherical divergence. In general these arrivals are generated by laterally travelling energy exciting the fluid column in much the same way as the air in an organ pipe is excited. The tube wave is more persistent than casing arrivals and is therefore usually more troublesome when it occurs. The effects can sometimes be reduced by changing the source location, by reducing the level of the fluid in the borehole to below the level at which the excitation occurs (a solution not enamoured of drilling engineers!) or by fitting some means of blocking the propagation of the energy. Figure 3.3 illustrates a particularly good example of a tube wave. All is not negative on the tube wave front. Energy impinging on fractured zones in open holes can under certain circumstances give rise to both up and downward travelling tube waves whose point of generation coincides with the fractured zone. From a very simplistic viewpoint this is caused by the fractures undergoing a "squeezing" action, energy is removed from the advancing seismic wavefront and transferred to the borehole fluids. If one uses a pressure sensitive (hydrophone) detector then the occurrence of tube waves can be used to diagnose fractured regions within the well, see figure for an example of this type of data.

Figure.15 tube wave


Interface waves Pseudo-Rayleigh waves are reflected conical dispersive waves (B10t, 1952) At low frequencies ( 25 kHz) their propagation velocity becomes asymptotic to the compressional wave velocity of the fluid This type of wave is only encountered in fast formations Stoneley waves are scattered along mterfaces, in fast formations, they show group and phase velocities at high frequencies that increase asymptotically towards the propagation velocity in the fluid. In slow formations, these waves are more highly dispersed and are more sensitive to parameters linked to S wave propagation At low frequencies, Stoneley waves are analogous to the tube waves observed m VSP surveys. Fluid waves are guided (or channel) waves, showing very little scattering, which are propagated through the fluid located between the tool and the borehole wall.(figure.16).

Figure 16: stoneley wave


Borehole Seismic definition The name given to seismic surveys, where the seismic sensors are normally lowered into the well bore. The seismic sensors may be single component, 3 component, and could be deployed at single levels, or several levels in the well bore

Why borehole seismic? 

The comparison between a seismic section (in two-way time) and an acoustic log (interval transit time versus depth ) leads to questions about the relations between the two types of data and the possible combination of their corresponding datasets (Figure.. 17,18).

The acoustic log provides an obvious link between geophysics, seismic and well logging data. Although covering different frequency bands (acoustic logs: in the order of 10 kHz; seismic: ranging from about 10 to I 00 Hz), the two techniques are based on the same Jaws of wave propagation but with different mythologies. Under a certain number of conditions, the seismic measurements collected at these different frequencies can be compared and used to improve knowledge of reservoir characteristics. Acoustic log has a very different vertical and lateral range of investigation compared with seismic surveys (surface or borehole) (figure.19)..

Figure.17: surface wave measurement.


Figure.18: Well and surface data matching

figure.19: important of borehole seismic. 


the depth-to-time conversion of well log data is carried out using the acoustic velocities of formations obtained from acoustic logs (sonic logs), this method is insufficient to provide an effective comparison between seismic and logging survey datasets. There are discrepancies between the acoustic velocities derived from logging and seismic surveys, it is thus necessary to perform a sonic calibration for the depth-time conversion (figure.20).

Figure.20: tie between seismic time and log depths


The sonic log calibration involves establishing a time-depth relation consistent with the seismic survey yielding the same vertical resolution provided by the sonic log. In other words, the sonic log measurements are recalculated to be compatible with variations in fluid and lithological composition, so the integrated travel time between two depth readings can be matched with the corresponding data from well velocity surveys.

A well velocity (or check shot) survey is carried out by measuring the travel times of head waves emitted from a surface shot by means of a geophone or an hydrophone placed at various depths in a well. Check shot surveys are the predecessor of vertical seismic profiles. Vertical seismic profiles (VSP) may use more sophisticated tools to record the entire seismic wave train generated by surface source and transmitted through the earth filter downward. A VSP survey is usually recorded at a much higher density of depth points but may not cover the entire wellbore.

Once the calibration has been carried out and a corrected time-depth relation established, it is possible to compare the well (logs) with surface seismic data. One technique employed for this purpose is the creation of a synthetic seismogram using density and acoustic velocity logs. Bulk density and acoustic velocity logs are used to create an acoustic impedance log. After depth-time conversion, the reflection coefficients derived from the acoustic impedance log are then convolved with an appropriate wavelet to produce the synthetic seismic section (often referred to as a seismogram).

Seismic data obtained from the vertical seismic profile (VSP) with or without source offset, are processed to provide seismograms at seismic frequencies that are directly comparable with synthetic sections and surface seismic sections. Even though these data have a poorer vertical resolution compared with well logging and a restricted frequency range, they can be used to adjust profiles obtained from seismic reflection surveys carried out at the surface. In addition, borehole seismic surveys can be used for defining appropriate

operators for stratigraphic deconvo• lution and converting seismic sections to acoustic impedance sections or logs.

More questions that BHS could answer: ☯ Where is my reservoir top on my seismic section? ☯ Are there faults near my borehole? ☯ How far my reservoir laterally extends? ☯ Where is my desired formation top in the well below TD? ☯ Is there overpressure zone below TD? ☯ I want to make synthetic seismograms! ☯ I want to make a velocity model at the well location! ☯ I need information to better process my surface seismic data!

Figure.21: VSP applications


Objectives of Well-Seismic Ties 

The objectives for performing a well-seismic tie are listed here

Wells, of course, are registered in units of depth – feet or meters

Seismic data is recorded and usually worked with a vertical scale of 2-way travel time

To relate well data to seismic data, and vice versa, we have to handle this change in vertical scale units (Figure23)

Thus: Well-seismic ties allow well data, measured in units of depth, to be compared to seismic data, measured in units of time This allows us to relate horizon tops identified in a well with specific reflections on the seismic section We use sonic and density well logs to generate a synthetic seismic trace The synthetic trace is compared to the real seismic data collected near the well location

The well-seismic tie is the bridge we need to go from seismic “wiggles” to the rocks that produced the “wiggles” and our interpretation of the subsurface geology (figure 22)

Figure.22: well tie example


o The purpose and required accuracy of a well-seismic tie varies with the stage of our studies o If we are doing regional mapping, e.g., mapping a significant erosional unconformity or a flooding surface, then our tie does not need to be very precise, within 1 or 2 seismic cycles (peaks or troughs) – and the seismic data quality does not have to be very good o In the exploration stage, we would like to tie well data, e.g., the top of a stratigraphic horizon/marker within ½ a cycle 

This requires good seismic data quality

o In the exploitation stage (development & production), we need to not only know the seismic event within ½ a cycle, but the shape of the real and modeled seismic trace should be quite similar For this, we need very good seismic data quality If we obtain a good character (shape) tie between the real and synthetic traces, then:

Figure.23: well tie usages


We would then be able to extract various seismic attributes (measures of the seismic wavelets) to predict rock and fluid properties

We may also be able to use a process called inversion to transform the seismic data into an estimate of the rock properties in crosssection views or as a 3D volume (if we have 3D seismic data)

Types of seismic borehole • • •

Acoustic well log Check shot VSP vertical seismic profiling zero-offset VSP Deviated wells: Vertical-incidence checkshot and walkabove VSP Offset VSP, walkaway VSP, and walkaround VSP Three-dimensional VSP Salt-proximity survey Crosswell VSP and reverse VSP Borehole seismic while drilling Drill-Bit Seismic survey seismicVISIONservice while drilling Borehole microseismic surve

Figure. 24: carton for bore hole seismic types



Chapter 2: Acoustic well logging The use of acoustic well logging to determine the cornpressional wave velocity of a formation ts a routine and relatively Long established practice (Summers and Broding, 1952, Vogel, 1952) More recently, however, the full waveform is recorded in order to determine the propagation velocities of the different types of waves and measure certain petrophysical properl!es with a view to obtaining lithological information (Arditty et al , 1984, Matthieu and Toksoz, 1984, Paillet and Turpening, 1984 ).

Equipment and data acquisition The different features of acoustic logging tools are outlined below (I) By usmg tools with multiple transmitters and receivers it ts possible to create stacks similar to surface seismic reflection survey stacks, common shot point, common reflection point and common receiver point. These data can be processed in a similar way to seismic surveys. (2) When tools are equipped with a large number of transmitters and receivers, data acquisition is performed sequentially by interrogating each transmitter-receiver pair m tum With a limited number of transmitters and receivers. data acquisiuon can be earned out simultaneously from the same some pulse using several receivers. (3) The transrmtter-receiver "offset" and the mter receiver "spacing" determine respectively the depth of mvestigatron and vertical resolution of the log The vertical resolution is generally taken to be the receiver spacing ( 15-30 cm). (4) The depth of investigation will be determined by optimising the path between transmitter and receiver m the mud column, invaded or altered zone and the virgin zone Depending on the acoustic parameters of the media and of the tool geometric, the depth of mvesngation can then vary from 2 cm to l meter Thus. m the usual case where the invaded zone is damaged and hence "slower", a short spacing tool will g r ve a greater Llt than a Jong spac mg tool which may read deeper into the formation. (5) Sonic tools with long transrrutter-recerver spacings enable a good time discrimination of the different arrivals, provided that the source rs sufficiently powerful and the attenuation of the traversed media is not excessively high. (6) The dominant frequency of the transmitter pulse (approximately 10 kHz) and the frequency bandwidth of the receiver (the ceramics used have a very wide frequency response 100 Hz 20 kHz) are important charactensllcs of the available tools. (7) The time sampling step is generally a few microseconds for a listening milliseconds. 27


of a few

(8) Tools display different mechanical charac teristics , some may be rrgid avoid wave propagation via the tool body) while others are flexible.

(machined to

A. Operations For conventional operations and small diameter boreholes { < 5 m) generally dnlled in the oil industry, sonic logs are run with axially symmetric tools that are centred in liquid-filled wells {mud or water). The presence of gas bubbles in the mud usually leads to a mediocre quality of recording. In large-diameter boreholes, the tool maintained in an off center poison in order to avoid excessive dispersion of waves m the mud The logging speed rs usually 10-15 meters per minute

B. Calibration Strictly speaking, the acoustic log does not require any calibration since the measurement of time is based on a quartz crystal with a precisely defined oscillation frequency, thus leading to almost no error m the calculated velocity Several sequences of pulses are used in order to provide a measurement 6 inch intervals. Even though the lime measurement relatively precise, the first arrival detection technique can lead to significant errors

C. Types of tool 1. Monopole tools The conventional some logging tool has an axial symmetry and ts equipped with multidirectional receivers. A compressional wave rs generated m the fluid by the transmitter, thus giving nse to a compres• sionnal wave (P wave) and a shear wave (S wave) m the surrounding formation at the critical angles of refraction (see Fig. 25)

Figure:25: Conventional acoustic logging sketch showing generation of P and et al., 1984)

S waves. (Williams

In a vertical well, this type of tool enables the recording of five modes of wave propagation (see following section, Presentation of acoustic log). 28

( l) refracted P waves, (2) Refracted S waves, only in fast formations, (3) fluid waves, (4) Two types of dispersed tube waves, corresponding to the pseudo-Rayleigh and Stonely waves

2. Tools with dipole-typs source Information on S wave propagation in both slow and fast formations may be obtained through the use of tools equipped with polarised transmitters and receivers. This type of tool generates P waves that are polarised at right angles to the axis of the well. The P waves create flexure modes at the borehole walls which give rise to pseudo shear waves travelling through the formation parallel to the axis of the well Figure 26 illustrates the principle of operation of this type of tool.

Figure.25: Sketch showing asymmetric transmitter used for generation of S waves. (After Williams et al., 1984) Mobil Oil has developed a dipole source tool known as SWAL (Shear Wave Acoustic Logging tool; Zemanek et al., 1984) where the transmitters and receivers are constructed using a technology based on the work of Sims (1968). In a SWAL tool, the transmitter and receivers are linked by a 7-conductor cable. The distance separating the transmitter and the nearest receiver may vary from 6 to 15 feet, while the distance between the two receivers is 3-5 feet. The transmitter frequencies are in the band 1-3 kHz.


Schlumberger proposes a LOOI of rhe same type known as DSIT (Dipole Sonic Imaging Tool) which has the un ique feature of being able lo operate in both monopole and dipole modes. Figure 20 presents a comparison between logs obtained by LSAL (long Spaced Acoustic Log, - also a Mobil monopole tool) and SWAL tools in a seisrnically slow formation (Figure.26)

Figure.26: Comparison between Long Spaced Acoustic Log (LSAL)and Shear Wave Acoustic Log tSWAL1 recorded in unconsolidated Miocene formations.(Williams N al .. 1984)

Different types of logging tools The acoustic logging wvl~ used by different contractors (Fig. 1.12) provide either realtime measurements of compressional wave velocity or are designed for full waveform data acquisition. The following examples arc taken from the various available products:

Monopole source or conventional

sonic tools:

the BHC sonic and LSS (Long Spacing Sonic) tools of Schlumberger. tne acoustolog of Atlas Wireline and the Full Wave Sonic Tool of Halliburton Logging services. a sonde developed by the Society d'Erudes de Me sures et de Maint enunce (SEMM). which is a flexible tool equipped for simulaneous data acquisition on either the two nearest or the two farthest receivers, Mobil's flexible LSAL tool (Long Spaced Acoustic Logging:, William, ct al.. 1984). with transmitter-receiver and inter-receiver connections being made by cable, 30

The flexible tool. a product of El]• Aquitaine, the Array Sonic (SDT-A/C r. first proposed by Schlumberger in 1984 (Morns el al., 1984). 2) S wave dipole emitter tools • Mobil's SWAL tool (3) Mixed type tools (operating both in single-pole and dipole modes) • Schlumberger'» DSIT, • The MAC tool of Atlas Wireline Services Figure 21 illustrates the main features of some these tools (see manufacturers more detailed information).

Figure.27: Some examples of acoustic


logging tools




Presentation of acoustic log data The standard way of presenting acoustic data is m the form of depth logs, the most common presentation is the ∆t (interval transit time or slowness) versus depth for P waves, which can equally be used for Sor Stoneley waves. In addtion, the integrated P wave transit time (also termed TII Transit Time Integrated, Figure.28 ) is also indicated on the log.

Figure.28: example of a sonic log, showing interval(∆t),combine with GR log. Full waveform data can also be plotted as common-offset sections, or alternatively a, gathers of common source or receiver points. Which are analogous to the sections utilized 33

in seismic surveying. A common-offset section is made up of a set of sonic recordings plotted as a function of depth, the measurements being obtained with a constant transmitter-receiver distance roftseu. Full waveform darn may also be presented as a VDL Variable Density Log) ,which is a continuous plot of the z-axis of the waveform with the amplitude Variations being coded in grey scales. The series of common-offset sections presented below serve to illustrate the different wave propagation modes. With single-pole sources, the most commonl observed mode- an• due to refraction between the well fluid and the furma1ion: in fast formations. Compressional and shear waves are encountered as well as interface waves of the Stoneley or pseudo Rayleiuh pc.. Figure.29 is an example of a common-offset section showing clearly distinct modes of propagation that was obtained with a 3 m transmitter and receiver distance.

figure.29: Common-offset acoustic section.


Obtaining acoustic parameters from log data The following acoustic parameters are obtained from some logging surveys ( 1) propagation velocity, (2) Attenuation, (3) Frequency These physical quantities refer to the main wavesets observed, notably the refracted P and S modes (only in fast formations, recorded with single-pole axially symmetric tool) as well as Stoneley waves. The measurements thus obtained from sonic logs can then be used to derive other parameters such as rock mechamcal properties (e.g. Poisson coefficient, bulk and shear moduh, etc ) and porosity, as well as indications of permeability, degree of fracturing and lithology . The acoustic parameter conventionally acquired in real time rs the P wave velocity, expressed in terms of transit time L1t (units of µs per foot), which is obtained by picking the refracted P wave arrivals

A. Estimation of velocity and integrated travel time (TTI) Measurement of the travel time between receivers enables a determination of the slowness L1t of a formation, the reciprocal of acoustic wave velocity. The mtegratron of L1t over depth yields the integrated travel time (also known as TI1 Transit Time Integrated), which corresponds to the time taken for a wave to travel over a certain distance (Figure.30). It is generally represented by bars marking out l ms intervals of time, with IO ms between longer bars.

Figure.30: Integrated travel time indicated on sonic log. 35

I) Estimation of slowness ( ∆t or Dt) using standard tools With conventional some tools, the transit time measurement of the P or compressional wave, L1t (µsift), is obtained by subtracting the travel times between a transmitter and 2 receivers usually spaced2 feet apart. This technique theoretically removes the effects of the wellbore, provided the tool is centered in a perfectly cylindrical hole.Detection of the first arrival (generally belonging to the P waveset) rs performed using a nurnrnum energy threshold (bias) (Figure.31).

Figure.31: Detection of arrival using threshold filter In practice, conventional systems are compensated for borehole effects and for the tool-hole configuration, so transmitter-receiver pairs (or system incorporating automatic storage of transmitter receiver transit times) are used to ensure a more reliable measurement of travel time. The compensation procedure involves averaging the transit times over the same depth interval from different receiver pairs.

II) Estimation of slowness ( ∆t or Dt) using transmitter/receiver array tools For the more recent types of full wave recording tools (e.g. Array sonic, EVA, etc.), signal processing techniques are used which are similar to those employed in seismic data processing These techniques make it possible to attribute an interval transit-time (or slowness) to each of the wave propagation modes, i.e. refracted P and S waves, and Stoneley-type mterface waves. 36

The mean slowness of propagation of a wave across a given mterval corresponds to the time delay acquired by the wave over this interval. The delay can be calculated by measuring the different arrival times at each receiver (or from different transmitter positions) located in the depth mterval of interest for a common depth of transmitter (or receiver). As a consequence, the slowness of a particular formation may be estimated by measuring the delay m wave propagation by making use of sorted acoustic waveform data. This can be achieved by gathering data derived either from a common transmitter point or from a common receiver point. In this way, the average of the two delays provides a slowness value which is compensated for borehole effects.


Chapter 3: SEISMIC WELL SURVEYING DATA ACQUISITION The well velocity survey technique A well velocity survey is a type of seismic well operation performed to determine the vertical propagation time of a wave emitted at the surface by a seismic source, and then recorded by a geo• phone. In practice, since the source and the well geophone are not generally situated on the same vertical, the distance separating the verticals which pass through the well geophone and through the source must be taken into account. (Fig. 32). The surface seismic data obtained from seismic reflection survey are set with respect to a referenceWell geophone

Figure.32: Implementation of seismic well velocity survey. Plane (DP datum plane) and the vertical travel time estimated by the well velocity survey set to the same reference plane. In land seismic surveys, the reference plane is generally chosen at the base of the weathered zone.For well velocity shooting, the assumption can be made that the raypath is vertical as far as the reference plane, but is oblique and rectilinear from the reference plane to the well geophone. A borehole seismic survey operation is per• formed using a seismic source, a well geophone, a reference geophone or hydrophone placed near the source and a recording laboratory (Fig. 33). The processing equipment does not require a large number of seismic channels, but must have good recording and precision dynamics as well as a short sampling interval (0.25, 0.5 or l ms). The tool must be small, light and equipped with a good clamping system and a seismic cartridge including either a vertical geophone or a set of three geophones arranged in a triaxialconfiguration. The source (Figure. 27) used must be repetitive, preferable emitting a short signal with a clearly• defined initial pulse and a wide spectral range: an airgun is generally used in offshore operations. Onshore, the following kinds of source can be used: offshore-type sources in a mud pit, low• charge explosives 38

and dropped weight impulsive sources. The use of vibrator sources is widespread despite their being unfavourable for the picking of first arrivals.The reference receiver is either a hydrophone for offshore operations, a geophone or mud pit hydrophone for onshore operations

Figure.33:Implementation Schlumberger)

of seismic

well velocity survey (source configurations).(Courtesy of

Operation of a seismic well survey After setting the zero datum at the rotary table or at ground level. a well velocity survey at a given depth cornorises the following steps: ( 1) Checking the depth of the tool in the well. The depth is chosen in relation lo the position of the velocity and density contrasts obtained on the well logs and according to the quality of the hole. h is important not to position the tool in a zone where caving has occurred. ft is essential to have a measuring point at the starting and finishing depths of the sonic log. The intermediate points are chosen close to the markers. preferably situated beneath them so as 10 avoid interference between the downgoing wave and the upgoing wave reflected off the marker. (2) Clamping the tool and :,, the cable. If the tool moves. the position of the measuring point has to be modified. The cable must be slack to avoid cable waves. Clamping is critical to obtain good signal to noise ratio. 39

(3) Recording of seismic data. Seismic measurements are made up from the recording of several surface shots using ampli• fication factors and filters at different frequencies as to obtain field records wilh a signal to noise ratio optimized at the first arrival, (4) Picking of first arrivals on the well geephonc TG and oo the reference receiver TR, and verifying the con ...istency of the arrival times, (5) Tightening the cable.

Check shot The Checkshot is the very basic type of Borehole seismic survey. In the case of a vertical well it involves positioning the source at a single fixed zero offset position, usually relatively close to the well bore. The Borehole receiver tool is positioned at various stations throughout the well, e.g. every 500-ft, formation tops and sonic log points. At least 3 shots are fired at each station. We are only interested in the first arrival time (time it takes for the signal from the source to arrive at the downhole receiver), this time enables us to obtain time/depth information used for correlation of the Surface Seismic and for the calibration of acoustic type logging tools (figure34).

Figure.34: check shot survey Geophysicists are familiar with the velocity survey's one-way acoustic travel time as a critical component that is necessary to help convert surface seismic's two-way travel time to depth. In the absence of the check shot velocity survey, accurate velocity information can sometimes be extracted from the tried and true sonic log. Relying solely on sonic logs, however, may entail considerable risk involving interval velocity errors (figure.35). What may not be clearly acknowledged are how limited check shot data are -- and how very limited sonic logs travel times are inconsistently aiding the time to depth conversion process. The sonic log excels as a formation boundary and indirect porosity measurement log, but it can only see one-two feet 40

into the formation under good downhole conditions and can be subject to cycle skipping and washedout zones.

Figure.35:check shot survey and velocity relation.

Check shots notes    

It involves the recording of first arrivals along a well that penetrates fairly deep target layers. Objective is estimating the velocity and thickness of subsurface layers. It is performed using receivers that are placed in the borehole at known depths and a source that is placed near the well head. It is similar to a downhole survey but using a deeper well and larger receiver spacing.

Check Shot Surveys Interpretation Interpretation of a check-shot survey data includes the following steps: 1. Picking the first arrivals from each depth level 2. Applying any necessary corrections to these times 3. Calculating the interval velocity between each successive receivers 4. Computing the RMS velocity profile 5. Correction from slant to vertical times may be neglected because depths are large compared to shot offset.  The interval velocity between two successive receivers (Ri, Ri+1) is calculated as:

∆Z: receivers 41

receiver spacing ∆Tvi: difference in vertical time from datum to (Ri, Ri+1)

Borehole seismic data are the most effective correlation bridge available between the well bore and the surface seismic data. Borehole seismic data that include the check shot velocity survey and the VSP can measure large volumes of rock -- and will indicate the presence of velocity anomalies, which may be totally missed by the sonic log. These velocity anomalies must be measured and dealt with accurately when mapping the velocity fields that are so critical to an effective surface-seismic time to drill-depth conversion process (figure.36,37). The RMS velocity to the bottom of the Nth layer is calculated as:

Vi: interval velocity within the ith interval ∆Tvi: vertical time within the ith interval This RMS profile is comparable to the RMS profile found by velocity analysis of surface seismic data.

Figure 36: rms velocity calculated from check shot


A check shot velocity survey measures a much larger cylindrical volume of rock compared to the relative soda straw volume measured by the sonic log. The check shot survey and the more precise vertical seismic profile (VSP) should at least be considered in the logging program of every exploration and key development well being planned to minimize or eliminate the ever-present and costly danger of surface seismic time to depth conversion error (figure.38) 42

Figure.37: check shot raw data and how to convert to interval and rms velocity When the sonic log is used to produce a synthetic seismogram for surface seismic correlation purposes, one hopes that a check shot velocity survey is available from the same well to calibrate the sonic log. Calibration and correction of the sonic log often may be needed because the production of a synthetic 43

seismogram from a sonic log is a hybridization and transform process that can introduce seismic travel time error if cycle skipping, tool sticking, and washed-out zone effects are present in the sonic log. The sonic log is also of very limited use in identifying interval velocity inversions -- or any abrupt rock density and velocity change that are an appreciable distance from the well (Figure40). The check shot velocity survey can be used to produce a corrected sonic log, allowing sonic log pitfalls to be alleviated by enabling a data processing analyst to correlate effectively and more accurately through questionable zones that were traversed by the sonic logging tool downhole. A check-shot-corrected sonic log also makes it easier to determine interval velocities between key formations, since familiar formation boundaries can be readily recognized from the sonic log. If density log information is also available, a more accurate synthetic seismogram log integration usually results.

Figure 38: comparison between VSP and checkshot


Figure.39: Comparison between surface seismic and well data.

Figure.40: Time depth chart calculations methods (calibrated with sonic, not calibrated with sonic, sonic used to calculate time depth).


Chapter 4: Vertical seismic profiling Introduction and history of VSPs Although VSPs are generally considered to be a somewhat specialised discipline, they essentially form simply an extension to the surface seismic reflection method with a different configuration of sources and receivers. In the normal surface seismic method, the sources are generally in-line horizontally along the surface of the earth. In the simplest of the VSP cases, the rig-source VSP in a vertical borehole, they are in-line - or nearly so - vertically above some subsurface feature of interest. The detectors will have been placed in a borehole drilled with the specific intention of investigating this feature. The basic configuration is illustrated in figure 1.1 and the correspondence between the two survey types can be clearly seen. A point to bear in mind is that in the surface seismic method the receiver array will in general experience energy arrivals predominantly from beneath the array, whereas the VSP array arrivals will be predominantly into the ends of the array and this has important consequences in the processing of such surveys. The VSP configuration has considerable advantages over the surface method in that the seismic response of the geological section from surface to the deepest point drilled - and beyond, see section 12 - can be observed as functions of time and depth. Thus the propagation of seismic energy can be continuously monitored and important information concerning the origins of primary and multiple reflections, the nature of signal attenuation, and the presence of discontinuities etc. can be determined. Up until the Second World War, geophone observations in boreholes were made almost exclusively for the measurement of travel times from surface to specified stations in the borehole so that a seismic velocity distribution for that location could be derived. From then until the mid 1950s, some work was performed, mainly by research departments, to study wave propagation and absorption in addition to the regular velocity (check shot) surveys. With the advent of the continuously recorded acoustic velocity log (CVL) at about this time, the emphasis on the use of borehole geophone observations shifted to the calibration of these logs and until about 1970 this remained the primary use for such surveys. During this time and almost unnoticed by the West, geophysicists in the Soviet Union were developing the new technology of vertical seismic profiling, building up a very large body of technical data and literature. It wasn't until the early 1970s that western explorationists began to take notice of this new tool and even with the (now) considerable volume of information available the method was slow to gain favour in the West. It is a matter of historical fact that the USSR opened a gap of about 20 years in the development of this technology which is only now being closed. This is due in part to the easy availability of much faster computing technology to western geophysicists enabling a faster rate of development of the necessary computational tools. A possible explanation for the initial lack of interest in the technique is that the western geophysicists were preoccupied during this period with the development of CVL techniques and the derivation of synthetic seismogram data derived from them. In doing so they overlooked that real seismogram data were easily available by simply extending the standard velocity surveys. Additional factors inevitably played a part, probably the most significant of which being the differences between the two economic systems and the way these affected the real costs of drilling wells and providing the technical services for them. Since the mid to late 1970s, the need for ever more cost-efficient methods of exploration for and development of oil resources, has meant an upsurge in interest in methods that would initially have been considered as interesting theoretical ideas. A case in point is the VSP survey. It was realised early on that the VSP gave the industry the opportunity to record real seismic data that provided a direct 46

comparison between the information gained from the drilling results and the surface seismic data. This leads to a much more accurate assessment of the results of the well with regard to the original seismic interpretation upon which the decision to drill was based. In addition, migration algorithms were being developed along with sophisticated ray-trace modelling routines and these allowed for a more rigorous treatment of VSP data recorded using more "exotic" source and receiver configurations. These techniques were able to exploit the intrinsic properties of the VSP survey (i.e. low noise, and proximity of the receiver to the target horizon) to provide small scale seismic images in the vicinity of the well. It was recognised fairly early in the history of the VSP that there were two inter related properties of the VSP that could be of particular interest to the geophysicist. As the geophone is placed deeper in the borehole its earliest recorded reflection comes from ever deeper reflecting boundaries. It is not, however, only the shallow primary events that are lost; the whole of the long reverberant tail which follows each of the shallow reflections is also lost. In other words the deeper the reflections are recorded within the earth, the less they are obscured by multiple events. Also the nature of the recorded wavefields in the VSP provides a very effective means of removing (deconvolving) the multiple tail associated with each reflector. In general this provides a multiple-free data set which can be used to "calibrate" or aid in re-processing the surface derived data. It is also possible to use data thus processed to predict ahead of the current drilled location of the well, a technique that has saved many wells from the disastrous consequences of high pressure blow outs etc.

Vertical seismic profiles The operation of vertical seismic profiles (VSP) is very similar to a check shot survey (well velocity survey) at the operational level. A VSP is a downhole seismic operation where a seismic signal emitted at surface is recorded by a geophone situated suc• cessively at different depths in the well, with the source kept always on the same vertical as the geophone whatever the depth of the geophone. If the well is drilled vertically, the source has a fixed position close to the wellhead. If the well is deviated, the source has a variable horizontal position so as to maintain the transmitter and receiver on the same vertical. The VSP can be regarded as an acoustic log at seismic frequencies. Its lateral resolution is limited to the diameter of Fresnel's first zone, while the lateral investigation is a function of the source offset in relation to the well-head and the structural geometry of the strata. In the case of a horizontal tabular medium, the lateral investigation is equivalent to the lateral reso• lution for a vertical well (approx. 100 m) (Fig. 40a). For a deviated well, this lateral investigation is equal to the well's deviation (horizontal distance separating the extreme positions of the well geophone) (Fig. 40). A possible way of increasing the lateral inves• tigation consists of offsetting the source in relation to the wellhead and downhole geophone (Fig. 40c). The lateral investigation in this case is equal to appro• ximately half the horizontal offset of the source. The choice of offset depends on the depth of the target. It is limited by the fact that the incident waves must have an angle of incidence of less than 30° with the markers to satisfy the assumption of near-normal incidence for the calculation of the reflection coefficient and to avoid guided and refracted modes. In practice, the offset D must be less than three quarters of the depth of the principal geological target H (D 3/4 H).


Figure. 40 Lateral range of investigation (LI) and lateral resolution (LR) in a vertical seismic profile.

VSP operations The procedure for a VSP operatiot is identical to that carried out in well velocity surveying. However, the depth sampling interval is set at closer and more regular intervals. The maximum spacing between the successive depths depends on the minimum velocity (Vmin) of the formation and the maximum frequency (Fmax) that must be recorded in order to respect the Z sampling theorem (Shannon, 1949) needed to avoid aliasing and ensure high-quality data processing. The maximum sampling L1Zmax (two samples in one wavelenght) is given by the relationship: ∆Zmax = Vmin / 2F max For example, if : Vmin = 1 500 mis, and: Fmax = 150 Hz, then: Zmax=5 m The VSP recording is composed of upgoing and downgoing body waves of the P and/or S type, as well as guided t,nterface modes linked to the well and the well fluid. The guided modes, usually termed tube waves, are dispersive waves of the Stoneley type. The upgoming bod y waves are primary or multiple reflected waves. Only the primary reflected waves intersect the first arrivals. The downgoing body waves comprise waves emitted by the source forming the direct arrivals, and all the multiple events created by seismic markers situated above the well geophone. Figure 41 shows a compressional wave VSP with a complex set of tube waves labelled TWI to TW6. A simple way (although not always practical) of attenuating the tube waves created by surface noisengenerated by the seismic source consists of lowering the column of mud in the well and/or deviating themsource in relation to the wellhead.


Fig. 41 Example of VSP recording. (TW: tube waves). TWl, TW3 and TW6 are downgoing; TW2, TW4 and TWS are upgoing. (Courtesy of Gaz de France and /FP)

VSP principles Identification and origin of primary reflections Primary events are easily identified in a VSP data set by the simple fact that they intersect the time-depth curve. If the primary has been generated by a horizontal reflector, then it should appear as a horizontal event across the VSP display aligned at two-way time. Such an event may lose continuity into the body of the data due to multiple interference and possible worsening signal to noise ratio. This is caused by the longer propagation paths associated with shallower geophone plants. Deconvolution will generally improve the continuity of these events by removing the multiple activity. If the horizon is dipping then, the event will appear with moveout into the body of the data. The identification of the event as a primary and the determination of its lithologic origin is still secure, however, providing it cuts the time depth curve. Figure 42 illustrates VSP upgoing events at two-way time generated by horizontal or near horizontal reflectors at the borehole. it is clear that the upgoing primary events intersect the time-depth curve which 49

is marked on the display, the depth at which the reflection originates is confirmed by the calibrated velocity log to the left of the figure. As displayed the data has not yet been deconvolved and therefore contains multiple activity and additionally the wavelet contains source components. It is unclear therefore as to the exact relationship between the seismic events and the lithological changes. This is alleviated by deconvolution and figure 5.8 shows the same comparison but this time using the deconvolved upgoing data. The resident wavelet of this data is now zero phase, the centre of the wavelet for any event occurring at the exact time of that event. At SEG Normal polarity as displayed, an upgoing compressional arrival appears as a white trough, the centre of which identifies the position of the reflector. Once the phase of the wavelet is known, a precise correlation can be determined as the VSP and calibrated velocity log are tied to the same time measurements. The lithologic significance of any primary event can, therefore, be assessed.

Identification and origin of multiple reflections it was noted that upgoing multiples terminate within the body of the VSP as the geophone moves below the last reflector in the multiple path. The downgoing wavefield contains information with regard to multiple patterns generated above the geophone. Interbed multiples will be added to the downgoing wavefield as the geophone moves below the first primary involved in the interbed generation. The downgoing wavefield, observed at any point, will appear in the upgoing wavefield as the tail of a reflection at the same point. Finally after deconvolution, the data will provide a display from which the reverberants will have been removed. One therefore, has three separate but interconnected means of identifying multiple activity and determining its origin, the three approaches should be used together for a complete analysis of primary-multiple relationships and their lithologic origin. If one examines the model shown in figure 42, shifting the event diagram to two-way time (figure 43), provides one with an indication as to how multiple patterns will appear in the VSP data. Only multiples up to the third order are displayed.

Figure .43: Multiples in VSP 50

One may extend the identification of multiple events away from the VSP to encompass the surface seismic record. The approach is essentially the same, although the choice of comparison trace is slightly different. If the downwave is extremely stable, it is unlikely that any difference would be noticeable between the comparisons of any trace with the surface record. If, on the other hand, there is a variation in the downgoing wavefield with depth, one must ensure that the downwave used is compatible with the data being analysed. To this end, the downwave trace for the level with the same two-way first arrival time as the time of the reflector on the seismic record, should be used. Again the polarity of the downwave first arrival must match that of the reflection event examined; any positive correlation between the tail of the downwave and events beneath the primary then implies residual multiple activity in the surface record. Figure 34, is of a typical display provided by VSP contractors for correlation with surface data. The direct correlations would be achieved using the transposed or corridor displays, the full deconvolved panel would then be used for any detailed interpretation. If the VSP contains considerably more high frequency energy than the surface seismic, then a second version of this display would be produced, with the processing optimised for the data as recorded. This would preserve the information present in the field data and provide the geophysicist with a high resolution data set upon which to base his interpretation. The seismic bandwidth data would then simply form a control data set to guide the initial assessment of the well results. A point to note here, is that the transposed display, although preserving evidence of dip, cannot be used for dip calculations. A practical example of VSP interpretation is presented as a work study with these course notes.

VSP data Acquisition Field Equipment The fundamental requirement of any measurement system, including recording of borehole data, is that changes between measurements are due to a single variable. The equipment and techniques used in recording VSP data are designed with this in mind so that a major consideration is consistency in all aspects of the data acquisition – energy source, receivers and recording equipment. It is also important that the instrumentation is fit for purpose with adequate dynamic range and minimum distortion. Receiver The most common VSP receivers, or tools, have retractable, motor-driven, locking arms. Specific tools differ primarily with regard to how many locking arms they have, where the arms are positioned, how much lateral locking force the arms generate, as well as the length, diameter, and mass of the total receiver package. Let us examine two possible tool-to-formation coupling mechanisms. The design shown in Figure44 (Example of a VSP tool with a motor-driven locking arm mechanism) has a locking arm that we can extend and retract via electrical commands from the surface. Coupling mechanism between the geophone module and the mother tool is designed so that once the module is pressed to the borehole wall, the geophones are decoupled from the mother tool. Other logging tools can then be physically combined with the seismic receiver without adversely affecting the geophone-to-formation coupling. The tool's construction must be capable of protecting all internal components (particularly the electronics) when external pressure can be as high as 20,000 psi (137.9 MPa) and the temperature as high as 200 degrees Celsius. In order to operate in all types of boreholes, the coupling mechanism should 51

be adaptable to arms of different lengths so the tool can lock in well diameters ranging from 10 to 50 cm (about 4 to 20 inches). Slim-hole tools with diameters of 5 cm (2 inches) or less are required if the receiver must pass through production tubing. Slim-hole tools are also used to record data in the bottom portion of ultra-deep wells that have been drilled with small bits. VSP data should be acquired as quickly as possible, so that we can minimize rig standby cost. The locking arm must therefore extend and retract quickly. Most tool designs similar to those in the two previous graphics enable the receiver to lock fully in 30 seconds or less. In order to expedite recording, some VSP engineers do not retract the arm as the tool is raised from level to level. Instead, they simply decrease the locking force and maintain a modest arm-to-formation contact as the tool is raised. Then they quickly relock the tool at the next depth level. Since VSP tools need regular maintenance, it is essential that both service companies and clients insist on tool designs that are quick and easy to maintain. Too often, components have to be replaced by tired field crews, after midnight, in adverse weather and poor light. Neither the paying client nor the service company engineer wants an unnecessary loss of time due to required tool maintenance. Because of the hostile nature of the environment encountered by the downhole detector, the receiver employed for such surveys requires significantly greater design expertise and manufacturing capability than standard surface geophones (Figure.45). The downhole tool has to be able to survive up to - and in some cases beyond - 20000 p.s.i. or 1380 bar (ie equivalent to 6 cars for every of pressure and maximum downhole temperatures of more than 200°C (392°F). It is not possible to deploy a standard geophone spread cable downhole to provide the exact analogy of a surface seismic survey; the geophones must possess a mechanism for anchoring to the borehole wall and this will usually be powered and controlled from the surface. The cable used to deploy any downhole tool must be strong enough to support its own weight plus the weight of the downhole equipment, it must also be able to survive a considerable amount of “over-pull” should equipment become stuck in the hole. The downhole environment also often contains corrosive substances and all tools and cables must be able to resist attack from these corrosive materials. Standard cables used by the majority of logging contractors consist of an outer armoured section with seven conductor “strands” within the body of the cable. “High tech” cables with fibre-optic “conductors” possessing much wider transmission bandwidth are available, but have yet to establish themselves in the industry. This is mainly due to their significantly higher cost and the increased difficulty of operation using these cables but also because of the unavailability of the required high temperature electronics and the difficulties in terminating the cable at the tools.


Figure .44: receiver componenet

Figure .45:The design in (Remotely deployed lightweight VSP geophone package) has a lightweight geophone module that can be extended from, and retracted into, a mother tool. 53

Geophones Velocity-sensitive geophones are the most common transducer elements used to record VSP data. o o

A transducer is a device which converts one form of energy into another. A velocity-sensitive geophone converts the mechanical motion of the earth into electrical voltage.

Transducer Geometry We usually position these geophones in a VSP tool in one of two geometrical arrangements. The geophones may be linearly oriented along the axis of the tool, or they may be arranged in an orthogonal, three-component configuration. In vertical boreholes, an axial alignment of geophones measures only the vertical component of particle motion. If this type of geophone is used in a deviated hole, the geophone elements should be gimbalmounted, which uses gravity to orient them vertically. Although we can record valuable VSP data with vertically oriented geophones, several important applications of vertical seismic profiling require the X, Y, and Z components of particle motion to be measured. for example, we can estimate the reflection and transmission properties of shear waves, the energy mode conversions that occur at impedance boundaries, and determine fracture orientation only by recording subsurface particle motion in three mutually orthogonal directions. To record threecomponent particle motion, the downhole VSP receiver must contain non-vertical geophone elements. Figure46 (Gimbal-mounted geophones) illustrates an XYZ, three-component, gimbal-mounted package ofgeophones.

Figure.46: geophones in three mutually orthogonal directions This particular design ensures that all three geophones remain in an orthogonal XYZ configuration, even if the tool is rotated as much as 90 degrees from vertical. 54

Accelerometers Accelerometers measure the acceleration of the mechanical ground motion rather than the velocity. Accelerometers have a number of advantages. They can be designed to measure signals down to nearly zero frequency (typically geophones measure down to around 5 Hz with a natural frequency of 10-13hz). The accelerometers can also be tilted without changing the response. Thus they do not need gimballed mountings to maintain X, Y and Z components horizontal and vertical. The disadvantage is that they are usually less sensitive than velocity phones, producing less electrical energy for the same mechanical energy. However, mass loaded velocity phones, which have the effect of differentiating the velocity function to measure acceleration, are used in some VSP tools and do not have to be gimballed. The VSI Versatile Seismic Imager The Versatile Seismic Imager (VSI) represents the latest available technology in the acquisition of seismic waves generated by a seismic source. The VSI employs three-axis single sensor seismic hardware and software and advanced telemetry for efficient transmission of the data from the borehole to the surface. It consists of three parts (a power cartridge, a control cartridge, and the measurement sonde) and takes its measurements by means of a three-axis gimbaled accelerometer package in the sonde. Each sensor package delivers high-quality wavefields by using three-axis geophone omnitilt accelerometers, which are acoustically isolated from the main body of the tool and provide a flat response from 3 to 200 Hz. The configuration of the tool (number of sensor packages, sensor spacing, and type of connection (stiff or flexible) varies to provide the maximum versatility of the array. A maximum of 20 shuttles can be used, though only one has been used so far in ODP and IODP.three-axis single-sensor seismic hardware and software and advanced wireline telemetry for efficient data delivery from the borehole to the surface. Each sensor package delivers high-fidelity wavefields through the use of threeaxis geophone accelerometers, which are acoustically isolated from the main body of the tool. The number of sensors, intersensor spacing, connection type (either stiff or flexible), and tool diameter are field configurable to ensure the maximum (Figure.34)

Figure.47: VSI tools. 55

Versatility of the array. Regardless of configuration, the tool is used to collect seismic data by anchoring in the hole at the desired depth using a caliper arm. When anchored, the accelerometer package is pressed firmly against the formation while remaining decoupled acoustically from the body of the shuttle. Air guns deployed from the rig by crane then provide the necessary source pulse, and the resulting acoustic wave is recorded downhole on all three axes. On the JOIDES Resolution, the guns are typically held in one location relative to the borehole while the tool is moved to each of the desired depth stations within the hole. The anchoring, size, and acoustic isolation of the sensors allow for suppression of the tool harmonic noise and removal of tube waves from the borehole-seismic band. Furthermore, digitization close to the sensor package helps reduce signal distortion (Figure.48). Among the benefits of using the VSI tool are the increased operating efficiency (rapid mechanic deployment and reduced time between stations), the short shot-cycle time during remote source surveys, and the real-time quality control and data processing. The VSI tool can be combined with a gamma ray tool for accurate depth control and an inclinometry tool for spatial orientation. For the sake of avoiding excess noise in the data and damage to the tool due to excessive weight in case of high heave, it is standard practice to run the VSI with only a basic gamma ray sensor and telemetry, normally both provided by the EDTC-B. The VSI design focus on data fidelity and quick adaptation to changing survey needs avoids the compromise in data quality that typically results from efficiency limitations. The result is sharper, more accurate images and reduced operating logistics, which are fundamental elements for achieving complex surveys in a cost effective manner and with timely delivery of answer products (Figure.49). The operating efficiency of the VSI tool is enhanced by ■ rapid mechanical deployment ■ Very little time between stations ■ short shot-cycle time during remote source surveys (walkaway, offset vertical seismic profile [VSP]) ■ real-time quality control and data processing. Applications Applications: ■ ■ ■ ■ ■ ■ ■ ■


Integrated processing for inter- pretation of borehole and surface seismic data Images for reservoir definition Images ahead of the bit Three-dimensional (3D) VSPs Pore pressure predictions Planning for well placement Simultaneous surface and bore- hole seismic recording for high- definition images Shear wave processing and analysis

Figure 48. VSI tools field configuration.

Figure.49: compareson between convention seismic imager (CSI) and Versatil seismic imager.


Desirable geophone Amplitude/Phase Behavior In three-component data recording, the horizontal geophones must exhibit an amplitude and phase response identical to that of the vertical geophone. If the geophones record the phase relationships or the frequency content of the horizontal signal components in a way that differs from the way the geophone records the vertical component, then precise three-component data analyses are difficult to perform. If the amplitude or phase response of any one of the three orthogonal geophones differs from that of the other two, then we must determine a numerical operator that corrects the amplitude/phase behavior of the errant geophone, and then apply that operator to all data recorded by the anomalous geophone. After this numerical equalization, we can assume that any amplitude and phase effects observed in the data are caused by geology, and not by instrumentation. In order to minimize frequency and phase differences in three-component receivers, the wall-locking device that couples the geophone tool to the borehole wall must mechanically couple all three orthogonal geophones to the formation in the same way. Thus the locking arm must generate a large, laterally directed locking force for the horizontal geophones to couple properly to the formation. A horizontal force that is too low will create anomalous phase shifts and amplitude distortions in the horizontal component data. If these distortions go unrecognized, we may erroneously attribute them to geological causes. The amplitude responses of the XYZ geophones of the three-component tool shown in Figure.36 (Remotely deployed VSP module) made after the tool was coupled to the formation. Figure. 50 shows Amplitude spectra of vertical and horizontal geophones from remotely deployed VSP module, these response curves show no undesirable mechanical resonances for any of the three receivers up to the test limit of 150 Hz. These results are adequate for almost all VSP work.

Figure.50: Amplitude spectra of vertical and horizontal geophones from remotely deployed VSP module


GENERAL REQUIREMENTS OF VSP RECEIVERS There are several fundamental requirements for a good-quality VSP geophone tool. Locking Force A strong locking force is probably the more important receiver characteristic, one that greatly affects VSP data quality -particularly the quality of data recorded by non-vertical geophones. The lateral locking force, f, created by modern VSP receivers. Figure.40 shows the Principal design features of a VSP geophone that is significantly greater than the locking forces exerted by earlier geophone designs. The weakest acceptable horizontal locking force is generally defined to be the same as the weight of the tool. Most receiver designs now allow for the lateral force to be as great as two -four times the total tool weight (in air) (Figure.51).

Figure.51: Principal design features of a VSP geophone Depth Correlated In order to correlate VSP data with the subsurface geological properties interpreted from wireline logs, we must record VSP traces at the same depths as the log data to which they are being correlated. The repetitive up and down cable motion we use to position a VSP receiver at each sequential recording depth often creates a cumulative depth error as data acquisition proceeds. Consequently, we must be able to determine VSP receiver depths relative to logging depths without depending totally on wireline odometer readings. For this reason, we should deploy VSP receivers in combination with a gamma-ray or resistivity tool, Figure.52 shows the Oriented, 3-component VSP data are recorded with a gyro and gamma ray tool mounted on the VSP logging string to confirm geophone depths. 59

Figure. 52: 3-component VSP data are recorded with a gyro and gamma ray tool An isolation subassembly is used to ensure that these added tools do not introduce undesirable resonances into the geophone response. These logging tools provide a log curve which we can depth-correlate with log curves recorded before or after the VSP data acquisition. A gamma-ray tool is usually more desirable than a resistivity tool since we can record a gamma-ray response even in cased boreholes, whereas resistivity tools provide no correlation inside casing. By correlating equivalent log curves (e.g., a gammaray curve recorded in an open hole logging run and one recorded during a VSP data-acquisition run), we can often correlate VSP depths and logging depths to within 1 or 2 feet. When running a depth-correlation logging tool in combination with a VSP receiver, we must be careful to seismically isolate the geophone package from the logging tool so that the added mass and length do not create geophone resonances within the seismic signal band. Some service companies have developed isolation subs for this purpose to effectively attenuate frequencies above 1 or 2 Hz. The geophone module deployment mechanism, Figure 53 shows remotely deployed VSP geophone that serves as an isolation sub for the mother tool of a VSP receiver.


Figure .53: remotely deployed VSP geophone Geophone-to-Formation Coupling Measurement Despite the powerful lateral-locking forces generated by VSP geophone tools today, it is still helpful to make an independent, in-situ measurement of the geophone-to-formation transfer function at each recording depth. This function defines the relative amplitude and phase of each seismic frequency component transmitted from the formation into each VSP geophone element. We can make this coupling measurement by installing a surface-controlled mechanical oscillator in the receiver. After the tool is locked in place, the oscillator shakes the VSP geophone over a range of frequencies to span the seismic recording band. We can also measure the coupling by including in the downhole package a small, remotely activated mass that mechanically impulses the geophones after they are coupled to the formation. An internal mechanical oscillator is used in the geophone module diagrammed. Figure 40shows the oscillator sweep that produced the spectral comparisons in Amplitude spectra of vertical and horizontal geophones from remotely deployed VSP module) is shown immediately above the spectra. We must calibrate any coupling measurement system so that it accurately generates known amplitude and phase inputs to the geophones over the complete range of temperature and tool-inclination angles that might be encountered in VSP boreholes. Three-Point Support The three-point support for a down hole receiver. Figure54 shows Downhole receiver -plan view at right to prevent horizontal rotation of the tool about the fulcrum point established by the contact pad of the locking arm, A. The locking arm is one of the three contacts. The other two contact points (labeled S) are usually some type of machined standoffs. These contacts are positioned approximately 120 degrees in each horizontal direction from the locking arm, and extend a short distance away from the outer barrel of the tool. The force vectors produced at these three points stabilize the tool and prevent rotation about its longitudinal axis. 61

Figure. 54: 3-point clamping Downhole Digitizer and Telemetry System For a standard, seven-conductor wireline, two wires are needed for each analog signal. Thus, we can send only three independent, simultaneous analog geophone signals up hole on conventional wireline systems. One advantage of downhole digitizing and telemetry is that more data can be transmitted up hole by digital multiplexing than by analog signals. Downhole digitizing is required if we use multilevel, three-component VSP receiver systems in conjunction with a seven-conductor wireline. The digitizing/telemetry system can be external to the geophone package ( Figure.55)


Figure.55: down hole instruments Gimbal-mounted Geophones Modern VSP receivers record three-component particle motion in order to analyze the total seismic wavefield as it propagates through the earth. If we record VSP data in a deviated borehole using velocity sensitive geophones, the geophone tool should be equipped with a gimbal-mounted geophone package that responds to gravity. Gimbal-mounted geophones provide an orthogonal XYZ orientation of the internal geophone elements, with one geophone always being vertical, regardless of the tool's angle of repose in the borehole. In general, however, fixed-axis geophones are slightly quieter than gimbalmounted geophones. Figure 56 shows Gimbal-mounted geophones that one design of a gimbal-mounted geophone system. In this particular design, the gimbal package fits in the geophone tool so that the same horizontal geophone remains in the plane in which the locking arms move. The orientation of the internal geophone elements is then always known relative to an obvious external feature of the tool — i.e., the locking arm. This feature makes it convenient to connect the geophone tool to a gyro tool .We then know exactly how the horizontal geophone orientation should be indexed relative to the gyro reading of the azimuth direction.


Figure.56: 3-C geophones package Temperature and Tilt Angle Calibration of Geophones A VSP geophone can be subjected to extreme changes in temperature while recording data. Temperatures can range from 200 degrees Celsius or more at the bottom of a well to 0 degrees Celsius or less at the surface. Some geophones change their resonance behavior over such large temperature ranges. We must be aware of these behavioral changes in order to accurately calculate important geological properties from VSP data. The tilt angles of fixed (not gimbal-mounted) sensors depend on the deviation of the well bore. In vertical holes, the tilt angle is negligible, but in long-reach wells, tilt angles can be as great as 70 degrees. Highfrequency velocity-sensitive geophones are preferred by some VSP users because they are less sensitive to tilt angle than are low-frequency geophones. Oven tests of VSP geophone resonance behavior should therefore be made over wide temperature and tilt ranges. If accelerometers are used, then tilt is not an issue during acquisition because they have a constant response along each axis regardless of the inclination of that axis.


MULTI-LEVEL RECEIVER ARRAYS The continual quest to decrease the amount of time required to record VSP data led to the development of multilevel VSP receiver arrays. Such arrays couple receivers to the formation simultaneously at several different depths. If we require 20 hours to record a VSP with a single-level tool, then, in theory, we should need only four hours to record the same VSP with a five-level array which acquires data at five depth points simultaneously. This time-saving is appealing to oil companies because it decreases the standby costs of the idled drilling rig while the VSP data are recorded. Subsequently, the consistency that multi-level receivers offer for walkaways has proved very beneficial. Also passive monitoring of microseismicity requires multiple receiver locations (Figure.57)

FIGUR.57: multiple receiver locations Design options for multilevel receivers range from an eight-level device with only vertical geophones, to a twenty-level system with three-component accelerometers. We usually prefer to use these tools in cased portions of a well (particularly when deviated), because it is difficult and risky to deploy a long, flexible, multilevel system in an uncased, rugose, highly deviated wellbore. Some multilevel systems lock by magnetic clamping and therefore can only be used in casing or with bowsprings to push the receivers against the side of the open wellbore. If more than three independent signals are to be recorded via standard wireline, the data must be digitized downhole and sent to the surface by telemetry because of the limitations of analog transmission through a seven-conductor system. Otherwise, we must use a special wireline with conductors to handle the number of analog signals recorded (Figure.58).


Figure 2 Figure .58 : Array tool with twenty, three-component receivers compares the length of an array to the height of the Eiffel Tower. This gives a clear indication, not only of the extra-ordinary length of the array, but also of the length of borehole that can be interrogated by a single shot. The array shown has a variable receiver spacing between 2.5m and 20m and three-component accelerometers with 24 bit ADC downhole. Each receiver is independently locked using an electro-mechanically driven arm. The detectors are isolated from the receiver body after locking as described previously in the CSI single receiver tool.

1.Analogue seismic receiver Using analogue transmission of data on a standard wireline cable, one is limited to six live plus one common conductor, this means that six independent geophone channels can be recorded equating to a two-station 3-component geophone. An obvious method of transmitting more data up the same cable is to use downhole analogue to digital conversion with associated digital telemetry. Current technology allows for the provision of a maximum of 32 × 3-component receivers at a 4ms sample rate (Geochain Array Tool) for real-time data transmission. More geophone elements can be accommodated if one allows for a degree of buffering of the data downhole, with transmission to surface during the “dead time” between shots. A limiting factor on transmission rates is the high frequency attenuation of electrical signals in the wireline cable although it can be accommodated to a great extent by applying electrical load matching or “equalisation” in the surface equipment (figure.59).


Figure.59: analogue seismic receiver. Although in theory any recording system The last point is in fact the easiest to accommodate, the simplest solution being to place the geophones in a cylindrical barrel of sufficient thickness to stand expected borehole pressures. This simple solution is the one generally adopted but it brings with it further problems, one of the most obvious being that the performance of the geophone elements is immediately compromised. In isolation, geophone elements easily surpass the performance requirements for a downhole tool; as soon as they are encased in a barrel, however, their response is modified by the physical properties of the housing. For instance large tool housings will possess many mechanical resonances, some of which are coincidentally resident in the middle of the seismic pass-band. Tool operation is very much complicated by the need to couple the sensors to the borehole wall in order to receive the seismic energy in a manner that does not lead to distortion of the wavefield. Coupling is usually accomplished by providing the tool with an arm mechanism that extends from the body of the geophone housing until it contacts the side of the borehole. This forces the body of the tool against the opposite side of the well anchoring the device to the borehole walls. The arm mechanisms are generally hydraulically or electro-mechanically operated, the particular design adopted having a direct bearing on the size of the tool. An alternative locking mechanism employs a magnetic clamping device with the provision of a rotatable permanent magnet in the tool body, the obvious limitation to this method of operation is that the tool can only be deployed in cased sections of hole. Additionally even with a very high magnetic clamping forces, there is a possibility of micro-slippage of the tool as the device has only one contact point with the borehole wall. With each added piece of equipment the mechanical resonances become more troublesome and some ingenious solutions have been adopted to ensure that they do not appreciably affect the recorded data quality.


What then are the factors to be considered in the design of an ideal downhole tool? A. Short, lightweight and rigid

Moves mechanical resonances out of seismic passband

B. Mechanically coupled

Tool may be deployed in open or cased holes

C. 3-component geophones

Allows the recording of the full vector seismic wavefield providingmore accurate wavefield partitioning in processing

D. Gimbal mounted geophones

Allows optimum deployment in deviated boreholes. Alignment ofcomponents to borehole trajectory

E. Ends tapered and narrow diameter

Presents as small an acoustic impedance contrast as possible toborehole borne arrivals (e.g. tube wave)


Increased fidelity of recording seismic energy coupled with rejectionof fluid borne arrivals

High locking force

G. On board coupling tester

Ability to check tool performance in-hole

H. Analogue or digital data transmission

Provides flexible and scaleable deployment options


Allows for ease of maintenance

Modular construction

Some of these considerations are, to a certain extent, mutually incompatible. For example the requirement for rigidity conflicts with the necessity of providing as small a diameter tool as possible, a short-fat tool is inherently more rigid than a long thin tool. Choice of the appropriate geophone sensor type is also of paramount importance as each of the three sensing axes must possess the same performance characteristics. There are specific types of geophone for horizontal and vertical sensing, which differ in the method of suspension of the sensing coil, optimising the suspension for the designated sensing axis.

Receiver choice notes: 3. The main requirement of a downhole seismic receiver, is that it record the motion of the subsurface rock matrix - in response to the passage of a seismic disturbance - with the minimum possible distortion (or alternatively with maximum fidelity). To this end it is necessary for there to be no undue resonances of the mechanical housing of the sensor(s) that would introduce anomalies into the response of the tool over the seismic bandwidth. The simplest way of achieving this in conceptual terms is to accept that any mechanical system will possess resonances and to reduce the effect of those resonances on the recorded data. The ideal way of accomplishing this is to ensure that the resonances that are present will occur at frequencies outside the pass-band of interest (for standard seismic data acquisition this can be taken as between 0 and 200Hz although there are some applications that require a wider bandwidth). To achieve this, it is necessary to reduce as much as possible the mass of the sensor housing by either reducing the materials involved or by using materials of high strength but low density (e.g. titanium). The design should also be intrinsically rigid to further reduce the effects of the resonances. 4. To optimize the transfer function for seismic energy between the rock matrix and the receiver, it is essential that the tool be coupled directly to the formations through which the well has been drilled. This entails the use of a coupling device that allows the tool to move in sympathy with any displacements of the rock matrix. Ideally the design should use a mechanical device to enable the tool to be used in both open and cased hole environments. 68

5. For an accurate definition of the complete seismic wavefield, it is essential to record data using some form of three dimensional sensor, usually 3 orthogonally mounted geophones forming a cartesian co-ordinate system. There are other options available but these either require specific sensing elements or software manipulation to retrieve the seismic wavefield. 6. The use of gimbal mounted geophone sensors is preferred for deviated wells, this allows automatic optimisation of the sensing geometry for the three sensors if the tool is not vertical i.e. the vertical sensing element is always vertical and the horizontal elements are always horizontal. In vertical holes, the gimbal mounting is not necessary and indeed can be detrimental to the treatment of the data. It is desirable therefore to be able to use fixed sensing elements in these instances. For maximum flexibility the gimballed sensors could be lockable, either on the surface or remotely using some downhole mechanism. This is not easy to achieve in practical terms and most contractors will supply either fixed or gimballed sensor cartridges according to the survey parameters. 7. In many wells there can be a significant amount of energy transmitted down the mud column in the form of a tube wave. There are still discussions as to the exact manner in which this energy propagates down the well, but most authorities agree that the disturbance associated with this energy travels in the annulus of the interface between the borehole fluids and walls. If one reduces the cross-section of the tool and applies a taper to its ends, one can minimise the interaction between this energy and the tool. The problem is that the resultant tool parameters are then incompatible with the requirements. 8. High locking forces serve three interrelated purposes. Firstly and most basically, if the locking force is significantly greater than the tool’s weight, the tool will tend to stay in position. Secondly a high locking force will mean that the device is more securely held to the formation, such that as far as the seismic pulse is concerned, it is acoustically indistinguishable from the formation. Thirdly, if securely locked to the borehole walls, the tool will be less susceptible to fluid borne arrivals. 9. It would be useful to check the effectiveness of the lock to the formation prior to recording data, this has great potential benefits for data quality. In practical terms, devices to perform such tests are difficult to calibrate and generally increase the complexity of the tool. Most contractors use a variation on the theme of the “pulse” test. A geophone sensor is excited by an electrical pulse, the subsequent decay of signal from the elements indicating the quality of lock (this can be extended to the use of a swept frequency signal applied to a geophone element and some tools possess additional elements specifically for this purpose). Although an item to be included on a “wish list”, in practical terms the use of such a system is generally superfluous and time consuming. This is particularly true if the tool is fitted with a calibrated locking force sensor, a consistent locking force providing in most cases a better indication of data quality and consistency. 10. It is still a fact that digital electronics components have a lower temperature tolerance than analogue. To be able to run in extremely hot environments, therefore, the receiver tool should possess some means of overcoming temperature limitations. This can be accomplished by using 69

insulating techniques (such as “flasking”) and/or ‘Peltier’ semiconductor heat pumps or more simply by designing the system to work with either digital or analogue electronics. In analogue mode there will inevitably be a price to pay in the volume of data recorded per shot due to the limitation of two three component sensors on seven conductor wireline cable. 11. It is essential for the tools to be easy to maintain in the field in order to maximise the survey efficiency and minimise any possible downtime. The easiest way of achieving this is to design the tool to be as modular as possible. Any failures would then be rectified using spare modules rather than attempting a physical repair of a defective unit under field conditions. 12. The following figures illustrate a couple of the possible solutions that are currently available. Figure 60 illustrates the concept of Baker Atlas’ SST 500 downhole receiver array; this is a fully digital system capable of deploying up to 12 four component (three geophones plus hydrophone) satellite receivers. Figure 61shows a photograph of some elements of the SST array. Figure 62is a photograph of the BSR-2 analogue tool from Baker Atlas. This is capable of deployment in vertical or deviated holes and can be supplied in variants capable of running continuously at 200°C and 20000 p.s.i. (1380 bar).


Figure 60: SST500 system schematic (baker)


W inch unit

Figure. 61: SST 500 Satellites

Figure.62: BSR-2 Downhole seismic receiver


Recording Equipment After the downhole receiver the most critical part of the VSP acquisition system is undoubtedly the recording equipment itself. Unlike the downhole receiver, however, the aspect of performance that is most important is not the physical capability of the system (current electronics have capabilities in excess of what is required for high fidelity recording of the seismic data) but more the quality control facilities built into associated computer software. Audio CD technology for example requires a sample rate of just over 44kHz at a rough approximation this generally equates to a data transfer rate of approximately 1.4Mbaud (1.4 million bits per second), the maximum data transfer rate available from current downhole systems is 512 kbaud. Continuing the comparison, audio technology requires a bandwidth between 0 and 20kHz, seismic signals occupy approximately 0 to 200Hz, it is clear, therefore, that the electronics to enable adequate recording of seismic data from downhole surveys are readily available at the surface! The limiting factor for seismic recording thereby reduces to what the contractor can achieve when assessing the quality of the signals received by the system. Borehole seismic recording systems should therefore be capable of at least the following functions:     

Display (in real time) of all data recorded Ability to stack common depth data to help decide how many shots to take for each level Provision of adequate analysis of data to allow accurate assessment of any problems during the survey Provision of accurate images and hard copy of all data Provision of velocity-depth relationship at the well

These options will provide information for the acquisition engineer to make a valid assessment of the data quality for an offshore survey or for onshore surveys using impulsive sources. It only allows, however, the assessment of the data to be based on the signal quality of the direct propagating downgoing wavefield. In the majority of instances this may be sufficient although it does not allow for an easy assessment of the data contained in the upgoing wavefield. An indication of the arrival quality for this can be obtained if the data are plotted as a VSP “sectional” plot i.e. the traces displayed adjacent to each other in a manner similar to surface seismic trace displays. To further enhance the quality control of the survey, the system software should be capable of processing the data such that at least a first approximation of the upgoing wavefield can be generated. The use of vibrators as a source for onshore data acquisition requires the additional ability to assess the signal after correlation with the pilot sweep. The capabilities of the recording system must therefore be increased over the basic requirements noted above by at least the following: Provision of real-time full precision correlation for Vibrator source data Provision of seismic plotting capabilities Provision of in-field processed results for quick evaluation of survey data In many ways the QC processing performed in the field is essential for the true assessment of data quality - particularly with regard to the upgoing wavefield. It has additional benefits for the oil company in that fast preliminary results will be available within an extremely short time frame; this allows decisions to be made at the well site based on the results of the VSP.


Each VSP contractor possesses some variation on this theme of in-field processing. As this document is prepared by Baker Atlas, examples of that contractor’s in field VSProwess© QC capabilities are shown in figures 63 to 69. The VSProwess system hardware consists of a mixture of off-the-shelf items coupled to a proprietary acquisition controller and associated software. The recording system itself - i.e. the computer and media support - is based around two standard Intel processor based PC computers. These run standard multi-tasking operating systems and are networked together with all disk and peripheral devices shared between the two machines. One of the computers is dedicated to the task of data acquisition with the other used for any data processing although the roles of each are interchangeable. The computers are interfaced to an acquisition controller unit which either acts as a digital receiving station for downhole digital array tools, or as surface located analogue to digital converters for analogue downhole systems. The acquisition controller acts as an interface between the system control software and the geophone surface control panel, this enables complete control of all aspects of the survey acquisition and geophone deployment from a single device (the acquisition PC). The system illustrates what can be achieved with modern equipment and by taking advantage of proven existing technology. Furthermore with the adoption of standard PC technology, there is an almost guaranteed upgrade path into the future should the need arise.

Figure 63: Display of record from 6 element four component downhole receiver


Figure 64: Display of vertical component geophone traces from 6 receiver array

Figure 65: Time-depth, velocity and first arrival amplitude plots 75

Figure.66: Display of raw data for vertical, horizontal X and horizontal Y channels

Figure .67: Display of data in FK domain


Figure .68: Display of raw upwave without enhancement

Figure 69: Display of VSP data inverted to velocity


Why must there be these facilities? The engineer must be able to control all aspects of data quality, he must be able to see any noise on a signal, recognise instrument-related problems (for example DC offset) and be able to use tools that can indicate possible corrective measures. For example if the overall amplitude of a geophone signal is falling and the character of the associated wavelet is changing, there may well be a problem with the source output. The engineer should then have the capability of being able to examine the source signature and to either alter the source control (e.g. re-synchronise an array) or to have enough information available to decide to change the source. If a problem can be identified during the survey there is a chance of doing something about it whereas if the problem is not discovered until after the survey it will be too late. If a survey is being recorded with the express intention of examining a specific region in the well, it is quite possible for the engineer to take the data from the area of interest, apply processing, separate wavefields and examine the quality of the extracted upgoing energy. All this can be accomplished whilst recording the data for the next few levels; any decisions that are made concerning data quality can then be acted upon prior to the conclusion of the survey. Such actions can range from re-shooting a single level to the complete re-run of the survey with, for example, different source parameters. Interactive assessment of data in this manner allows the optimum use of the rig downtime associated with the survey. This approach also goes some way to being able to guarantee a specific level of data quality and, at the very least, provides the contractor’s clients with a degree of confidence in the results that they may not have possessed when commencing the survey.

Sources Due to the nature of VSP operations, source requirements are generally different from those encountered with surface seismic work. Notwithstanding this, any seismic source can be used to record a VSP survey. Figure 61 lists some of the sources that have been used for VSP surveys. It should be obvious that some sources are specific to either marine or onshore operations although there are some that can be used for either. Dynamite, although frowned upon these days due to its destructive nature, can be used in both environments although will almost always be a “last resort”. Recent years have also seen the introduction of several designs of marine vibrator. In theory such a device would probably provide the best possible source for marine VSPs, it being possible to tailor the output to provide any required energy spectrum in the same manner as for land vibrators. These sources, however, have problems of energy output and reliability, are cumbersome and expensive to deploy and thus far except for some experimental wellshoots, have not been generally available. An alternative shooting method uses a source placed downhole and records the VSP response either with a surface spread of detectors (reverse or inverse VSP), detectors in an adjacent well (cross-hole VSP) or with detectors in the same hole (co-well surveys). These surveys can have advantages but suffer from the need to provide a nondestructive downhole source - or alternatively disposable boreholes! 78

Figure 70: VSP sources

The requirements of an ideal source can be summarised as in figure 72. Most of the sources in use in the marine environment can satisfy the majority of the requirements listed in this figure, but some will require a modification to their mode of deployment to obtain the best results. A brief discussion of this list is probably in order. The consequences of the first point are obvious; if the source lacks energy then seismic impulses will be attenuated to such an extent that reflections from the subsurface will disappear into noise. The second point is related to the bandwidth of the seismic signal. Signal theory indicates that an impulse of zero time duration contains equal contributions from all frequencies, i.e. it possesses a “white” spectrum. It follows, therefore that the closer a signal gets to that of an impulse, the “whiter” its spectrum and by implication the narrower the wavelet associated with the energy pulse. The width of the pulse defines the minimum separation in time that two reflections can be in order for them to be resolved in the seismic image. The narrower the signal wavelet the greater the resolution and it follows, therefore, that the ideal source should be impulsive.

Figure 71:Ideal source requirements

The third requirement comes from the fact that single or multi-channel processes can be applied to the data, i.e. several traces can contribute to the result for the trace being processed. It is obvious that changes in the data from trace to trace caused by variability in the earth’s response will need to be retained. It is not at all easy, however, to design an algorithm that will preserve these changes and reject changes brought about by other means. Specifically this means that changes in character caused by variations in source output will be detrimental to the overall quality of the processed data image and should be avoided if possible. As was shown in chapter 4, with marine wells (or indeed any wells where there can be an accurate measure of the source signature) a signature deconvolution procedure can be applied to data to remove source variations. In many cases however, particularly onshore, it is not possible to provide a consistent recording of the signature. In recent years there has been a commendable shift in attitude toward safety and environmental aspects of operations within the oil industry. Safety has always figured highly in the seismic industry, possibly prompted by the fact that the earliest seismic sources were explosives! It has long been a requirement of the industry, therefore, that the sources employed must be as safe as possible and those that are intrinsically dangerous should be used in a safe manner. In some circumstances this can lead to particular sources being excluded from specific operations if the degree of risk is considered too high for them to be employed. Most VSP surveys are small-scale operations when compared to their surface seismic brethren. The need to be able to easily deploy the source against the background of restricted facilities and space, has led to the design of small compact airgun arrays. The need to access remote locations, possibly in jungle or swamp environments requiring that the source dimensions are as small as possible for a given energy output. This limitation on size severely restricts the maximum power output from VSP sources; were it not for the fact that the detector is positioned in a quiet environment close to the reflectors, this would probably result in a restriction in the applicability of VSP operations. The final two points of fig 61 are linked, a source that cannot be repaired or serviced easily will not be cost effective. A source that is expensive to operate will not provide sufficient benefits to outweigh its cost of deployment for VSP surveys as the volume of data acquired for each operation is generally small and provides specific information for a given survey configuration 79

Offshore sources

As the majority of offshore VSP surveys will be performed using some kind of airgun source, it is worth considering in

some detail the various factors influencing the performance of these devices. There are three main types of airgun in common use and these can be typified by the “conventional” system (as manufactured by Bolt technologies), the Sleeve Airgun and variations on these themes (for example the G and GI guns manufactured by Sodera use a similar mechanism to the sleeve gun but have additional deployment options). The basic method of operation is identical for all these devices in that a volume of high pressure compressed gas is rapidly vented to the water volume surrounding the gun, the method by which this is accomplished marking the difference between the two main types. Figures 72 and 73 illustrate the operation of the Bolt (“conventional”) and Sleeve airguns, the bolt gun is used here to provide a generic description of their method of operation. Referring to figure 72, high pressure air is fed into the gun via the connection adjacent to the solenoid valve housing, this builds up the pressure in chamber A which is connected via the central passage in the shuttle to the firing chamber B. Once charged the pressures of the gas in the top and bottom halves of the gun are equal and the gun is kept sealed by the pressure applied to the top of the piston (the surface area of the top of the piston in chamber A is greater than that of the bottom of the piston in the firing chamber B). The gun is fired by venting some of the air in the top chamber to the underside of the top of the piston via a solenoid valve, this reduces the pressure in the top chamber and increases the effective surface area of the bottom sides of the piston. The resultant pressure in the lower chamber now exceeds that in the top, hence the force experienced by the lower surfaces of the piston exceeds that experienced by the top and the shuttle is pushed upwards. Once the piston is displaced, the apparent pressure difference between the two chambers increases and the motion of the piston becomes self-perpetuating - the shuttle moving quickly upwards venting the stored gas in the firing chamber. The gas vents to the surroundings via four diametrically opposed ports in the body of the gun forming an expanding bubble of gas in the water in which the gun is placed.

Figure 72: operation of the conventional airgun


Figure 73: Operation of the sleeve airgun After firing the solenoid valve is reset, the pressure in the top chamber is replenished by the gas supply, the piston is forced downwards and eventually the gun re-seals. The speed with which the firing action is effected means that the gas bubble still surrounds the gun when the piston re-seals, avoiding water ingress into the firing chamber, indeed there is a constant flow of compressed gas into the gun throughout the firing sequence. The sleeve gun differs in essentially only one regard. In this device the enclosed shuttle and pistons are replaced by an external sleeve that slides up over the body of the tool to expose the exhaust port which in this case is a single 360° circumferential opening in the gun body. Figure 65 illustrates the typical pressure response of the output from an airgun as a function of time. Perhaps the most striking feature of the response is the oscillatory nature of the signal - this is obviously moving away from the preferred impulsive signature. The oscillations are caused by the bubble of gas that is produced when the device is fired and the mechanism is easy to explain. As the gun is fired and the stored gas begins to vent from the ports the pressure outside the gun begins to rise until the first pressure maximum is reached. This occurs after approximately a millisecond or so, the period being referred to as the rise time. This maximum pressure is only maintained for a very short period after which the rate of venting of the gas begins to fall; during this period the gas bubble is expanding. As the bubble expands its pressure falls until the external pressure associated with the hydrostatic head of the surrounding water Equals or exceeds the pressure within the bubble. The bubble continues to expand due to the inertia associated with the water displaced by the expanding gas, the hydrostatic pressure outside the bubble now working to slow its expansion. At this time there is no appreciable feeding of the bubble from the gun and the inertia of the water is eventually overcome. The bubble is now at its maximum volume and the pressure within at a minimum, thereafter the external hydrostatic pressure causes the bubble to start collapsing. The process now reverses; the contents of the bubble are forced inwards the inertial effects of the water now compress the gas which because of its compliance, reduces to a smaller volume and higher pressure than the equilibrium values. This continues until the build up of pressure inside the 81

bubble overcomes the inertia of the water, at this point the bubble has reached its minimum volume (and its second maximum pressure) after which the process repeats.

Figure 74: Airgun pressure signature The bubble, therefore, forms a resonant system caused by the compliance of the gas and the reaction of the water mass with energy being exchanged between compressed gas and displaced water. This is an important point and has implications for output pulse shaping. What causes the bubble oscillations to decay? As with any resonant system, energy is lost to anelastic effects (e.g. friction - dissipated as heat) and to radiation of energy - in this case acoustic. These cause a damping effect which after a time (generally around 500ms) reduce the bubble activity to near-zero (in addition the gas bubble will tend to rise and will eventually break the surface of the water). It has been estimated that in general only 7-15% of the stored potential energy in the compressed gas is radiated to the far field as acoustic energy. The part of the waveform between the time when the gas is first vented to the water and the second zero crossing is referred to as the initial pulse. The first pressure minimum is seen on the waveform as a pronounced “peak”, the amplitude of this event is augmented by interference from the surface reflection and has a significant effect on the far field transmitted signal. The factors that determine the rate at which the gas is vented into the surrounding water and hence the source signature are: Operating pressure Chamber volume Port area Gun depth Radiation resistance It is instructive to examine the effects of these factors. If one understands the mechanisms involved in the operation of these devices, it is far easier to design a source configuration that will provide the optimum input to the earth for a specific subsurface target.Modelling software can be used to simulate the responses of different gun arrays to help in the choice of source


Operating pressure The part of the waveform that is of most interest to the seismic data processor is the initial pulse. Ideally this will be of short duration and contain all of the available energy input to the earth -- the majority of effort expended on the design of individual airguns is directed toward the realisation of this ideal. How then is the waveform affected by the operating pressure of the gun? Figure 8.21 illustrates the effect of increasing the pressure within the gun. Not surprisingly, it is clear that the peak output of the first impulse seen by the near field monitor is very nearly directly proportional to the firing pressure used. Interestingly increasing the gun pressure correspondingly lengthens the bubble period. It is intuitively obvious that this should be the case as the water displaced by the higher energy stored in the bubble will be accelerated to greater velocities it therefore taking longer to be overcome by the ambient hydrostatic pressure. A further point to note is that the ratio of the amplitudes of the initial peak and the bubble oscillation appear to decrease with increasing pressure. This is again an intuitive effect in that the bubble will be expanding and contracting for longer periods and may therefore lose a greater percentage of its energy (due to frictional losses etc.) than the less energetic bubbles from lower pressures. It is obvious from these figures that the higher the gun pressure the more closely the signature of the airgun comes to resemble the ideal impulsive input. It is also obvious that there is a considerable way to go before the output can be considered as satisfying the requirements of figure 73. There are also some practical considerations to apply. For example the design of airguns is such that they will only survive a given maximum operating pressure. If one repeatedly exceeds the manufacturer’s stated limits then the device will eventually fail either through ruptured seals or through a catastrophic failure of the gun body - something that would certainly undermine the safety of using the source. In the diagrams in figures 75 and 76, the first pressure maximum is shown as a downward displacement. Although this first event corresponds to an increase in pressure (and is labelled as such on the axes) it has been a matter of historical preference that VSP first arrivals be displayed as downbreaks by the majority of VSP contractors. It is interesting also that in accordance with the SEG polarity convention, a display of a pressure sensor in this manner (hydrophones are used for these illustrations) corresponds to SEG Normal polarity (a pressure increase giving rise to a negative voltage output by the sensor).


Figure 75: pressure

Signature vs. chamber

Figure76: Signature vs. chamber volume

Chamber volume It has often been stated that larger chamber volumes provide greater energy and in the past it has been quoted that the peak pressure output is proportional to the cube root of the chamber volume. Whereas the initial statement may indeed be true in that there is a greater amount of energy stored in a larger volume of gas at the same pressure, it is quite easy to show by experiment that the latter is not.That the peak pressure increases with chamber volume can be seen in figure 67, if one measures the amplitudes in this figure, however, it is obvious that the cube root relationship does not hold. The explanation for this is really quite easy to see; if the energy associated with the gas was released instantaneously, there would indeed be a strong relation between volume and peak pressure. When the gun is fired, however, the gas is not released as quickly as one would possibly expect as it is vented via the ports of the gun which by their nature have a limited area and in turn restrict the maximum rate at which the gas can be discharged. The rate of discharge is what determines the size of the maximum pressure peak associated with a particular gun. What can be seen on the oscillograms in figure 67 is that increasing the chamber volume increases the bubble period, this means that the extra energy associated with the additional volume of compressed gas is being used by the system to “feed” the bubble. That there is more energy is undisputed, but this energy is distributed over a longer time frame and dissipated more by frictional effects than by radiation of acoustic energy. This “smearing” of the energy over a longer time period means that guns with larger chamber volumes tend to exhibit a greate. Port Area This is possibly the most important aspect of gun operation, the port area defines how much gas can pass from the interior of the gun to the surrounding volume of water in a given time. If one restricts the size of the port it is intuitively obvious that the rate at which the gas can escape will be reduced; with a large port area, the rate will be increased. Hence the first statement that can be made is that the larger the port area, the greater the amount of energy that can be expended in a given time. It follows therefore that if the rate at which the energy is released increases, then there will be a greater high frequency content to the energy pulse. The combination of these two effects tend to shape the pressure pulse such that it becomes narrower (HF) and higher amplitude (energy). As more gas is released in the earlier part of the signature, the bubble will tend to expand further due to the inertial effects of the higher energy water displacement, frictional losses will therefore increase within the bubble. As less gas is available to “feed” the bubble, this will tend to reduce the relative amplitude of the oscillatory contribution to the signature and increase the period of oscillation. This effect, however, is not the only one working on the bubble. The lowered rate of release for smaller ports means that there is more gas available to feed the bubble, this tends to mean that the vented gas will tend to expand for longer. If the rate of injection of the gas exactly balances the rate at which the pressure reduces as the inertial effects are overcome, the bubble will reach equilibrium pressure prior to collapse and the oscillatory tail of the signature will be removed. What then are the consequences of these effects? Firstly feeding the bubble has more effect on bubble period than the increase in the inertia of the moving water, overall then one sees a reduction in bubble activity for small ports with an associated lowering of peak energy and output bandwidth. Very large port areas provide a high peak energy with moderate contributions from the bubble and wide bandwidth. For intermediate port sizes, peak energy and bandwidth will exhibit values between the extremes. 84

A great number of computer models have been constructed to describe the operation of an airgun. In most cases these have been adequately tested by reference to recorded gun outputs to provide an accurate prediction of gun and array performance without the necessity to measure the proposed configuration under field conditions. It is convenient here to use one of these models to illustrate the effects of port area on gun output, this example (figure 77) is taken from an article published in Geophysics by Dragoset (1984).

Figure 77 Signature vs. port area

It is clear from the foregoing discussion and the data displayed in figure 8.23, that in order to provide the maximum peak pressure output from the gun coupled with the widest bandwidth, the port area should be a large as possible. Indeed the greatest single limiting factor controlling output from the Bolt-type airguns is that the ports are in fact quite small (this can have advantages, however, when operating in marshy environments as it restricts the ingress of contaminants into the gun mechanism). Such observations as these led to the development of the Sleeve Airgun. As noted previously the basic operation of this device is the same as for the Bolt, but the design effectively turns the gun “inside out”. Instead of an internally housed piston and shuttle arrangement, the sleeve gun has an external sleeve (hence the name!) that slides up exposing a large circumferential port. This is much larger in area than the Bolt ports and as such is associated with a commensurate increase in performance with regard to bandwidth and peak pressure output. Gun Depth The depth of the gun determines the ambient hydrostatic pressure under which the gun is going to operate. This has a profound effect on the performance of the gun and its output waveform. The general effects can be seen in figure 78 and summarised as follows the initial pulse increases slightly in amplitude with depth As depth increases the bubble period shortens The initial pulse broadens slightly with depthmDeeper guns experience a longer delay between the first pressure maximum and the “ghost” reflection from surface 85

Figure 78 Signature vs. gun depth Taking the last point first, it is clear that the energy output from an airgun source is not confined to specific directions. Indeed a single airgun can be considered as a point source with energy output distributed over a spherically expanding surface. This means that energy will be travelling in all directions, the important one here being upwards toward the sea surface. At surface, there is a large acoustic impedance contrast, the value associated with the air above the water being much smaller than that of water, the reflection coefficient associated with a change in acoustic impedance is:

Going from water (ρ1v1 )to air (ρ2v2) means that the expression above tends toward “-1”, hence almost all energy reaching the surface will be reflected back downwards with a 180° phase shift (i.e. reverse phase). This produces a dipole effect and inevitably leads to interference between the main source output and the secondary virtual (“ghost”) source. The consequence of this is that the interference leads to notches in the source spectrum, these “ghost notches” can be large and effectively define the usable bandwidth of the source. A complication of this phenomenon for VSP processing concerns the adoption of signature deconvolution procedures using near-field measurements of the source output. It is readily seen that for a near field monitor positioned (say) 1m from the airgun, the ghost energy will have travelled from gun to surface and back to the source monitor; directly propagating energy to the monitor will, however, have travelled only the 1m gun to monitor separation. As the energy is distributed over a spherically expanding surface, the ghost will have experienced a relatively high reduction in amplitude when compared to the direct energy and the effect of the ghost reflection will be reduced. In the far field, however, the propagation paths are of similar length, the amplitudes of the ghost and direct wavefields being therefore comparable. The result is that the spectra recorded in the near field will not be affected to the same extent as the far field by the ghost arrivals. In addition if the monitor is positioned above the source, the path length differences are not the same between near and far field recordings and it is intuitively obvious that the cancellation effects will be at different frequencies. It is worth noting that although there is cancellation of selected frequencies caused by the ghost effect, there is also a degree of enhancement of energy at


Onshore Sources Dynamite Dynamite is what one might term the “traditional” seismic source. In early seismic exploration it was the only source that provided sufficient energy for usable data to be recorded on the instrumentation of the day. Environmental and safety concerns mean that the use of dynamite has steadily declined and in general it is only used today when other sources are impractical or there are specific problems that require extremely high energy inputs to the ground. Surface seismic operations still make use of explosive sources in environmentally less sensitive areas, VSP operations, however, seldom do. Although in some ways the ideal source (high energy and impulsive), it generally exhibits too variable a signature on a shot to shot basis - due to variations in source environment - to allow effective use of the multi-channel operators employed in VSP processing. It is also rare these days to find a rig operator that relishes the thought of explosives being detonated alongside the rig. Vibrators Vibrators on land provide what is perhaps the ideal source for VSP acquisition from the standpoint of data quality and flexibility. The features which make the vibrator source so suitable for VSP data are that it is repeatable and that it can be controlled in such a manner as to be able to tailor the seismic input to the earth for each specific well location and environment. For example if it is known that a particular well location is associated with poor penetration at high frequencies, the vibrator sweep can be modified to input more energy at these frequencies. Conversely - depending on the survey objectives - the sweep can be designed to completely ignore this part of the seismic bandwidth and concentrate in optimising the energy within the unaffected pass band. The various methods for controlling vibrator output and the subsequent scope for an almost infinitely variable input to the earth, make the flexibility of the vibrator source one of its most pleasing attributes (Figure.79). One draw-back with the source is that spreading the energy over a range of frequencies distributed over time, means that we move away from the ideal impulsive signature. Indeed to recover a dataset that looks anything like a seismic image one must first cross-correlate the recorded data with a reference signal derived at the vibrator. This reference sweep serves to define the seismic input to the earth and the correlated output looks and behaves like data recorded using an impulsive source (provided a sufficiently wide frequency band has been included in the sweep definition). However, a benefit of correlation is that it rejects random noise and improves the signal to noise ratio (Figure.80). A problem associated with vibrator derived VSP data is that for accurate processing a reliable transit time from source to receiver is required. In concept this is not difficult, in practice, however, because the final shape of the wavelet (bandwidth and phase response) is defined both by the correlation process and earth filtering, there is a degree of uncertainty with regard to the precise values obtainable from the data. That said, it is a relatively simple matter to provide an additional impulsive reference source to control the results from the vibrator survey. An additional advantage to the use of vibrators is their low impact on the environment and their inherently higher safety of operation when compared to explosive or even airgun sources. The units are usually mounted on off-road all-terrain buggy vehicles, there are few locations (assuming the ground conditions support the vehicle) that they cannot reach, they are non-destructive in operation and require no special site preparations to perform satisfactorily. Both P and S wave vibrators are available and this source is one of the (very) few available that allows a controlled generation of shear waves at or near the surface. 87

Figure 79: Buggy and truck mounted vibrator unit

Figure 80: The vibroseis recording system 88

Land Airgun This device is an attempt to make use of the repeatable impulsive nature of the airgun source signature in an onshore environment. By its nature, the airgun must be operated in a marine environment. It is possible to fire such a source in air, however there is little coupling of the source to the earth and the lack of lubrication means that the seals in the gun rapidly deteriorate. The land airgun attempts (quite successfully) to re-create marine deployment conditions by providing the gun with its own portable marine environment. The most commonly used version is the LSS-3 from Bolt technologies. This consists of a cage which supports a water-filled bell housing in which is positioned a small bolt airgun of typically 60 capacity, the complete unit mounted on a truck. When in use, the bell housing is hydraulically lowered onto the ground such that the rear of the truck is jacked up clear of the surface and supported by the bell. The weight of the truck effectively pre-loads the base (pan) of the LSS-3 onto the ground providing the reaction mass required to input energy to the subsurface (Figue.81). On firing the airgun (typically at a pressure of 2000 p.s.i.), the release of the compressed gas into the bell, expands an elastomeric diaphragm stretched across its base, driving the pan downward against the ground. The resultant upward reaction of the main assembly within the cage is damped by the “catch cylinders” - essentially large shock-absorbers - and the unit is gently lowered back into its rest position ready for re-firing. The damping of the system is essential to avoid the device generating secondary seismic impulses. The spent compressed gases pass through a separator and once vented from the system the unit is ready to fire again, cycle time is typically of the order of 6 seconds. The land airgun provides a clean and impulsive source signature without any of the bubble effects that are seen when airguns are deployed in a truly marine environment. Depending on the size of the units a range of energy outputs are available. The largest units easily provide sufficient energy to penetrate to depths of 4500m (15000ft) although these units are rarely - if ever - deployed outside the domestic U.S.A. Throughout the rest of the world the units fielded, particularly in the European theatre, are capable of providing penetration to around 2400-2700m (8-9000 ft). In very favourable conditions penetrations of up to 3700m (12000ft) can be achieved, although the energy at this depth is low and the data recorded with a single shot of dubious quality for VSP processing. It is interesting to note, however, that with the repeatable signature and short cycle time, it is possible to record a great many shots at a depth station for stacking.


Figure 81: Operation of LSS-3 and examples of units deployed on Unimog and MOL chassis Airgun in Pit / Buried Airgun The airgun in pit is perhaps the “traditional” onshore VSP source after dynamite. Although there are many factors involved in its deployment that are less than ideal for VSP data acquisition, it has the overriding advantage that it is easy to use in an efficient manner and provides a generally high energy input to the earth. As with the land airgun, the deployment attempts to re-create the marine environment, this time in the most direct fashion, by placing the gun in a water filled hole in the ground. There are several problems involved with this method The most obvious of these is that water in the pit will tend to leak away over the course of the survey unless some method of “waterproofing” is used. The simplest method employed is to line the pit with a tough impermeable polythene membrane. In some critical well- shoots where other sources for whatever reason were not available, it has been known for the oil company to construct concrete or steel lined pits. It is important that the pit should be constructed in a manner that allows for a good definition of the source environment, particularly in terms of the way in which this is modified during the survey. The energy output by the gun will interact with the pit walls. In the case where the walls are not strengthened i.e. are simply formed from the soil of the hole, the energy will tend to produce a collapse of the pit. In the worst-case scenario (an unlined pit), the material from the collapsed wall will mix with the fluid in the pit creating a low velocity medium between the airgun and the base of the pit. 90

A modification to the seismic transit times of up to 7 or 8ms one-way has been seen in pits where this collapse has been allowed to proceed, it is obvious therefore that the pit conditions have a great influence on the data recorded. A rule of thumb for pit construction is illustrated in figure 82, the dimensions of 3m cube are in fact a compromise in favour of ease of construction. Ideally the gun should be considered as an isolated source and be positioned as far as possible from the walls of the pit to minimise interaction with what is after all a strong acoustic impedance contrast. It is theoretically possible for the walls of the pit to act as secondary sources of predominantly shear wave energy. This effect can be minimised by placing the source as central to the pit as possible such that the contributions from opposite sides are cancelled. If shear energy is required, however, it may be possible in some cases to maximise its input by placing the gun adjacent to one of the walls. If this is attempted, one should be aware that although the airgun is not an explosive source, the peak energies associated with the pressure pulse created are more than enough to damage even concrete walls. Figure. 82: Airgun in pit A variation on the theme of the pit airgun is the buried airgun. This is an attempt to avoid the major problem associated with the traditional method i.e. pit collapse and at the same time improve the energy input to the earth by placing the source beneath (or at least close to) the base of the weathered layer. It is a well known fact of seismic life that due to its un-consolidated nature, the shallowest part of the subsurface will generally form an extremely lossy region with respect to seismic energy. If the source can be positioned beneath this layer, the resultant energy input will be greatly improved. The buried airgun operation therefore places the source at the bottom of a purpose-drilled hole of slightly wider diameter than the gun at depths of up to 30 or more metres. The depth of deployment is basically limited to the available length of airlines etc. Except for the region in which the gun is to be positioned, the hole is cased with plastic retrievable casing (to prevent collapse during the survey) and filled with water


Field Technique Figure 83above illustrates what could be considered the “standard” operational arrangement for a the majority of simple rig source VSP surveys. It can be extended to more complex survey configurations by the simple expedient of an additional source controller unit at a remote source location. In all cases the recording equipment configuration differs little from that shown although each VSP contractor possesses equipment unique to his operation. Generically there are two variants in the surface equipment chain and the selection of the appropriate system is primarily determined by the type (analogue or digital) of downhole tool.

Figure .83: Schematic of field operational set up 92

The method of source deployment for

the majority of rig source VSPs is simply a matter of suspending the source over the side using a rig crane. This is in fact the easiest and possibly the safest method of deployment from stationary structures and is generally applicable to boats used as the source platform for stationary offset sources. If the remote source is required to move as in walkaway surveys, then additional means of dynamically positioning the source may be desirable (for example hydroplanes fitted to a gun array). After setting up the VSP equipment the contractor will perform a complete set of electrical and mechanical instrument tests on both the surface and downhole equipment; only after the equipment has been shown to be working on the surface will any instruments be placed in the well. Once the testing cycle has been completed the tool will be run into the hole. On running in, the VSP engineer will select certain depths where he will stop the tool, activate the locking mechanism and shoot a number of records. These records taken on the way into the hole serve two purposes; firstly they ensure that the equipment is still functioning correctly. This is a test of paramount importance. Although the downhole tool may be working perfectly on the surface, there is always the possibility that the conditions downhole may highlight faults that were not apparent with the tool on the deck of the rig. This factor is a consequence of the harsh operating environments encountered downhole and does not reflect on the general reliability of the contractor's equipment. The second reason for taking records as one runs into the hole is to provide control points for the data recorded later in the survey after the geophone may have been in the well for many hours. Any change in response may be noted and hopefully remedied and any depth problems with the wireline unit will be highlighted before the survey is completed and the tool pulled out of the hole. With some systems an additional control of the depth monitoring process is performed using a passive gamma ray tool coupled to the VSP sonde. The output from this device during station changes is used to tie depths from earlier electric logging runs. The records taken on the way into the hole also provide the engineer with an opportunity to modify certain parameters prior to commencing the survey proper (for example it would be possible to tune the output of a source array to provide the best compromise between energy and bandwidth). Once the tool has reached TD of the well, the survey can begin in earnest. There are many ways of recording a standard VSP, the simplest and most widely adopted method being to shoot at a regular measured depth increment along the hole. In general the increment will be no more than 30 m (100 ft) and is nowadays typically 15 m (50 ft) with smaller increments used for high resolution surveys. The spacing of the stations, along with the velocity of the medium, determines the maximum usable frequency that can be recorded prior to spatial aliasing during processing. This means that for a variable velocity profile, the different velocity regions will exhibit different alias frequencies. One should, however, not place too much emphasis on this as processing methods and routes can be adapted to ensure that aliasing effects are minimal. In general the sensitivity if the data to the aliasing phenomenon can be reduced by the use of non- linear operators (for example the median) although care has to be taken in the design of the appropriate processing route. If one is intending to use predominantly linear operators during processing, however, this approach may lead to slight problems. F-K operators can be reduced in efficiency if one requires them to be applied to data recording variable velocities. A simple (in theory) way of avoiding some of these problems is to record the data at a fixed time increment defined by reference to the velocity profile of the well. If one now views the recorded data, each event will display the same moveout per trace irrespective of the velocity of the rocks at any particular depth. This makes F-K processing simpler as each wavefield will possess its own characteristic moveout and wavefield separation becomes easy. The disadvantage is that the survey becomes more difficult and time consuming to acquire and more prone to errors (for example the time increments have to be derived from somewhere and this is usually from an uncorrected integrated acoustic velocity log). Remember also that it is quite easy to “fool” FK methods by shifting data to align so that a particular wavefield appears “stationary” in the data. The 93

final problem with this method is that the conventional VSP display of depth against time is now visually unappealing and therefore difficult to interpret. Use of interpolation methods with the recorded data to provide traces at the requisite intervals is also possible and can be an effective tool to use when time for processing is short. Use of this technique, although quite common in surface data processing (to add in missing traces) can lead to problems in the precise location of events in the VSP. There is considerable scope for flexibility in the station interval use for a particular VSP survey. Much work has been done regarding wavefield separation techniques, with the result that virtually any station interval can be processed without undue difficulty. For example, when shooting a vertical incidence survey in a deviated well, the simplest method is to shoot on constant measured depth interval. This means that the resultant image will exhibit a variable trace spacing if the data are plotted on offset. The survey can also be shot using depth stations calculated to give a constant offset spacing. Alternatively the constant time increment method can be adopted; each method will process to approximately the same standard, but each will behave in a slightly different fashion. Processing methodology is sufficiently advanced for the general approach to be to use the shooting method that provides the most cost-effective way of acquiring the data for the survey. That the data conforms to the requirements of the survey objectives is still of paramount importance; the point here is that there may be several methods of providing the same dataset. With modern techniques, the only real reason (in general - there are exceptions) to choose one method over another is that of expense. A VSP survey will generally be shot from the deepest station to the shallowest. This procedure is adopted to provide the greatest depth control accuracy due to the wireline cable always being under tension when moving the geophone between stations. This avoids the possibility of recording erroneous data if the tool becomes temporarily hung up whilst running into the hole. At each depth the tool is locked to the formation by activating the locking mechanism. Once this has fully engaged and the tool is supporting its own weight, slack can be applied to the wireline cable - to avoid wireline conveyed energy. In recent times the need for slack has been reduced by the development of tools capable of providing a high locking force to weight ratio (some deployments from certain semi-submersible rigs in poor weather conditions, may still experience heave which the compensation mechanisms cannot fully accommodate, in these cases applying slack is essential). The tool is then allowed to “settle”. This last point is to ensure that any vibrations induced when pulling the tool up the hole have time to damp out before the record is taken. Once the engineer is satisfied with his geophone plant, he will then take several shots at the level in question to ensure good signal to noise performance on stacking; the tool will then be unlocked and pulled to the next station. If more than one source location is being used, data will in general be acquired from each source position before the tool is moved, this removes the necessity of multiple runs into the well, thereby saving time and money. This also means that there will be no variability between geophone plants between surveys, important if one is comparing results from sources placed on opposite sides of the well for example. With remote source configurations, it is desirable that the control and monitoring of all sources be centralised at the recording location, usually the rig. A remote control device, for example Baker Atlas’ RSS unit, is therefore required; this equipment should also act as a synchronising device between guns in an array. Such units generally operate in pairs with a remote unit acting as a slave to one at the rig. All information concerning the remote source, including a near- field monitor signal, is gathered by the slave device and transmitted via a dedicated radio telemetry link to the master unit, where it is passed to the recording equipment for writing to permanent storage media.


The positioning of a source is of prime importance to the processing of the data generated by its operation. In the onshore case this is almost a trivial exercise in that all the required locations can be surveyed in prior to the operation. In the offshore case, although the required positions are known, the instantaneous position of the source at each shot must be monitored and the location of each individual firing position noted for future quality control and use by the processing personnel. Some sort of dynamic positioning equipment is therefore required. There are many systems available to the industry; traditionally such surveys were recorded using the Artemis range-bearing system to record the navigation fixes, this system possessing an accuracy of 3m in 6km (0.05% error). In recent years although providing the accuracy required for a VSP survey, the use of this equipment has declined in favour of the GPS system (for example the Tasman system) which uses the network of positioning satellites in earth orbit. The accuracy of this system is currently similar to that which can be achieved with Artemis. In practical terms, however, Artemis does have a disadvantage when compared to GPS solutions, in particular, it has the limitation of being a “line of sight” system. Any obstacles between the stations on the rig and the source boat will degrade the performance of the system and indeed the need for base stations on both rig and boat can have its drawbacks. GPS on the other hand can be utilised if necessary using a single receiver station at the source, can be extended to larger offsets than line of sight allows and is less sensitive to physical obstructions obscuring the satellite signals (assuming a minimum number of satellites in view)

Field Quality Control Probably one of the most vital factors in the successful recording of any VSP survey is the knowledge and experience of the field engineers. They have to be able to recognise any problems with the data and be able to correct any possible deficiencies in the field. This means that not only do they need to fully understand the equipment they are using, but they also need an appreciation of the geophysics involved. Access to sophisticated in field quality control facilities ensures that geophysical aspects of the data can be adequately assessed. In the early days of VSP surveys, in field QC was performed almost exclusively using hard-copy camera records. The first arrival was examined to ensure that there was sufficient signal to noise performance (to enable accurate transit time picking) but further analysis was limited to a qualitative assessment based on experience alone. The first arrival times were recorded, the time-depth curve plotted to ensure that there were no apparently anomalous velocities but little else of a quantitative nature could be done. Current technology, however, provides the tools to provide a much more rigorous treatment and assessment of the data and allows true VSP processing at the rig location. What then should be the criteria used to determine the overall quality of the data? There are several problems that can be easily identified on location and many of these can be rectified by the judicious adjustment of recording parameters, configurations, or discussions with the rig crew. In the final analysis, however, the only real measure of the quality of the data lies in the processed VSP image. Some common problems (and their remedies) associated with data acquisition are detailed in the following section. To a large extent the impact these problems have on the data quality and usability are discussed in chapters 3 and 4, what follows is intended to provide an insight into the mechanics of assessing their effects in the field.


Casing Arrivals In general terms, when casing is set in a well only the minimum necessary cementing will be performed to keep down costs and rig time. Although this approach can save money, it can have major repercussions with regard to the quality of the data from a VSP survey. If casing is not cemented to the formation, or the rocks have not “filled back” into the annulus surrounding the tubing, any energy arriving at the hole can set the casing resonating. Energy then propagates down the metal of the casing as described in section 3, swamping the true seismic arrivals. The situation can be considerably worsened if there is more than a single string of casing in the hole. In this case, other than anchoring the successive strings together, there is usually no need to provide a full cement bond for the whole of the well. In practice this means that if there is more than one string in the borehole, there is a strong likelihood of recording casing arrivals at some point in the well. Even if the tubing is not excited into “ringing”, if there is no coupling between successive strings, very little of the seismic energy is likely to be transmitted to the downhole tool in such a section of the well. Unfortunately there is very little that can be done in the field to alleviate the problems of casing arrivals. The arrival wavelets of this energy are coherent between successive shots at a level. This is true because for each level there will be a unique depth or set of depths at which the casing is excited, these will be consistent from shot to shot and hence will give rise to consistent arrivals at the geophone. Although consistent for a particular depth station, it is not necessarily the case that they will be consistent between stations hence it is not possible to suppress them using standard wavefield separation techniques (in the way that tube waves can be attenuated). In general casing arrivals possess a high frequency characteristic, this can be exploited to a degree by applying a low pass filter to the data, thereby reducing their overall contribution to the dataset. It must be stated that there is no processing method capable of completely or even adequately removing casing arrivals. In general therefore when casing arrivals are seen in a VSP, the section over which they occur is usually of little use. What then of the field engineer? In general if casing arrivals are present this will be seen as a warning that the limit of usable data has probably been reached. The engineer will therefore advise the client representative that there is little point in continuing with the survey. He will, however, have satisfied himself that the arrivals are not an isolated problem caused by a short section of un-cemented tubing. In many instances, casing arrivals need only be evident over a short section of the well where local conditions have dictated that the cement bond has been less than 100% effective. Once the geophone tool has left this region and the bonding of the casing has improved, the metal-borne arrivals will be damped out by the material surrounding the casing and the VSP will again yield valid results. Tube Waves Tube waves consist of energy travelling along the well-bore within the borehole fluids and it is generally accepted that the energy propagates along the interface between the borehole fluids and the borehole walls. Unlike a seismic pulse, where the propagating energy is distributed over a spherically expanding wave-front, the tube wave energy as its name implies is restricted to the confines of the borehole. In general, therefore, the only attenuation experienced by the tube wave is that associated with frictional losses in the borehole fluids, as a consequence these arrivals are extremely persistent when compared with “true” seismic arrivals. How are tube waves generated? There are a variety of points in the borehole where a tube wave can be produced, the “traditional” source of these arrivals is from horizontally travelling energy from the source interacting with the well- bore at or near the surface. This “excites” the borehole fluid column in a similar manner to that seen in the air column of an organ pipe. Additionally, however, any discontinuities in borehole diameter or conditions (for example the end of a casing string or a significant 96

change in lithology), can give rise to secondary sources of tube wave activity. In these cases the change in the borehole acts so as to refract energy from the seismic wavefront into the borehole. In open hole sections through fractured zones, the fluids in the fractures may be in communication with the borehole fluids. Seismic energy incident at the fractured zones will instantaneously “squeeze” the fractures, generating an effective motion of the fracture fluids into the borehole fluids. This means that there will be an exchange of energy from the seismic pulse to the borehole fluids and the subsequent generation of tube waves. Such events, however, can be used to assess the presence and strength of the fractures - not every aspect of tube wave activity is negative (see figure 3.4). The effects of tube waves can be alleviated to a degree by placing some obstruction to their propagation in the borehole (there are a number of projects underway investigating the possibilities), or an improvement may be achieved by changing the survey configuration to modify the energy propagation paths. In many cases slightly moving the source location can significantly reduce the amount of tube wave generated. On land it may be possible to further reduce the amount of tube wave by placing a physical barrier to horizontally travelling energy, for example digging a trench between the source location and the wellhead. This works because the energy most likely to induce tube waves during onshore surveys is ground-roll. Another method that, not surprisingly, has had a limited applicability involves lowering the mud column so as to remove the coupling between the well fluids and the ground roll energy. This method has worked well when attempted, but is expensive in time and materials requiring as it does, that the mud weight be increased to maintain well equilibrium. In offshore wells, the interaction between the seismic energy and some part of the seabed drilling equipment often generates tube waves. If this is the case it is unlikely that any reduction in the intensity of the arrivals can be effected. If the engineer has not been able to reduce the level of the tube wave energy by applying one of the possible remedies, then his function becomes to provide an assessment as to whether the arrivals will preclude the production of a usable upwave dataset. In most cases, providing that the arrivals are consistent, the energy will be removable during processing, indeed the latest generation of field processing software from some contractors (e.g. the Baker Atlas VSProwess system), can easily provide this process at the well site. If the arrivals cannot be removed at source, then the engineer must ensure that the survey parameters are kept as constant as possible to ensure that the character of the data remains consistent. In doing so he will greatly enhance the effectiveness of software based removal strategies. Random Noise This phrase covers a whole range of phenomena, all of which exhibit a lack of periodicity or coherence between successive traces. By the fact of being randomly distributed throughout the data, the general level of this noise can be reduced by the simple technique of stacking successive shots at the same geophone level. If the noise has a predominance of high frequencies, the data may be further improved by applying spectral filtering. Although random noise can be attenuated, it is usually almost impossible to eradicate; it is after all, random in nature and provides no clues to enable the engineer to determine from where it originates. The only approach available to the field engineer is to systematically shut down all possible sources of noise at the rig site. This will eventually lead to a reduction in the noise levels when the offending process has been terminated; it may be the case, however, that the offending arrivals have no relationship to the rig-site machinery. For example, if the drilled formations are soft it may be possible that some of the noise is a function of the formation deforming after the tool has locked. This “give” will reach a limit after a period of time, hence the effects may be minimised by allowing a longer “settling time” for the tool at each station before taking the first shot. It may be the case that the cycle time between shots has to be increased for a similar reason. 97

Some boreholes are affected by micro-seismicity of the rocks, either due to natural seismic activity in regions of high tectonic activity, or the release of stress from the environs of the borehole walls. This latter phenomenon can either be induced by the drilling operation itself, or by naturally stored energy finding a channel for release via the well. Whatever the reason, the effects cannot be predicted and hence cannot be prevented, indeed there are techniques available that make use of such arrivals to monitor stress releases in a reservoir. Another possible cause of this noise is the presence of gas. Even with the most diligent attention to detail in the sealing of reservoir formations, if gas is present it will “seep” into the borehole fluids and the bubbles thus formed will behave as small acoustic sources each radiating stored energy. In the final analysis, an engineer faced with high levels of random noise, must ensure that sufficient shots are taken at each level to provide a realistic reduction of the noise by stacking. As mentioned in chapter 4 the statistical improvement in signal to noise performance is proportional to the square root of the number of shots taken. To achieve an improvement of 4:1, therefore requires a total of 16 shots. To achieve a 5:1 improvement requires 25 shots, an increase of approximately 70%. It is clear, therefore, that there is a limit as to the practical reduction of noise levels by stacking. Indeed if to get any reasonable signal requires shooting more than 16 shots, then it will generally not be possible to shoot the VSP economically and the engineer will recommend terminating the survey. The engineer will make use of the ability of modern acquisition equipment to generate and modify stacks “on the fly” to determine the optimum data for recording and inclusion in the survey dataset. This together with spectral analyses of the recorded signals allows the effects of random noise to be examined, quantified and the effects on the survey data reduced such that the final image is not degraded. Systematic Noise The most common sources of non-random noise are electrical pick-up from cable leakage (usually monotonic, 50 or 60 Hz oscillations depending on the frequency of the rig power supply), mechanical or electrical activities from the rig crew and machinery, or local induced seismic activity (e.g. a nearby surface seismic survey). The first cause is the only one that can be easily addressed. Although it may involve considerable trouble shooting to find the source, simple re-siting of equipment or re-routing of cables solves the majority of cases. The second cause can be attacked in the same manner as for random noise, by shutting down all non-essential activities on the rig until the noise is removed from the data. This rather hit and miss operation usually results in some noise reduction, but can be very frustrating. The reduction of noise from nearby seismic operations will depend on how successful the company representative is in negotiating a “time share” agreement with the seismic survey. If this is not possible, however, it is sometimes enough to time the VSP shots to coincide with the dead time between shots from the seismic vessel depending on shot interval. Varying the time delay between shots such that the offending wavefield appears at different (pseudo-random) times in the data can also be tried, the noise reduction then achieved by stacking. VariableSource Signature This and subsequent “QC” sections are concerned with possible problems associated with the VSP acquisition systems. As these problems are directly concerned with the equipment used to record a survey, it is logical and quite correct to assume that the recording engineer can exercise more control over these aspects of the operation. The first consideration under this umbrella is that of source output. In the days when the borehole seismic survey was used primarily to provide velocity information, all that was required of the source was that it provide a high amplitude impulsive first pressure peak to enable accurate determination of travel times. There was no interest in what followed 98

this peak and in fact the source could possess all manner of secondary pulses without degrading the primary data. VSP processing, however, requires that the waveform within the data remains constant - or nearly so - from level to level in order to adequately separate the up and downward travelling wavefields. The use of airguns provides the capability of very stable source signatures, and hence stable seismic wavefields, assuming the operational parameters of the guns are kept constant throughout the survey. With a single airgun this is in fact generally easy to accomplish in good conditions, all the engineer has to monitor is that the pressure to which the gun is charged remains constant and that a constant hydrostatic head of pressure is maintained (i.e. the gun remains at a constant depth). As a further safeguard he can make periodic checks of the signature by viewing the near field monitor traces, and analysing their spectra. On fixed installations (e.g. platforms and jack-up rigs) the source can be deployed at a constant depth relative to the sea bed without too much difficulty, however, in a heavy sea state the height of water above the gun can vary considerably. It is possible to alleviate this effect by using a “height switch”. This arrangement uses two switches, attached to the airgun support, positioned a fixed distance apart and which are activated by the movement of water past the switch. These can be adjusted so that the gun can be fired only when there is a specific height of water over the gun. This arrangement may not however provide adequate results when a remote source is deployed from a boat (i.e. not a fixed installation). In this case using buoys to support the source will preserve the source character, unfortunately this means that the absolute height of the gun above sea bed is then variable leading to inaccuracies in transit time determination - this is particularly troublesome in poor weather conditions with appreciable swell. A further complication to the source output is the use of arrays. Modern airgun control systems can be constructed to ensure timing accuracies of 0.1 ms. Unfortunately these systems cannot take into account mechanical variations of the array between shots, they are of necessity “after the event” synchronising systems. Fortunately the manufacturing tolerances of sources in use today are of a very high order, once a delay is set into a firing circuit, there will be little drift. Nevertheless, automatic monitoring and updating of individual firing delays is desirable and the engineer will constantly monitor the output of an array, if there appears to be any change in output will re-synchronise the individual array elements. Figure 84 illustrates the effect of poorly synchronised array elements. The use of an array allows a more impulsive signature and a shorter reverberant tail. With either single guns or arrays, the near field monitor provides a reference for the source output and provided a record of every shot is made, can be used to design designature operators to remove the associated source effects. In a sense this allows one to be less rigorous in the treatment of the source in that after designature, the VSP data will have been normalised, on a trace by trace basis, to the output of each shot. The far field effects of earth filtering will then have far greater impact on the recorded VSP than variations in source output. To be rigorous, however, it is preferable even when using designature processes, to keep the source variations to a minimum.


Figure. 84: Effects of poor array synchronisation Poor Geophone Lock (coupling to formation) There are several degrees of poor locking but in general all result in data that is unsuitable for VSP processing. The most obvious and catastrophic occurs when the locking mechanism fails to operate or does not provide sufficient force to hold the geophone in position (in an oversized section of hole for example). If this happens, the tool will remain hanging from the wireline and any seismic energy arriving at the geophone will set the tool oscillating. In these cases there may well be, at best, only minimal contact with the borehole walls and these oscillations will not be damped producing a “ringing” signal. In such circumstances the direct arrival time may sometimes be derived depending on the nature of the signal, although there may be ambiguities as to the exact point on the signal to pick. A point to note here is that locking the tool to the formation is not necessary if the recording devices in use are hydrophones. Geophones and accelerometers are velocity sensitive devices and as such need to be excited by the motion of the medium through which the energy is travelling. Hydrophones an the other hand, are pressure sensitive devices, and in the downhole environment require the energy incident at the borehole to be transmitted via the borehole fluids. The fluid then becomes the medium with which the sensor must be “coupled”. If the tool locks to the formation, it may be possible to test the security of lock of some tools using an onboard “shaker” or “pinger”. These devices provide a mechanical excitation of the tool, the speed with which the induced vibrations die away being indicative of the quality of lock. More recently with 3-component geophones, mechanical testing has given way to electrical pulsing of the individual components, the induced oscillations used in a similar manner. These devices are a convenient plus point as a diagnostic tool although the experienced engineer will be able to recognise from the form of the VSP signal whether the tool has securely locked. Sometimes although the quality of lock is apparently good, the build up of energy with time at the tool in response to a particular shot suddenly gives rise to “micro-slippage” of the device. This usually happens around 100 to 200 ms after the direct arrivals and generally exhibits itself as ringing arrivals which swamp the real seismic data at this point in the signal. With the quality of current locking devices the occurrence of this distortion is usually confined to regions of the hole where the locking 100

mechanism is working at the limits of its operating range. It is interesting to note, however, that the test methods outlined above will not necessarily perform as expected under these conditions. Poor locking may also be apparent when running in casing. This occurs for the same reason (i.e. poor cementing) as gives rise to casing arrivals, although the record may not be affected by casing borne energy. The effect, in many cases, may be extremely localised although in some wells the poor coupling may extend for the whole casing string (Figure.85). Whatever the reason for the poor coupling, the field engineer has two alternatives available to him. When running in open hole, if the station is particularly important (for example at a formation top), then the first course of action would be to unlock, then re-lock the tool. In many cases the slight relocation of the arm and tool body are sufficient to ensure a good lock. In some cases the lock may improve to a degree but an additional unlock/lock cycle may further improve the coupling. If this operation does not work, or if the time available for the survey is limited, then the second course of action is simply to move the tool by a short distance (e.g. 10 ft or 3 m), to a region that is not affected by whatever is causing the original data degradation.

Figure 85: Good vs. poor geophone locking Most instances of poor lock outside casing are due to the hole being out of gauge, (both over and undersized). It is therefore prudent to examine any calliper log available prior to the survey in an attempt to identify any possible problem zones in advance. An obvious extension to this is that if available the CBL (cement bond log) should also be examined for the cased section. If no CBL is available, examination of calliper logs recorded prior to casing may be useful, oversized sections can often give rise to poorly cemented regions. Positionng With any remote source survey, it is of paramount importance that the exact location of the source be known for each shot. It is also very important for the majority of survey types to keep the position of the source constant for every shot at a particular level. Although it is theoretically possible to process the data for each shot record separately using independent co-ordinates, it is time consuming and not to 101

be recommended. It is not possible to accurately stack such data (due to differences in arrival times and ray path variations) without considerable manipulation of the data. The lateral positioning of a source can be monitored quite easily using navigation systems. As far as field QC is concerned, the locations of every shot are available to the VSP crew and can be compared with the target positions. The differences in travel path and hence arrival times of events can tolerate reasonably wide errors in position without adversely affecting the quality of the VSP image (although see paragraph above). A more serious source of errors arises out of uncertainties as to the depth of the source. With a constantly changing gun depth, the absolute seismic transit time will be constantly varying in sympathy. With vertical ray paths (rig source, vertical well or vertical incidence survey, deviated well) the time difference between the direct arrivals and the reflections remain constant (figure 86). This means that, ignoring the absolute value of the direct arrival time, if the first arrivals for records with different gun depths are shifted to occur at the same time, events within the data will stack in phase. The derivation of the exact transit time can then be taken as an average of the values recorded for each shot at the geophone station. This in fact involves little error as the height distribution should be random in nature unless the engineer is depth on VSP events

Figure 86: Effects of source depth on VSP events


CHAPTER 5 : VSP PROCESSIN Basic VSP Processing Sequence stacked trace comparable to a synthetic seismic record without multiples, or a set of seismic traces comprising a high-resolution seismic section in the immediate vicinity of the well.Whatever the acquisition geometry, the processing of a VSP survey can be subdivided into different stages. The first step of processing consists of: ( 1) demultiplexing the data, (2) Correlation, if the seismic source is a vibrator, (3) Correction for the signature fluctuation effect, (4) Correction for tool rotation and well deviation (3 axes borehole geophone are required), (5) Elimination of poor quality recordings, (6) Stacking of recordings made at the same geo• phone position, (7) Corrections for spherical divergence and absorption, The second processing step includes the picking of first arrival times, using the same techniques as those used in well velocity surveying in order to establish a time vs. Depth relation T = F(Z) and a Velocity model at the well. The third processing step consists of separating compressional from shear waves, and upgoing from downgoing wavefields, using velocity filters and polarization filters. Shear waves have lower velocities than compres• sional waves, exhibiting a particle-movement direction (vibration) at right angles to the propa• gation direction. Compressional waves have a vibration direction parallel to the propagation direction. The shear waves are of two kinds: SH (vibration perpendicular to the propagation plane) and SV (vertical vibration in the plane of propa• gation). The downgoing waves are characterised by positive apparent velocities and the upgoing waves by negative apparent velocities. The separation of the two wavefields can be per• formed by the application of apparent velocity filters in either the space-time domain or the frequency domain. In the frequency domain, upgoing and downgoing waves are divided into sets with nega• tive and positive wavenumbers (k'). A simple way of extracting them is to retain in the (f, k) plane only those energies that are found in f the positive or negative halves of the wavenumber field. In the space-time domain, separation of the two wavefields can be achieved by the application of filters based on the average or anti-average principle (Lamer 1982, Coppens 1982 and Hardage 1985). This type of algorithm extracts the desired signal by subtracting a noise model that has been estimated as accurately as possible. In the case of VSP, the noise model actually corresponds to the downgoing wavefield and the desired signal is the upgoing wavefield. One way of estimatingthe downgoingwavefieldis to apply a static time shift to all the VSP traces, using a value which is equal to the first arrivaltime but with a change in sign. Then, a filter can be used to recover only the infinite apparent velocities(e.g. by means of compositing or median filtering). Numerous specific algorithms have been developed to separate the upgoing and downgoing waves, including trace pair filtering (point-to-pointpredictive filter) (Mari et al., 1986 and 1989) and various multi-channel algorithms, of which one of the best known is from to Seeman and Horowicz(1983).


After wave separation, the choice of processing differs according to the acquisition geometry, well profile and geological structure. • If the source and receiver can be considered as being on the same perpendicular as the reflectors (the simplest case is that of a vertical well in hori• zontal strata with the source situated close to the wellhead) the processing steps are as follows: (1) Deconvolution of the upgoing by the down going waves. Application of a deconvolution operator at each geophone position allows the removal of both source signal and downgoing multiples. (2) Flattening of the deconvolved upgoing waves is carried out at each depth point by the application of a static correction equal to the first arrival time measured at the geophone position under consideration. This operation renders the VSP recording comparable in time (two-way travel time) to a recording obtained by surface seismic reflection. (3) Obtaining a VSP stacked trace. The deconvol• ved and flattened upgoing waves are stacked in a corridor which is placed immediately after the first arrival . This restricted vertical summation known as a corridor stack gives a trace in the seismic frequency bandwidth without any assumption about the source signature. After deconvolution, the seismic signal is a zero-phase signal. The VSP stacked trace is comparable to a synthetic seismic record obtained from sonic and density log data. A stacked trace obtained in this way may contain upgoing multiples. To remove the effects of multiples, a narrow stacking corridor is chosen in order to accept only the reflected signal received just after the first arrival. Thus, the corridor stack is analogous to a syn• thetic seismic record - without multiples - in the frequency band of the received signal. In this way, it is comparable to a surface seismic CDP stacked trace(Figure87).

Figure. 87 : Stacking corridor applied to processed VSP data, with resulting stacked trace. (Mari and Coppens, 1987) 104

• If the source and receiver cannot be considered as being on the same perpendicular as the reflec• tors (the simplest case would be a vertical well in a horizontally layered medium where the source is offset from the wellhead), the data processing is as follows• (1) Deconvolution of the upgoing waves. The deconvolution operator is unique. Since it is extracted from traces recorded at the bottom of the well, a source signature is not required (2) Moveout correction of the deconvolved upgoing waves. These corrections are carried out by introducing a velocity model derived from the first arrival times, or a model based on ray tracing techniques designed to take account of the acquisition geometry. (3) Flattening of deconvolved upgoing waves after move-out correction. This is performed by the application of static corrections at each geophone position. The static correction corresponds to the first arrival time reduced to the vertical. (4) Migration. The method most commonly used in VSP is the one proposed by Wyatt and Wyatt (1982).

Figure 88 shows an example of processing of VSP data recorded between 1045 and 105 m, the source being slightly offsetted (30 m) from the wellhead.The spacing between successivegeophone positions varied from 3 to 23 m. The figure presents a VSP after editing, showing both downgoing and upgoing waves. Upgoing waves were deconvolved After deconvolution of the upgoing waves by the downgoing waves, the VSP trace obtained in the stacking corridor is utilized to match the seismic surface survey with the downhole data as illustrated in Fig. 89. The fit is obtained by using a deconvolution technique applied to surface seismic which takes account of the source signature while attenuating the effect of multiples


Fig. 88 Example of VSP data processing. Time (s) vs. depth (m) sections, with Llz indicating distance between two successive geophone positions. (Ga; de France-IF? document)


Figure. 89 Matching of surface seismic survey with VSP data. (After Mari et al., 1987). The section (Fig. 90 7a) represents the data obtained on the vertical component Z of the well geophone. Those obtained on the horizontal cornponent X are oriented m the plane passing through the source and the well. A strong field of downgoing SV waves can be seen on the horizontal component at 0.6 s and l s for geophone depths of 930 m and 1600 m. In the example shown in Fig. 2. l 7b, the use of polarization filtering has led to a separation of the P and SV waves (vibration direction included in the source-well plane) and to obtain VSP sections in P and SV waves (Fig. 90 b).




Fig.90 VSP horizontal (X) and vertical (Z) components of the well geophone recording. (Mari and Coppens, 1989), b)VSP separation of P and SV waves. (Mari and Coppens, 1989)


The presence of residual compressional ~aves may be noted on the SV wave section. The separate processing of the VSP data in terms of P and SV wavefields makes it possible to obtain migrated VSP seismic sections (Fig. 91). The SV wave migratedsectionis shown with a time scale half of that used for the P wave section (200 ms in S = 100 ms in P), corresponding to a V,JVs ratio of 2. Correlation of the two sections cannot be achieved by eye on thJ basis of seismic features. Instead, the depths and times of primary reflections have been identifiedin the upgoing P and SV wave• fields, after their separation and before migration (Fig. 91a), using the time-depthrelations Tp = Fp(Z) and Ts= Fs(Z) obtainedby pickingfirst arrivals.

Figure. 91 Processing of offset VSP: a) extraction of upgoing SV and P waves, on migrated P and SV waves. (Mari and Coppens, 1989)


b) VSP section based

VSP processing steps Although we will consider only the basic rig-source VSP recorded in a vertical hole the basic processing sequences for all VSP types are broadly similar and generally entail the use of exactly the same processes for the majority of the processing route. The sequence can be conveniently sub- divided into five sections as follows: Data preparation and editing Separation of upgoing and downgoing wavefields Deconvolution (multiple suppression) of upgoing wavefield Enhancement of upgoing wavefield Suppression of noise and unwanted signal Figure 92 is an example of a typical VSP flow chart which illustrates most of the main divisions described below.

Figure92 Simple VSP processing route 110

Data preparation and editing The data for any VSP survey usually consists of a (variable) number of repeated observations performed at a series of different geophone stations within a borehole. The signal to noise ratio (S/N) and sometimes the signal form can vary between each of these observations at a geophone station and from level to level within the well. The variation between levels is usually not of consequence unless caused by changes in source output, indeed the form of the signal is expected to change as one progresses down the well. Differences between successive shots at the same level, however, are not desirable and can lead to a degradation in final image quality and should be dealt with in the initial stages of processing. The object of part of the data preparation process is to edit the field data to a stage where the geophone records are as consistent as possible in signal content between successive shots at a level, and to ensure that any variation between levels is caused by variations in travel path or geology. This process should also be used to obtain the best possible S/N for each level. The tools generally available at this stage are: (I)Exclusion of poorly recorded data (ii) Use of source signature deconvolution for marine data (iii)Accurate alignment in time of records at any one level (iv)Summing (v) Amplitude recovery (vi)Band limiting and notch filtering (I) Exclusion of poorly recorded data It is the nature of well geophone data, that records at any one level can exhibit remarkably different noise or signal characteristics. These may be caused by a battery of reasons from noise "bursts" from the borehole or its environs, to rig noise or micro-slippage of the wall-coupled geophone tool. Figure 93 shows a series of geophone records made at a single geophone station and illustrates this sort of variation in signal content and quality. The first record illustrates the effects of micro-slippage of the tool, this occurs when the downhole tool is not properly coupled to the formation (the methods of locking can vary but usually comprise a mechanical arm which protrudes from the side of the geophone housing see section 9.1) and manifests itself as high amplitude, low frequency variations in signal. These are due to the tool casing resonating after being excited by the incident seismic energy pulse. A geophone that is well coupled to the formation will not exhibit these resonances, they will be effectively damped through the contact of the tool casing with the borehole. This particular record was generated by not allowing the locking arm to couple to its rated locking force. For the third and subsequent traces the geophone has been fully locked, although it is quite obvious that there is a degree of variation in S/N performance between shots, probably as a result of changes in the general conditions in the environment. These records were recorded in a "quiet" hole using a relatively low energy seismic source. Bad records, in this case the first two, should be excluded from subsequent processing and in cases where all records at a level are thus affected, it may be necessary to exclude the complete level from the VSP.


Figure 93 Variation in data quality caused by variable coupling to the format

ii) Use of source signature deconvolution for marine data The use of this technique is only applicable where a source signature representative of the transmitted seismic pulse is available. This usually means that this process is restricted to marine locations due to the difficulties in recording an accurate source monitor signal for onshore wells. There are two reasons for applying this technique. Firstly it is desirable to remove any source effects from the VSP (for example when using airgun sources, the contributions from the source bubble to the image should be 112

minimised), and secondly in the case of a varying source output, the process can be used to stabilise the source signature from record to record. If the source has been so designed as to provide as impulsive a signature as possible - without the presence of a bubble-tail - this process may be considered superfluous. If the source output is varying between shots, it is considered essential to apply a signature deconvolution process. The variation in source character will be seen to add at best a degree of random noise to the data reducing the inherent resolution, and at worst may add a non random element which may confuse and mislead the interpretation of the data. Figure 94 demonstrates the effect of applying a signature deconvolution technique to data acquired using a single airgun as the source. In general this process can be applied before or after summing of records at the same level, the trade off being in computational overhead. It is generally preferable, however, to apply the process prior to summation.

Figure 94 Effects of signature deconvolution.

(iii) Accurate alignment of records Times from well geophone records are usually derived as the interval between the first arrival at a near field monitor and the first arrival at the downhole geophone. These times can be picked either "break to break" or "trough to trough" and can be achieved manually or by the use of automatic timing routines. 113

Automatic routines can be applied using various methods; for example, threshold, cross correlation and polynomial fit. The threshold technique works well for break picking provided the data possesses a high S/N, cross correlation techniques work well for trough picking - even in the presence of noise and polynomial fitting works well for either break or trough and does not require that the signal envelope under analysis is consistent from trace to trace. It should be noted, however, that the cross correlation can be adversely affected if there is any variation in the signature from record to record - see point (ii) - or if there is not consistent coupling of the geophone to the formation. In order to achieve the optimum stack of common depth records it is necessary to remove time variations within a level before summing. This can be achieved by calculating the average first arrival time of the traces to be summed and then shifting the individual first arrival times to this average time before summing.

(iv) Summing This process has been alluded to in preceding paragraphs and is usually the final stage in data preparation prior to actual signal processing. In this process all available records after editing (as above) are summed for each record with a common source-receiver configuration. This process effectively reduces any random noise evident in the data. It is important, however, for some applications that the absolute amplitude of the data be preserved and amplitude corrections depending on the number of records summed have to be made. Figure 79 demonstrates the application of this technique to a particularly noisy set of records. Statistically the improvement in S/N for such data is defined by the square root of the number of records in the stack so for 4 records in the stack there will be a 2:1 improvement in S/N, Figure 95Improvement in signal / noise ratio by summing.

Figure .95: Improvement in signal / noise ratio by summing 114

(v) Amplitude recovery The recorded trace decreases in amplitude with time due to three main effects; spherical divergence, transmission loss and absorption. The amplitude of events within the VSP are reduced to a degree where later arrivals cannot be seen on the display. Therefore the purpose of the amplitude recovery processing is to restore the amplitude of the events so that they correspond to the amplitudes expected from each of the reflecting interfaces i.e. all amplitude ratios are preserved. Spherical divergence is a function of the seismic energy being distributed over the surface of a spherically expanding wavefront. As the wavefront progresses through the earth the energy density at its surface decreases as a function of the expanding area. Transmission losses occur as the wavefront traverses an acoustic impedance contrast (a reflector). In this instance the seismic energy is partially reflected and the remaining energy transmitted will of necessity be at a lower level than immediately above the reflector. The final mechanism arises out of the fact that the earth is not a truly elastic medium. The molecules comprising the rock matrix form the basis of a natural attenuator and there will be selective absorption of energy depending on rock type, depth of burial, tectonic history etc.For surface seismic data in a homogeneous medium, the recorded amplitude is proportional to T the reflection time. All the effects together can be expressed as Tn, where n≤2. For VSP data it is found empirically that n = 1.5 gives a good basis for amplitude recovery in many cases and in practice values between 1 and 1.5 are used. In theory to provide an accurate amplitude recovery the amplitude function applied to the downgoing wavefield should be different to that applied to the upgoing wavefield as a single recovery function applied down the trace will not properly account for the spreading seen by the upwave. In general, however, the application of separate functions depends on the purpose for which the data has been acquired. If straightforward correlation with the surface seismic data is the prime reason then the single function is adequate. If a process requiring the exact preservation of relative amplitudes is to be performed, then more thought is required on the part of the processor. Figures 96 and 97 illustrate VSP data before and after application of such an amplitude function.

(vi) Filtering The choice of any band-limiting or notch filter is best made by inspection of F-K transformed data i.e. data after the application of a fourier transform operator (transformed from time-depth to frequencywavenumber space). Any noise bands are immediately visible on data thus processed and in addition it is usually quite an easy task to identify the usable bandwidth of the propagating up and downgoing wavefields. Figure 98 is of the raw VSP data from figure 80 after transformation and one can clearly estimate the highest usable frequency by observing the limits of the coherent section of the respective wavefields. The filtering process should be utilised at various stages of the processing route and there are three main stages that require such processing as a necessity. The first filter is applied at the initial inspection stage to effectively set the primary bandwidth of the data. The second is applied after deconvolution (removal of multiples) to cater for any spectral anomalies and noise introduced by the deconvolution operation. Finally the data should be filtered.


Figure .96: Data prior to amplitude recovery

Figure.97:Data after amplitude recovery 116

Figure.98:F-K transform of raw VSP data aligned at one-way time‫ز‬

Separation of upgoing and downgoing wavefields When the data from a conventional rig source VSP are plotted the downgoing and upgoing events are seen as overlying wavefields which display an equal but opposite dip through the section. Separation of these wavefields is necessary for the further processing of the data for the following reasons: The upgoing wavefield contains information concerning the subsurface in terms of acoustic impedance and structure; indeed it is the wavefield that one is trying to retain and enhance. The downgoing wavefield due to its shorter travel paths in the subsurface, is of higher amplitude than the upgoing wavefield and thereby obscures to a large extent the information that one is trying to recover. 117

(ii) The downgoing wavefield contains information concerning the multiple activity present in the upgoing wavefield. It follows, therefore, that although the "target" wavefield consists of the primary upgoing events, a necessary step in the isolation of these data is the identification of the downgoing wavetrains from which to design the deconvolution operators There are various methods for wavefield separation but whatever the method adopted it will be subject to the effects of spatial aliasing. For VSP data there exists a fundamental alias frequency which is defined by the travel time between adjacent geophone stations. Other bands of aliased energy occur at the harmonics (multiples) of this frequency and at zero frequency. A common misconception is that the resolution of VSP data after wavefield separation is limited by this fundamental alias frequency. This in fact is not so, the band of frequencies affected in each alias band is relatively small and it can be shown that the small distortions caused by spatial aliasing are quite acceptable. The use of non-linear operators in processing (such as the median) can, under certain circumstances, lead to aliasing effects that are almost negligible. This aside there are occasions when the aliasing effects can down-grade the VSP performance, for example Pand S-wave partitioning using 3-component data - of which more later. Synthetic data is used for the purposes of this discussion as it is essential to know the exact form of the wavefields before the separation process is applied so that the quality of the wavefields after separation may be assessed. The use of just two reflected events is quite justifiable when linear operators are employed (i.e. if the effect of wavefield separation on a number of reflections is exactly the same as the addition of the responses of the individual reflections after wavefield separation). For non-linear processes such as the median or coherency type operators, the situation is not quite so straightforward. Figure 99 illustrates the subsurface model employed throughout this discussion.


Figure 99 Synthetic model

Aliasing and VSP data 118

The data from a standard rig source VSP survey form a two dimensional wavefield for which the dimensions are depth and time. Both are discretely sampled but with different consequences. (a) For time sampling, anti-alias filters are included in the recording system to attenuate energy above the Nyquist frequency (i.e. the frequency above which alias effects occur, this is equal to half the sampling frequency). If this energy were not suppressed it would "fold into" the useful seismic frequency band and cause distortion. Correct use of the recording instrumentation will therefore eliminate temporal aliasing.

It is not possible to provide in the VSP sense a continuous depth record and additionally it is not possible to "filter" depth. It is not therefore possible to remove depth contributions that may lead to aliasing effects and as a consequence spatial aliasing effects will be introduced whenever multichannel processes (again, for example, the median operator) are applied to the data. (b)

Broadly speaking the downgoing and upgoing data form two distinct wavefields. Under spatial aliasing, these are indistinguishable at certain narrow frequency bands and these are referred to as aliased or folded frequencies. The fundamental alias frequency can be deduced from the relative dips of the wavefields in the time-depth domain (T-X space). If the relative dip is T seconds per trace, then the fundamental alias frequency of an event is 1/T Hz; further aliasing occurs at harmonics (multiples) of this frequency i.e. 2/T, 3/T Hz etc. bands of such energy can be identified on figures 48 and 85. The alias bands (apart from zero frequency) can be increased to beyond the useable bandwidth of the VSP data by simply reducing T i.e. by decreasing the separation of the geophone stations. Although close spacing is a sufficient condition for effective wavefield separation, it is not a necessary one, this should become apparent from the following examples.


Figure.011: Wavefield separation using F-K fan filters 120

Wavefield separation methods (i) F-K filters (a) Fan filter Consider the model illustrated in figure 99. The expected response of this model to both down and upward travelling energy is plotted in figure 011panel (a). It is obvious from this display that the instantaneous dips of the wavefields vary according to the velocity of the medium in which the sensor is positioned. Such variations in the wavefields make their estimation more complex as they are not defined with one dip but are resident over a range of dip values. Panel (b) of this figure shows the energy distribution in F-K space. A conventional solution to wavefield separation is to apply a fan filter in its reject mode to the data (in F-K space) with downwave alignment. In this case, however, the fan has such a wide spread that a large proportion of the upgoing wavefield is removed along with the downgoing. This is especially true at higher frequencies where, after folding, the fan becomes very wide indeed. Panel (c) illustrates what is left of the upgoing energy after application of the fan filter and it is easily seen that there is no significant energy over 50 Hz remaining in the data with a significant gap in the spectrum between 25 and 40 Hz depending on the upwave alignment. The application of the fan filter has obviously distorted the upwave spectrum to an unreasonable extent. Panel (d) illustrates the resultant upgoing wavefield estimate in T-X space and the lack of high frequency content is easily apparent in the broadening of the wavelet. (b) Wavenumber filter It is clear from the foregoing example that the majority of the problems in the use of the F-K transformed data for wavefield separation originate from the width of the filter applied. A very convenient and simple way of avoiding these problems is to force one of the subject wavefields to have constant dip. It is a property of the VSP that the downwave is almost spatially invariant down the array of geophones in real data sets and is therefore an ideal candidate for this type of treatment. A simple method of ensuring constant dip is to shift the traces toward time zero by an amount corresponding to their respective measured first arrival times. The first arrivals will then exhibit zero dip between traces and due to the invariance of the downgoing multiple train, the downgoing reverberants will also exhibit zero dip. Figure 010 panel (a) illustrates this alignment using the same synthetic data set as for the fan filter example. Panel (b) shows the F-K transform of this data; the horizontally aligned downwave is transformed to a narrow vertical band of energy in F-K space with an alignment at K=0. The upgoing energy still folds across the downgoing at regular intervals which correspond exactly to the frequencies seen with the data aligned at recorded times, the first 121

intersection occurs at zero frequency, the next at 25 Hz with subsequent intersections at higher frequencies. This first intersection (above zero Hz) defines the fundamental alias frequency of the steeply dipping upgoing events seen in panel (a). The shallower dipping event has its own set of alias frequencies the first of which occurs at about 60 Hz. This discussion implies that the preferred method of suppressing the downgoing wavefield in F-K space is a narrow wavenumber reject filter whose band limits just encompass the downgoing energy. As with the fan filter, wavenumber filtering also rejects segments of the upgoing energy and although these segments are very much smaller, the upwave spectrum is still left with small "bites" taken out of its spectrum; these can easily be seen in panel (c) of this figure.


The transformation of the wavefield back to the T-X domain provides the estimated upgoing wavefield. A cursory inspection of the data suggests that the resolution has been retained and that there has been no significant distortion of the VSP wavelet.

Figure 010 Wavefield separation using F-K wavenumber filter The wavenumber filter discussed in the previous section was applied with a "box-car" shaped accept band; in T-X space this is equivalent to a Sinc function ( sin x / x ) acting as a filter or 123

smoothing operator across the traces (both of these approaches introduce side lobes to the wavelet and in the case of the wavenumber filter these can be reduced by applying a cosine taper to the pass-band). Median filter An alternative approach in T-X space would be the use of a running average across the trace, the results would be similar to the box-car wavenumber filter. A disadvantage of the average (mean) function is a tendency to "smear" energy between traces; a more effective separation can be achieved by the use of the median operator. For the estimation of the downwave the median behaves in a similar manner to the running average because the downgoing wavefield tends to be spatially invariant (this property providing near enough identical samples to work on between traces). The strength of the operator, however, lies in its treatment of the upgoing wavefield. For a randomly distributed reflectivity sequence the overall effect of the median is similar to the wavenumber filter in that bands of aliased energy are included in the downwave estimate. For an isolated reflection event, the median effectively "ignores" the upwave in its estimation of the downwave, see figure 102r(right) for an explanation of the operation of the median. Returning to the synthetic model, the median operator is applied horizontally across the data aligned at zero time to provide the downwave estimate. This estimate is then subtracted from the original data leaving the upgoing events with the high frequency response preserved. The action of this filter on the synthetic data is illustrated in figure 102(left). If there is a genuine change in the character of the wavefield being enhanced, another important property of the median is that it will preserve the change. Any running average or F-K filtering will tend to "smooth over" the transition and hence will produce a distorted image over that section of the data.It should be noted that the so-called ‘upgoing’ wavefield derived in this way actually contains all wavefields except downgoing and requires enhancement to isolate the upgoing wavefield (see 4.4).


Figure 102.,The operation of the median(right),Wavefield separation using median filters (left)

Parametric wavefield separation Another approach is ‘parametric wavefield separation’. In this method wavefields are parameterised according to a particular characteristic (for example moveout, apparent velocity etc.), these parameters are then used to guide a “coherency” estimate of the wavefield across the data, the idea here is that the required wavefield will occupy the specified alignment and can therefore be directly estimated using the specified measure of coherency. This method has the advantage that all data is taken into account in the separation process which is done in one pass however many wavefields are being separated. This differs from the median method where wavefields are enhanced and subtracted in turn. At each subtraction, aliasing between wavefields can potentially result in degradation of the results. Additionally, the upgoing wavefield output from this method should contain upgoing arrivals only and rarely needs further enhamcement. So what is the distortion introduced by spatial aliasing? The foregoing discussions imply that there is very little distortion for the wavenumber or median filtering but significant amounts for the fan filter. A detailed examination of the events on trace 45 of the synthetic data set before and after wavefield separation reveals the changes. Figure 103 shows the comparison for each separation type . It is immediately apparent from these traces that the fan filter has considerably distorted the wavelet and lowered the effective bandwidth of the data. Both the wavenumber and median filters have basically preserved the bandwidth of the data although the wavenumber 125

filter has introduced low amplitude events into the precursor and tail of the wavelet. The median filtered trace shows no evidence of wavelet distortion of the upgoing energy and clearly for these isolated events has done a better job than the wavenumber filter. As hinted above, this is not always the case, if there were a significant number of upgoing events the distortions for both the wavenumber and median filters would be similar and the only strong reason for using one technique over the other would be a saving of computational time for the median operator. As with all such statements the situation in the real world is not as straightforward as this and other considerations must be borne in mind. For example, the median operator is not a linear process and the application of a spectral filter prior to the median operator will not necessarily produce the same image as applying the spectral filter after the median operator. The proven conventional wavefield separation policy can be summarised as: (i) Shift the traces to zero time, then either (b) Estimate the downgoing energy with a narrow accept wavenumber filter.Estimate the upgoing energy using the same narrow band wavenumber filter in its reject mode (to suppress the downgoing energy)

Figure .103: Comparison between resulting wavelets from F-K and median wavefield separation 126

Wavefield separation in real data Synthetic data examples are of great use in developing techniques or arguments but the proof of any technique comes when one applies the processes to real data sets. For the purpose of this demonstration data from a well in the North sea are used. The survey was recorded using a fixed geophone station increment of 25m and the source (a single Bolt airgun) was suspended from the rig at a depth of 9m. Figure 104 shows the data at one-way times sub datum; the data have been stacked, an amplitude recovery function applied, and the panel has been filtered to remove any high frequency noise that may be present in the VSP. Figure 90 shows the data after downwave alignment, that is with the traces shifted toward time zero by their first arrival times. The wavefield separation applied to this data set has been accomplished by using the median separation technique described above and figures 105, 106 and 107 show the data after downwave enhancement, data after downwave subtraction and then shifting to two way arrival times respectively. This VSP is the same data set as that shown in figure 108 where the raw wavefields prior to separation were displayed at two-way time. For comparison purposes this figure has been reproduced here as figure 109, and one can immediately see the improvement in clarity of the upgoing wavefield.

Figure. 104: VSP data at one-way time sub datum 127

Figure. 105:0Data after downwave alignment


Figure. 106 :Data at downwave alignment after downwave enhancement


Figure 107: Data at downwave alignment after downwave subtraction 130

Figure 108: Data after downwave subtraction aligned at two-way time


Figure.109:Data aligned at two-way time without downwave subtraction


Median filter An alternative approach in T-X space would be the use of a running average across the trace, the results would be similar to the box-car wavenumber filter. A disadvantage of the average (mean) function is a tendency to "smear" energy between traces; a more effective separation can be achieved by the use of the median operator and this is discussed below. For the estimation of the downwave the median behaves in a similar manner to the running average because the downgoing wavefield tends to be spatially invariant (this property providing near enough identical samples to work on between traces). The strength of the operator, however, lies in its treatment of the upgoing wavefield. For a randomly distributed reflectivity sequence the overall effect of the median is similar to the wavenumber filter in that bands of aliased energy are included in the downwave estimate. For an isolated reflection event, the median effectively "ignores" the upwave in its estimation of the downwave. Returning to the synthetic model, the median operator is applied horizontally across the data aligned at zero time to provide the downwave estimate. This estimate is then subtracted from the original data leaving the upgoing events with the high frequency response preserved. The action of this filter on the synthetic data is illustrated in figure 110 If there is a genuine change in the character of the wavefield being enhanced, another important property of the median is that it will preserve the change. Any running average or F-K filtering will tend to "smooth over" .

Figure 110 Wavefield separation using median filters Deconvolution of upgoing wavefield In VSP data the strongest wavefield is always the downgoing one. This is because it comprises the direct arrivals and even-order reverberants, the majority of which being generated in the near surface where reflection coefficients tend to be large. The upgoing wave, by contrast, as it consists of odd-order reflections is always scaled down by at least one reflection coefficient 133

compared to the downgoing wave at the same time. It follows, therefore that the major contribution to the form of any upgoing primary reflection event will be from the downgoing wavefield and to a first approximation the upgoing wavefield at any point in the subsurface will consist of a scaled version of the downgoing wavefield measured at the same point. The downgoing wavefield, therefore, contains a description of the reverberant systems that are appearing in the upgoing wavefield and can be used in the design of deconvolution (multiple suppression) operators. The downgoing wavefield will consist of two components, the reverberant system which will be minimum phase and a source generated component which may not. Two approaches can be taken in the design of the deconvolution operators. The first approach involves the design of a gapped operator which will "collapse" the reverberant tail and then to separately apply a wave-shaping operator to produce the desired final wavelet. The alternative approach is to design a single operator containing both the multiple and source generated components separately assessing the minimum and maximum phase portions of the signal.. The results are similar to the two stage operation described above.The deconvolution operators designed from the downgoing wavefield are applied on a trace by trace basis and applied to the equivalent upgoing wavefield. Figure 111 illustrates the application of this type of deconvolution. In general the use of the downwave derived operators as described here, produces a more effective deconvolution. The use of longer operator lengths gives a more complete removal of the longer period reverberants and the ability to use long operator lengths of the same order as the design window comes from the deterministic nature of this type of deconvolution. As the downwave can be precisely measured, providing the reverberant tail of the upgoing wavefield mirrors that of the down, the deconvolution is also precise. As an aside: Conventional deconvolution techniques which use statistical methods to derive the operators cannot make use of long operators. These techniques rely on the assumption that the reflectivity sequence of the earth is essentially random and the autocorrelation functions of the upwaves are inspected for any non-random events within a specified design window. These nonrandom effects are then attributed to multiple activity and the operator designed accordingly; the operator lengths are therefore of necessity shorter than the design windows. The basic assumption of the random aspect of the reflection sequence is not rigorous and can lead to errors in operator estimation, the deterministic downwave deconvolution process makes no such assumptions. As described above, the downgoing wavefield at any point in the borehole can be used to deconvolve the upgoing wavefield at the same point. This process will, however, only deconvolve reverberants that have been generated by at least one primary above the point at which the downwave is being observed. The application of a single operator will therefore not deconvolve any interbed multiples that have been generated by at least two primaries below the point of observation, indeed it will not remove any upward travelling reverberants. If one remembers that the amplitude of the primary upgoing wavefield is smaller than the downgoing by one reflection coefficient, it should be obvious that the contributions from upgoing


Figure 111: VSP data after deterministic downwave deconvolution Enhancement of upgoing wavefield After the upgoing wavefield has been isolated it is generally necessary to enhance it against the general noise background so that a detailed study may be made of its form and variation. In general the same techniques as were used to isolate the downgoing wavefield can be used to 135

enhance the upgoing, albeit with important differences. In most VSP data the reverberant events in the downwave are near-consistent, at least in the early part of the data, from trace to trace. This is a function of the majority of the downgoing arrivals being generated in the near surface, where the lithology is often close to horizontal. As one progresses into the earth structural effects can become more pronounced. In the presence of structure the upgoing events will show moveout in time from trace to trace due to migration effects and these effects can become significant at depth. Any processing that attempts to enhance the events in the upgoing wavefield must therefore be capable of preserving and indeed clarifying any events thus affected. In particular, the length of any spatial operator should be short enough to preserve any changes in moveout or terminations of the events within the body of the VSP, but long enough to ensure that local variations in the events do not prejudice the overall continuity of the data. Figure 001 the results after the application of a median based point spatial filter designed to recognise only horizontal or close to horizontal events. Much of the lithology at this well is horizontal and therefore this form of enhancement has been reasonably successful in rejecting noise and enhancing the desired arrivals. Similar results can be obtained for data exhibiting dipping arrivals by defining the median operator to accept arrivals that display a particular moveout within the data. This will be more effective in enhancing dipping events but will suffer from similar limitations as the horizontal operator, in that noise arrivals may still be enhanced if they occur at alignments close to that of the filter limits. Figure 001 shows the same data as 001but in this case an alternative enhancement filter has been applied. The filter is still based on the median operator, still has the same number of sample points but is now applied in two passes. In the first pass a range of slope values are examined and the median value for each slope alignment calculated. The slope with the largest median value within the scan range is then stored along with the value. The second pass examines the stored values; if the slope lies within a predetermined range of slopes, then the stored value is output as the value for that sample. If the stored values lie outside this accept range, then the sample is zeroed. This filter has the characteristic of enhancing any upgoing energy in the specified window (as these events will usually possess a reasonable amplitude), but ignoring any coherent noise arrivals, statistically more of which exist outside of the expected upwave alignment than along it. F-K techniques can also be used to enhance the upgoing data. Fan and wavenumber filters are the most popular types in use by the industry and any enhance/reject window can be applied to the data, as such these filters can be very flexible in use. It is more difficult, however, to define exactly the portion of F-K space to which one wants to apply the process and in practice the specification of slope when using the median operator is far simpler. Other operators such as mean or semblance can be applied to the data, the appropriate choice depending very much on the individual data sets although the industry as a whole tends to favour either median or F-K methods.


Figure 001: Deconvolved upgoing wavefield after application of horizontal median operator


Figure 001: Deconvolved upgoing wavefield after application of noise rejection filter enhancing dips of up to 1ms/trace

Noise and unwanted signal Noise within VSP data sets can be attributed to many factors. The two main classes of noise are (a) noise generated by the recording equipment or techniques, and (b) unwanted seismic arrivals. The first classification can be subdivided into two further categories:

(I) Mechanical/electrical (ii) Physical (eg tube wave and casing arrivals) In category (i), the main generating mechanisms are functions of the electrical and mechanical properties of the recording equipment, and category (ii) arrivals are generally due to the configuration of the survey. 138

(I) Mechanical/electrical The electrical noise generated by the recording equipment with present day technology is of a very low order and this is illustrated by the fact that most of today's seismic recorders have dynamic ranges in excess of 120 dB. There are forms of electrical interference other than component noise, the most prevalent of which is mains pick-up. This is where the signal leads from the downhole tool or monitor transducers are for some reason inadequately shielded from stray magnetic and electrical fields originating form the rig's power supply system. This noise is usually present as 50 or 60 Hz sine wave interference depending on supply type. Problems of this nature can usually be isolated in the field but in some instances no remedy can be found (a point to note here is that if all the signal path uses digital information transfer, the likelihood of this type of noise is much reduced). There are two methods of removing this noise, firstly a very narrow band reject (notch) filter can be applied to the data if the noise is monotonic, although this should be avoided if at all possible as it distorts the VSP wavelet. The second method is simply stacking shots at a level where the noise appears anti-phase, the subsequent cancellation effects effectively removing the offending "arrivals". There are also a number of causes of mechanical noise, the most common of which are tool resonances induced by poor locking of the geophone to the formation. In this case the degradation of the signal is easily apparent via the surface QC system and if necessary, the location of the tool can be altered to provide a good lock. Again in modern tools the majority of mechanical resonances have generally been reduced to a minimum, either in the design stage or by judicious application of damping devices in the field.

(ii) Physical The mechanisms for the generation of tube or casing arrivals have been dealt in last chapter ,but it was noted there that the possibility of reducing their effects in the field are somewhat limited. These classes of arrivals must be removed using some of the processing techniques noted throughout. Casing arrivals: as noted earlier these exhibit an apparent velocity within the data characteristic of the steel that is transmitting them. They usually occur in the vicinity of the first arrivals and tend to mask the real direct arrivals. As they form a coherent set of arrivals, they show the same character from shot to shot and cannot therefore be reduced by the summation of shots at a level. These arrivals, however, usually show a spectral content which is of higher frequency than the seismic arrivals and can therefore be attenuated by the application of a low-pass filter. Tube arrivals are more problematic. They do not usually lend themselves to attenuation via spectral filtering due to the variability of the arrivals for different geophone locations. The quality of the geophone lock has a direct bearing on the expression of any tube arrival at a particular geophone station. In many ways a tube wave is analogous to the seismic arrivals that are the aim of the survey. As such they can be attenuated to a great extent, by treating them as a separate class of arrivals and applying wavefield separation techniques. Both median and F-K approaches 139

are valid and the mechanism is exactly the same as for downwave subtraction, the initial alignment however has the tube waves positioned to present zero moveout of events between traces. Figure 114 is of a VSP which suffers from tube wave interference, figures 115show the data after tube wave subtraction using median estimates of the tube wave. The separation techniques were applied as for downwave subtraction. There is a small amount of residual energy present this being an unavoidable function of the variability of arrivals between geophone stations. In this particular case, however, the effects of the residual tube wave are confined to high frequencies and can be removed quite effectively by spectral filtering. Another class of arrivals which can be considered as noise are mode-converted S-waves. These can be used to gain useful geophysical information but more often than not interfere with the upgoing P- wave to an unacceptable degree. Again similar separation techniques can be applied, although due to their close association with the P-wave are not usually 100% effective. All the foregoing discussions assume that a single geophone sensing element with its axis placed vertically has been used for the acquisition. In the majority of cases these days, a 3-component geophone with sensors placed in a cartesian coordinate system is used to record the VSP and these allow a more rigorous separation of P- and S-mode energy fields


Figure 98 VSP with tube wave arrivals

Figure .115: VSP after tube wave subtraction using median techniques


CHAPTER 6: ESPECIAL TOPICS Types of VSP surveys Figure116 illustrates the five most widely used VSP configurations. The rig source VSP (panel A) in areas of zero dip illuminates the subsurface in the immediate environs of the borehole, contributions to the reflection image originating from the fresnel zone centred at the well. Panels B and C from this figure show the effect of offsetting the source from the receiver location. In the case of both the offset source and the rig source into a deviated well, it can be seen that the propagation history of the energy allows reflections to be received from locations away from the borehole. It is a small step thereafter to deduce that this will allow for the generation of subsurface images away from the well location. If one extends the treatment of deviated wells, panel D illustrates that by positioning the source vertically above each geophone station, the resulting ray paths provide exact equivalents to the normal incidence surface seismic trace (note that this is only strictly true for regions of zero dip). This survey is perhaps one of the most useful VSP configurations in that a two-dimensional seismic record can be produced with a very simple processing route; this geometry is sometimes referred to as a "Walkabove" survey. The final commonly used survey type is that of the "Walkaway" VSP. Whereas for the majority of the surveys noted above, the source is held stationary and successive records are taken after the geophone has been relocated, the Walkaway survey as its name implies, holds the geophone station constant and "walks" the source away from the well location. In practice the source is generally shot along a line through the wellhead in a direction to provide a two-dimensional subsurface image over a particular subsurface feature. In theory this survey type allows for a large amount of data to be acquired in a short period of time whilst also providing a reasonably even cover of the subsurface around and beneath the well location. Although the offset source and Walkaway options are shown in vertical boreholes they are equally applicable in deviated wells although the processing route may be subject to slight modification. Further VSP designs (see figure 117) address particular applications. The "Walkalong" VSP (panel A) is the "oblique incidence" equivalent to the Walkabove survey and is appropriate for a borehole deviated in an arbitrary direction in an area of constant dip and strike -- although the imaging of such a survey is far from trivial! Both the "Walkaskew" and "Walkaround" have applications in the study of rock properties. The former attempts to maintain a constant angle of incidence at the target, so that lateral changes in rock properties can be inferred from lateral changes in reflectivity. The Walkaround is the circular equivalent of the Walkaway and could be used to study changes in reflectivity in a area of low dip. Its main potential use, however, is the study of azimuthal anisotropy through the analysis of the direct compressional and shear wave arrivals. Walkaway and Walkaround surveys are subsets of the 3D VSP, recorded with an areal spread of source positions. Such surveys have only recently become commercially viable with the development of borehole geophone "strings" allowing simultaneous acquisition of several geophone stations. A further variation on the theme is the Reverse VSP. Any of the configurations noted above can be reversed with the source positioned downhole with a surface spread of receivers. This 142

arrangement can have cost and logistic advantages on land but presupposes either expendable boreholes (explosive sources) or non-destructive sources.

Figure 116 VSP survey types

Figure 117 Further VSP designs 143

In every instance it is advantageous to know approximately what results to expect from a given survey configuration. Indeed in many cases, just to know whether the proposed survey will even have a chance of fulfilling the stated objectives, is an item of information that is not always apparent from common-sense considerations. Some means of simulating the results of surveys is therefore required. Before leaving the topic of survey configurations, a general set of surveys that are gaining more and more interest with increasing levels of technology is that of the so called 3D VSP. These are the direct analogy of the 3D surface seismic dataset with the proviso that the array used to record the data is limited to a single location in the subsurface and hence the redundancy of data seen in the 3D VSP is not fully emulated. The surveys do, however, provide very detailed cover in the vicinity of the well and, in theory at least, provide the opportunity for extremely high resolution of detailed structure about the well. Figure 118 illustrates the generic form of the survey and they will be discussed in more detail after the section on walkaway surveys.

Figure 118 Generic 3D VSP design

3-component processing "Traditional" VSP recording techniques relied, until the mid 1980s, almost exclusively on the use of single-axis borehole geophones. The instruments were deployed in a manner that ensured that the sensing element had a maximum response to seismic energy where the associated particle motion was in the vertical direction (see figure 119). It was assumed that the major elements of the seismic wavefield were up and downward propagating P-wave energy fields. For the rig source VSP in the vertical hole and the vertical incidence VSP in a deviated hole this assumption usually proves adequate, providing the local structure has low dip and is not complicated by faulting or intrusions. If there are to be significant offsets of the source from the geophone, or in regions of high dip/complex structure, this assumption is no longer valid. In the simplest case of a purely compressional wavefield, the oblique angle of arrival of the energy at the downhole detector gives rise to an effective reduction in amplitude of the recorded signal. In general, geophone sensitivity reduces proportional to the cosine of the angle between the direction of arrival and the geophone axis. Consequently P-wave arrivals will not be recorded with correct amplitudes unless incident in a direction precisely along the geophone axis (figure 119). Further to these considerations, when the source is laterally offset from the receiver, the propagation paths are no longer perpendicular to the bedding planes and there is therefore a component of particle motion along the acoustic interface. This means that in addition to the transmitted P-wave energy at an interface, some of the energy can be mode-converted to S-wave and transmitted as such with possible re-conversion at subsequent interfaces etc., moment's 144

thought allows the deduction that with some configurations and dips, S-wave energy could be maximally recorded by a vertically polarised geophone with a minimum recording of the P-wave energy. In the more general case of a more even split in energy between the wave-modes, it is quite often the case that the spatial proximity of the P- and S-wave arrivals gives rise to unacceptable aliasing effects, if filters depending solely on apparent differences in velocity are used to partition the wavefields. If the VSP wavefield is recorded using a "3-component" downhole geophone many of these problems can be avoided. In the majority of 3-component tools, three geophones are arranged to be mutually orthogonal, forming the standard x,y,z axes of a cartesian co-ordinate system. With such an arrangement the full 3-dimensional particle-motion vector can be recorded. With a knowledge of the particle motion one can exploit to the full the differences between the P- and S- propagation modes and accurately partition the two wavefields for separate processing. In certain circumstances (usually where there is only one significant mode-conversion interface) the S-wave data can be processed to provide an alternative subsurface image to that provided by the P-wave. One problem that must be overcome before any 3-component data can be processed is that of geophone alignment. As the geophone is suspended down the hole by means of a wireline cable (figure 120) it is clear that the tool is free to rotate in the borehole between successive stations depending on the torque experienced by the cable. It is obvious also that unless there is some means of referencing the orientation of the sensing elements, the horizontal component information will be of little use. There are basically two ways to overcome this problem. The most obvious method is to find some method of directly measuring the tool orientation, and this can be accomplished by incorporating some form of gyroscopic measuring device in the downhole tool. This method provides the most accurate solution and allows the simultaneous acquisition of a borehole directional survey with the VSP. This approach is not always possible and very difficult to achieve with current technology if strings of downhole geophones are employed. If this route is not possible then all is not lost as the second method utilises the amplitude information recorded by the geophones by making a couple of simple assumptions. The assumptions made are: a) The first arrival at the geophone is the directly propagating P-wave and (b) The direction of arrival lies in the source-receiver plane. The P-wave energy usually travels with the highest seismic velocity and will arrive before any other wavemode, unless one is extremely unlucky with unexpected refraction effects. The direction of arrival is slightly trickier but again the least-time path between source and receiver


Figure 119Sensitivity of geophone

Figure 120Transformed co-ordinate system The combination of these factors means that the amplitude of the arrival as measured by each of the sensing elements will be a function of the angle the associated particle motion makes with the sensing element and hence for P-waves, the direction of arrival. As the direction of arrival is defined by the source receiver plane it is now a trivial exercise to derive the tool orientation and most processing approaches use either a power analysis of the direct arrivals, or using particle motion diagrams (hodograms) These computational methods produce results that generally agree remarkable well with those from direct measurement but there are instances when this approach is not feasible, for example: (1) The first arrivals are not direct downward travelling P-waves (2) The first arrivals are P-waves but are contaminated with other arrivals (eg casing) (3) The directions of arrival are not coincident with the source direction for all the levels in the VSP due to subsurface structure etc (4) The signal to noise ratio of the horizontal components is poor (5) The source is not offset from the geophones. Fortunately, as implied above, items 1 to 4 do not usually play a significant part. Item 5, however, is unavoidable with a rig source data set in a vertical well, the only secure method of orientation in this case being the gyro measurement.


Imaging of VSP data As recorded the VSP contains no readily accessible information regarding the spatial positioning of the reflection data. How then is it possible to derive a two-dimensional subsurface image from data that are recorded as a function of depth and time? Figure 120 is a very simple schematic illustration of an offset source survey. A horizontally layered earth of uniform velocity (so that refraction effects can be ignored) is modelled and several reflection paths from the offset source to the downhole geophone are shown, one for each of the reflecting interfaces. If the reflection points for every interface are joined it can be seen that the locus of the reflection points describes a smooth curve starting at the geophone and moving away from the well with increasing depth. .

Figure 120 Raypath and reflection point locus plot It is quite easy to infer that for a series of geophone (and/or source) locations a family of reflection point loci can be constructed (figure 6.10). What can one deduce from this information? Firstly, if the velocity profile at the well is known, it is possible to construct a twodimensional velocity field in the vicinity of the well. This can be extrapolated away from the well using dip and other information from drilling or rig source VSP information etc. It is now possible to define to a first approximation the positions occupied by the reflection point loci as noted above. One can then overlay the time-recorded VSP for a particular source-geophone pair on the plot of the locus for that pair. This is not as straightforward as it might appear as one has to preserve the time structure of the trace and this involves the application of a variable "stretch" function to the time trace. This process is analogous to the normal moveout correction (NMO) applied to surface seismic data. Figure 121 illustrates this technique applied to one trace and 147

figure 122 shows the effect of its application to a series of traces where the reflection image begins to be obvious.

Figure 121 Moveout corrected trace


Figure 122 Moveout corrected traces This display can be of great use in that the origin of much of the reflection image can be easily seen and much of the amplitude information for each event is preserved. It is quite difficult, however, to directly compare this display with a standard set of seismic traces. This is solved by using a "binning" algorithm to partition the energy back into a conventional array of seismic traces. This example is based on a horizontally layered model although, as hinted above, the approach can be extended to include structure. This approach is generally referred to as "mapping" or sometimes as the VSP CDP transform. An alternative method is to use standard seismic migration algorithms to image the data. A velocity profile is again needed and again ideally this should be applied taking into account the possible dips expected etc. (A point to bear in mind for both approaches is that the subsurface image produced will depend very much on how the velocity model is used to constrain the data. If structural discontinuities (eg faults) are entered, then they will of necessity "imprint" themselves on the recorded data). The most commonly used migration schemes are based around variations on the Kirchhoff integral, the basic physical operation of which can be easily appreciated. The routines take each sample of each recorded trace and calculate a locus of points from where that sample could have originated using the supplied velocity profile; all points on the calculated locus are then given the value of the sample. The method works because at positions of real reflection points the amplitudes from the loci will be coherent and add constructively. Away from reflection points the contributions from each sample will be random and effectively cancel. A direct corollary to this is that by its very nature contributions from random noise events will also cancel thereby reducing the overall noise content of the subsurface image. The simplest way of applying either the mapping or migration methods is to use a horizontally layered, laterally invariant velocity profile. It is intuitively obvious that this will lead to a degree of inaccuracy in the resultant image although the errors introduced will be smaller for the migration approach. This is because unlike the mapping approach, the model used sets no limits as to the position of the reflection points and hence the image should provide a reasonable estimate of dip assuming a realistic velocity model. With the ray-trace based mapping methods, the position of the reflection point is fixed by the velocity model and this may not correspond to the recorded position of the event within the data. If the subsurface model is known with a degree of certainty, then this information can be incorporated in the model and the accuracy of this approach can be improved. In general the migration approach is to be preferred over ray-trace schemes unless there are amplitude problems within the data (for example strong angle-dependency of reflection coefficients), or the subsurface is very disjointed. In this case there is ample scope for applying mapping schemes in an iterative fashion. The subsurface is first modelled using a ray-trace package, the results of the modelling are then be used to generate a synthetic VSP data set which is compared with the recorded data. The results of the comparison are then used to update the 149

model and the process run again until there is a convergence of the modelled and synthetic results. Examples of the different imaging techniques as applied to a real data set are shown in figure 123. This is derived from a rig source VSP from a deviated well in the North Sea. Four panels are illustrated, the first is the original surface seismic data, the second is the mapped data using a reasonably refined but horizontal subsurface model. The third is of the results using a migration approach but with the same velocity model and the fourth shows the seismic section with the migrated data spliced in along the well location. The migration approach has clearly better imaged the dipping beds near TD of the well and the overall noise level is also much lower. It is also interesting to note that the apparent zone of illumination is much smaller with the migration approach, this indeed is a more accurate description of what to expect from this survey. The cover indicated by the mapped data could be constrained by refining the model further to allow for structural effects, the final result of which would be close in appearance to that from the migration. It is obvious, however, that the migration has not been as severely constrained by the velocity model and can produce a very reliable image with less detailed knowledge of the subsurface.

Figure 123 Migration versus mapping, deviated well rig source VSP

Walkaway VSP surveys The walkaway VSP by its very nature requires the largest departure from the rig source processing route of any configuration mentioned so far. It is instructive to examine the reasons for this and see how the different considerations that have to be made for this survey type affect the handling of the data. Figure 6.14 shows the basic survey configuration; a geophone is secured 150

at depth in the well and the source is fired at a series of positions along a line through the wellhead location. Some of the expected travel paths are shown on this diagram and the shaded area indicates the expected zone of subsurface illumination. Figure 011 shows the ray paths for one shot point and one receiver location with both down and upgoing ray paths annotated. Note that for long source offsets the path lengths for both classes of arrival will be of similar length especially for a deep geophone location.

Figure.124:Subsurface illumination from a Walkaway VSP

Figure 125 Downgoing and upgoing Walkaway wavefields Figure 126 illustrates the events expected from this model from two geophone stations. The top part of the panel illustrates a geophone placed shallow in the subsurface and the bottom part illustrates a deep-placed geophone. Note that as one no longer has a change in geophone location 151

between shots (i.e. the distance between the geophone and a reflecting interface remains constant), both up and downgoing wavefields display the same form of moveout. Both wavefields produce a hyperbolic arrival within the data with the downgoing arrivals displaying more curvature than the upgoing. For a deep geophone the downgoing events occur later than for a shallow geophone, whereas the upgoing events occur at shorter times.

Figure 126 Manifestation of Walkaway wavefields Although the downgoing wavefield displays greater moveout than the upgoing, the degree of moveout is not constant throughout the data. Both wavefields exhibit less moveout toward shorter source offsets; this in turn means that the spatial separation of the alignments of the up and downgoing wavefields decreases toward the centre traces of the panel. It is obvious, therefore, that there is an immediate problem when one comes to isolating the upgoing from the downgoing energy. The normal methods of separation (eg. velocity filters) depend on there being a large apparent difference in velocities between the wavefields; this is no longer the case and if one was to attempt to separate the wavefields from such data, an unacceptable degree of spatial aliasing would occur. The solution to the problem is really very simple and is achieved by recording a series of geophone stations from each source location. If these are now gathered together according to shot point rather than geophone location, it can be seen that each shot has associated with it a conventional albeit limited VSP data set, with the up and downwaves displaying their conventional expected VSP moveout. Each source location can therefore be thought of as providing an independent VSP displaying all the qualities required for effective wavefield separation. The initial stages of walkaway processing therefore involve the sorting of the data from common geophone gathers (CGGs) into the smaller more manageable common shot point (CSP) gathers.


With this in mind, the majority of wavefield manipulation (i.e. separation of up and downgoing, P- and S-wavefields etc.) for walkaway surveys, is accomplished with the data sorted according to CSP gathers. After all such processing has been completed, the data are re-sorted back to CGGs, further processing including imaging etc. then performed in the CGG domain. It is worth noting that although removal of coherent events or wave-mode partition of wavefields is accomplished in the CSP domain, the removal of random noise can be attempted in either CSP or CGG domains with equal success. Equally enhancement of the partitioned upgoing wavefields can be achieved if necessary using conventional velocity filtering techniques within the CSP domain. Alternatively, however, as there are several independent estimates of the upgoing wavefield (one available from each CGG), it is possible to image all the available data from each CGG separately. One can then improve data quality by stacking these images; this method is in fact the closest one can get in VSP processing to producing multi-fold cover in the true surface seismic sense. The modifications to the standard VSP processing route noted above, would appear at first sight to be almost trivial, after all almost all are concerned with simple data manipulation rather than processing. The main limitations with this type of survey occur when one considers the imaging of the data. A moment's thought indicates that although the mechanics behind the imaging process are relatively simple their application in practice is far more complex. Either method of imaging can be performed on walkaway data. In some locations, however, where there is marked angle dependency of reflection strength, the migration approach can provide unpredictable results due to the wide variation in reflection angle seen between the near and far offset traces. An important consideration is the velocity/acoustic impedance field used to image the data. Due to the variability of the travel paths, anisotropy and lateral velocity variations, no two shot pointgeophone pairs experience the same velocity field; this is, of course, true for every VSP survey although the effect is more pronounced with the walkaway. A static offset VSP can be designed, for example, such that the difference between propagation histories is far less problematic. In a sense the walkaway VSP is nothing more than a special case of the offset source VSP survey. Whilst there are practical considerations to be made, from a processing viewpoint, that are different to those required by static offset source data, the image presented to the oil company interpreter has the same properties as one from a static offset source. Where the walkaway really scores over the standard offset source VSP is in the acquisition stage.

3D-VSP Surveys In many ways the 3D VSP is simply an extension of the walkaway VSP survey. It is obvious that with the high cost of rigs and drilling operations, the 3D VSP must be performed in the shortest possible time in order to maximise any economic advantage that might be hoped to be achieved from running such a survey. The question of why one would wish to perform a 3D VSP survey must be asked. It has already been intimated that the VSP is a tool that can obtain images from the subsurface from regions not illuminated by surface seismic surveys; in addition there is the benefit, always encountered with VSP surveys that the seismic energy has suffered less modification by the earth due to its reduced travel path length. These two factors, when combined, allow the operator to plan surveys to provide a true 3D solution from the borehole derived dataset whilst being able to avoid some of the pitfalls (for example by undershooting velocity anomalies etc.) associated with surface datasets. The 3D VSP only becomes viable, however, if sufficient data can be acquired to provide adequate statistics for the various processes to be applied. This obviously would not be a problem if time and money were unlimited, if this were the case any downhole receiver tool could be used to 153

(eventually) record all the data required. This is patently not the case in the majority of well scenarios. The only manner in which this type of survey can be economically recorded, is by using a downhole receiver array thereby reducing the number of traverses of the source. Ideally data should be recorded with as few variations in survey parameters as possible. For example, it is physically impossible in the offshore case to exactly re-occupy a source position, this means that for different placements of the downhole receiver for successive passes of the source boat, there may be considerable differences in the source conditions and the associated recorded travel time. Whereas it is possible to account for much of the variation during processing, it is time consuming and not always successful. The direct consequence of this is that image quality is compromised. The obvious solution is to acquire as much data as physically possible with the same source conditions i.e. to use a downhole receiver array. As noted above the greater the number of geophone stations recorded, the better the results should be. It follows, therefore, that the best results would be obtained by the array that provides the greatest number of array stations, ideally allowing the survey to be recorded in a single pass of the source. As a rule of thumb it has always been considered that the minimum number of geophone stations required for adequate processing is at least seven and preferably nine (odd numbers are required if median filters are to be used in the processing route), it is clear, therefore, that the ideal 3D VSP geophone array should possess at least this number of geophone stations if one is contemplating such a survey. Another important consideration for both 3D VSP and 2D walkaway surveys is that of aliasing. Temporal aliasing can in most cases be discounted in that all available field systems are capable of providing a sufficiently time-sampled dataset to make such effects inconsequential. The effects of spatial aliasing, however, can be considerable and should be avoided if at all possible. The most deleterious effect is produced by the spatial separation of elements of the receiver array.

Note 5 m spacing gives 25 to 180 Hz 15 m spacing gives 8.3 to 60 Hz It is clear from the foregoing that probably the most convenient general purpose separation is around 10 m and that any large receiver array tool if optimised for 2D/3D walkaway surveys should ideally possess this spacing. 154

Shooting Patterns In theory, it makes little difference as to the shooting pattern adopted for recording 3D VSP surveys. There are very few of the shooting limitations encountered in surface seismic data in that there is only one receiver location to be considered. In practice, however, there may be distinct advantages to using a specific shooting programmers (figure.127)

Figure 127 3D VSP shooting patterns Consider figure 127; the simplest options a and b, are ideally suited to a “low tech” shooting vessel where a single source is towed behind the boat and a regular rectangular grid of shot points recorded. Option c is similar but uses two sources positioned either side of the boat for “flipflop” shooting, recording two lines for each pass of the boat. Item d is the idealised “spiral” shoot providing the same shooting grid as a or b, this is obviously not a viable scenario and any such circular/spiral shoot will be performed either as options e or f. In e the shoot is performed in concentric circles with a radial shooting pattern, this manner of shooting can provide a simple method of extracting 2D sections through the receiver location although does require a varying shot point interval thereby complicating the shooting of the survey. Option f is easier to shoot in that pops are taken at a constant separation around the spiral. The shooting pattern adopted depends very much on the requirements of the survey and the capabilities of the shooting vessel and her crew.

4D-VSP Surveys An extension to the 3D VSP survey, uses the data recorded in such an operation to monitor the development of the reservoir over time. This so-called 4D survey (time being the 4th dimension) requires complete repeat shooting of the 3D VSP survey. As the differences between repeat surveys are likely to be small, the source and receiver positions should ideally be precisely reoccupied in order to remove as many degrees of freedom as possible from the operation. This from the source viewpoint is not possible to achieve in practice with the current levels of technology, receiver array positioning is a far more precise activity but even here it is possible to introduce errors. It is important, therefore, to have an independent reference for the survey (in the form of a seismic marker above the reservoir) that is unlikely to be affected by changes in reservoir characteristics. If this is possible, the precise re-positioning becomes less important in that the processing applied to the data can be performed using the reference horizon as a control.Standard processing of the survey to provide subsurface images can therefore proceed using data that are recorded with less than perfect repeatability. The knowledge of the 155

actual positions is still of paramount importance, however, in order to produce the most accurate image during each survey. Where the requirement for complete accuracy of re-occupation of positions is essential, is if there is a necessity for precise analysis of data using the same travel paths (for example performing repeated AVO analyses of specific reflection points). Whether this latter type of processing is even feasible, however, is as yet uncertain. A 4D VSP may be used on its own as a valid tool for monitoring a reservoir, however it is more likely to be used in conjunction with repeat 3D surface seismic operations. The main drawback to the 4D approach using the VSP alone, is that there is a limited amount of subsurface illumination available from such a configuration. Surface seismic on the other hand is more difficult to calibrate than the VSP. The marriage of the two technologies has the potential of providing the most accurate approach to large scale seismic reservoir monitoring by using the VSP surveys as the calibration control for the surface seismic data.

Interpretation of rig-source VSPs So far only horizontally layered, laterally continuous reflecting horizons have been considered. The real earth rarely, if ever, exhibits these characteristics, how then do departures from this ideal situation manifest themselves within the VSP data? The following sections are concerned with the identification of dipping reflectors and diffraction phenomena within a standard VSP data set and illustrate how useful information can be derived. After this, other aspects of VSP interpretation are considered and the section concludes with example interpretation exercises.

Dipping reflectors and diffractions Figure 5.1 illustrates a simple dipping reflector with the ray propagation paths associated with four geophone stations. The dipping reflector intersects the well at geophone station G1, at which point a horizontal reflector also cuts the well. Ray path plots are not shown for the horizontal reflector in the interests of clarity. It can be seen quite easily that as the geophone moves further away from the dipping reflector, the reflection point associated with the respective ray path migrates up-dip from the well. The limit is reached when both source and detector are positioned at the surface, and the ray path in this case is normally incident at the reflector. At geophone station G1, the reflected and direct arrivals for both reflector geometries are coincident in time and depth. The right hand panel of this figure, shows the manner in which these arrivals will manifest themselves within the two-way time VSP image. The horizontal reflector appears - not surprisingly - horizontal and cuts the first arrival curve at a depth corresponding to G1. The dipping reflector on the other hand, although cutting the first arrival curve at the same location, displays a hyperbolic moveout pattern toward shorter reflection times for shallower geophone locations. The amount of moveout relative to the distance moved by the geophone, allows the degree of dip to be calculated. If the dipping reflector terminates or turns over up-dip from the well, before the normal incidence point is reached, then the event in the VSP will also terminate. Reflection energy from the horizontal reflector will originate from close to the borehole and will provide no information concerning the reflector away from the well.


A point to note here is that although the degree of dip can be calculated, with the source positioned at the wellhead, there is no way of determining dip azimuth. This is easily demonstrated if one considers the case of dip in the opposite direction to that in figure 5.1; the ray paths associated with this will be a mirror image of those shown in the figure and the time response will therefore be identical. The computation of the angle of dip is very straightforward, but involves making two assumptions: (1) The dipping reflector is a planar, uniform surface. (2) The velocity of the material above the reflector can be regarded as constant. The first assumption is reasonably secure in regions of "well behaved" structure, and does not significantly affect the accuracy of the calculations. The second assumption may not be as reliable particularly in regions where there may be significant velocity changes in the near surface. If the dips are generally below 30 degrees, however, the errors introduced are again minimal; the basic consideration here is that the reflection points remain reasonably close to the well location. Even in areas of great structural variation and high dip, accurate calculations can be performed if geophone stations close to the reflector are chosen for the calculations.

Figure 128 Dipping reflectors in the VSP Having considered the manifestation of dipping and diffraction events in the VSP, how then does a fault appear within the data set? For this illustration (figure 5.6), a vertical component geophone has been assumed, which means that the diffraction seen will consist of S-wave energy. Additionally, the event diagram has been displayed at two-way time as this is the most likely coordinate system to be encountered by the interpreter. The most obvious feature, is that the diffraction associated with the fault boundaries, do not coincide with the terminations of the reflector within the data. This is a fact that is overlooked by many interpreters and can lead to erroneous conclusions. Another point to note, which is not easy to illustrate on such a diagram, is that the reflection events do not terminate suddenly. As one approaches the discontinuity, the fresnel zone for the reflection point (the area from which contributions to the reflection originate), effectively decreases in size due to the termination. What one sees in the VSP therefore, is that there is a slight ambiguity of perhaps one or two traces as to the exact position of the termination. Although this illustration is how one would expect the fault to appear in the ideal situation, the real world does not fulfil this requirement. In practice, therefore, one would normally see the reflection event but in general little diffraction energy would be visible, particularly if the socalled diffraction point was not sharply defined.


Figure 129 Fault in VSP

Identification and origin of primary reflections Primary events are easily identified in a VSP data set by the simple fact that they intersect the time-depth curve. If the primary has been generated by a horizontal reflector, then it should appear as a horizontal event across the VSP display aligned at two-way time. Such an event may lose continuity into the body of the data due to multiple interference and possible worsening signal to noise ratio. This is caused by the longer propagation paths associated with shallower geophone plants. Deconvolution will generally improve the continuity of these events by removing the multiple activity. If the horizon is dipping then, as noted in section 5.1, the event will appear with moveout into the body of the data. The identification of the event as a primary and the determination of its lithologic origin is still secure, however, providing it cuts the time depth curve. Figure 130 illustrates VSP upgoing events at two-way time generated by horizontal or near horizontal reflectors at the borehole. it is clear that the upgoing primary events intersect the timedepth curve which is marked on the display, the depth at which the reflection originates is confirmed by the calibrated velocity log to the left of the figure. As displayed the data has not yet been deconvolved and therefore contains multiple activity and additionally the wavelet contains source components. It is unclear therefore as to the exact relationship between the seismic events and the lithological changes. This is alleviated by deconvolution and figure 131 shows the same comparison but this time using the deconvolved upgoing data. The resident wavelet of this data is now zero phase, the centre of the wavelet for any event occurring at the exact time of that event. At SEG Normal polarity as displayed, an upgoing compressional arrival appears as a white trough, the centre of which identifies the position of the reflector. Once the phase of the wavelet is known, a precise correlation can be determined as the VSP and calibrated velocity log are tied to the same time measurements. The lithologic significance of any primary event can, therefore, be assessed


Figure 130 VSP upgoing wavefield, at two-way time alignment, with velocity log

Figure 131 VSP deconvolved upgoing wavefield, at two-way time alignment, with velocity log


Identification and origin of multiple reflections it was noted that upgoing multiples terminate within the body of the VSP as the geophone moves below the last reflector in the multiple path. The downgoing wavefield contains information with regard to multiple patterns generated above the geophone. Interbed multiples will be added to the downgoing wavefield as the geophone moves below the first primary involved in the interbed generation. The downgoing wavefield, observed at any point, will appear in the upgoing wavefield as the tail of a reflection at the same point. Finally after deconvolution, the data will provide a display from which the reverberants will have been removed. One therefore, has three separate but interconnected means of identifying multiple activity and determining its origin, the three approaches should be used together for a complete analysis of primary-multiple relationships and their lithologic origin. If one examines the model, shifting the event diagram to two-way time (figure 132), provides one with an indication as to how multiple patterns will appear in the VSP data. Only multiples up to the third order are displayed

Figure 132 Multiples in VSP The main multiple generators in most VSP data sets are associated with the surface, sea-bed or weathered layers and the complete shallow reverberant system is recorded at depth in the well. It is possible to derive information concerning the reflection sequence back to the surface from such data. The downwave can be used, therefore, to analyse the reverberant system of shallow primaries. This means that if the sea-bed or weathering multiples give problems, their position in time, their character and strength can be established by reference to the recorded VSP downwave. For example, if one aligns the appropriate trace from the downgoing wavefield against its counterpart from the upgoing data, such that the first arrival of the downwave coincides with the primary of interest, a visual correlation can be made of the reverberant system associated with that primary. In making this comparison, one must be careful to ensure that the 160

appropriate polarity display is used i.e. white troughs are matched with white troughs. This is simplified if the data used has been signature deconvolved when the resident wavelet has been considerably simplified. In the horizontally layered earth, multiples will appear parallel to the primaries giving rise to them. If there is considerable dip present, although the multiples will still exhibit termination within the data, the events may not appear parallel to the generating primary and their period will therefore not be consistent from trace to trace. The downgoing multiple tail will also exhibit moveout between traces and care should then be taken when designing deconvolution operators from the downwave to be applied to the upwave, as the respective periodicities will not necessarily be the same. One may extend the identification of multiple events away from the VSP to encompass the surface seismic record. The approach is essentially the same, although the choice of comparison trace is slightly different. If the downwave is extremely stable, it is unlikely that any difference would be noticeable between the comparisons of any trace with the surface record. If, on the other hand, there is a variation in the downgoing wavefield with depth, one must ensure that the downwave used is compatible with the data being analysed. To this end, the downwave trace for the level with the same two-way first arrival time as the time of the reflector on the seismic record, should be used. Again the polarity of the downwave first arrival must match that of the reflection event examined; any positive correlation between the tail of the downwave and events beneath the primary then implies residual multiple activity in the surface record.

VSP - seismic comparisons The VSP can be compared to the surface seismic data in two basic ways. Firstly the two data sets can be compared purely from the point of determining a litho-seismic correlation. Secondly they can be compared with the object of determining extra information via the VSP to aid in the interpretation of the prospect. It is an unfortunate fact, that the majority of VSP data sets are still recorded with the sole purpose of making a simplistic comparison between the response of the surface record with data recorded in the well. Although the VSP is a valuable tool in this respect, it does mean that all the other useful information that can be derived is essentially ignored. To satisfy the demand for simple correlation, it is useful to process the VSP such that its appearance matches that of the character of the seismic record. The most obvious parameter to modify to achieve this end is to band limit the VSP to the same frequencies as the surface seismic. This will provide two data sets with ostensibly the same general character but will ignore the potentially much wider bandwidth of the VSP. Another factor to bear in mind is that the wavelet resident in the deconvolved VSP is as near to zero phase as seismic processing can reliably be, without a wavelet shaping operation. The surface record, however, will at best possess a "mixed phase" characteristic and the correlation between a seismic event and a known lithological event can be uncertain. It is possible to alleviate this to a certain extent, by applying a wavelet matching and shaping process to either of the data sets, although as the phase of the VSP is known this should act as the control. In general, however, it is not usually necessary to perform wavelet matching for a straightforward correlation exercise, a sufficiently robust comparison being possible from the standard data. Figures 133 and 134 are the results of filtering the VSP to the same bandwidth as the seismic record. As should be painfully obvious, much of the detail has been lost and hence possible 161

information concerning any thinly bedded strata has been lost. This aside, however, the VSP can now be compared much more easily with the seismic record; figure 135 illustrates such a comparison. The same well data is used as before, but now the degree of similarity between the data sets can be assessed. Moving from left to right on the display the panels are: Acoustic impedance log derived from wireline logs Transposed undeconvolved upgoing VSP wavefield Surface seismic data at the well location Transposed deconvolved upgoing VSP wavefield

Figure 133 Upgoing wavefield


Figure 134 Deconvolved upgoing wavefield


Figure 135 Comparison velocity log/VSP/seismic section (seismic bandwidth) The successive traces of the transposed displays are formed by taking corridors of data from the traces at or about the direct arrival curve from the respective VSP display (see figure 136) this provides a more easily correlated display. The origin of the reflection events can now be easily inferred by reference to the borehole logs, and the respective lithology posted on the surface derived data. 164

Figure 136 Derivation of transposed VSP display. Figure 137, is of a typical display provided by VSP contractors for correlation with surface data. The direct correlations would be achieved using the transposed or corridor displays, the full deconvolved panel would then be used for any detailed interpretation. If the VSP contains considerably more high frequency energy than the surface seismic, then a second version of this display would be produced, with the processing optimised for the data as recorded. This would preserve the information present in the field data and provide the geophysicist with a high resolution data set upon which to base his interpretation. The seismic bandwidth data would then simply form a control data set to guide the initial assessment of the well results. A point to note here, is that the transposed display, although preserving evidence of dip, cannot be used for dip 165

calculations. A practical example of VSP interpretation is presented as a work study with these course notes.

Figure 137 Interpreter's composite display Necessarily conform to the ideals of interpretation as outlined in the preceding sections. The example (figure 138), illustrates that the identification of primary or multiple events is not always as straightforward as may have been implied by the foregoing discussions. This data set was recorded in a vertical hole with a rig source, and for the majority of the well the results of the survey tie very well with the drilling results. The velocity log recorded in the hole is displayed as a function of time to the left of the VSP panel and most of the VSP events can be easily correlated between the two panels. All is well with this comparison until one enters the section of salt from approximately 2.05 seconds. The top of the salt can be identified as the small "white" event at 2.05 seconds (this display is plotted at SEG normal polarity), but as one advances into the salt mass the expected response from the large anhydrite layer at 2.2 seconds, appears to be missing. Additionally there is a large "white-black" event, labelled "A", at 2.1 seconds on the right of the VSP display, which moves to longer times toward the time-depth curve. This appears to have no direct counterpart 166

in the log data and indeed apparently terminates within the panel before reaching the time-depth curve. Using the conventional wisdom outlined in the preceding sections, this event would appear to be a multiple reflection, although it is not immediately obvious as to which primary could give rise to the event. On closer inspection, the event does not actually terminate, but tails off in amplitude toward the first arrival curve just failing to intersect the well location. This, however, still does not answer the question as to where the large anhydrite event on the log has disappeared in the VSP. Looking in even more detail at the VSP display, reveals a further broken "white-black" event which occurs over about 14 traces (labelled "B"), 20 ms beneath the event discussed above. Further still, an extremely weak event at the well location at approximately 2.2 seconds is visible (labelled "C"), which appears to tie the anhyhrite formation. What then can be made of these observations? That event A is dipping, is quite obvious from the time moveout exhibited, and this corresponds to a dip angle of 11 degrees. Event B is also dipping, although in this instance the dip is much higher and equates to an angle of approximately 30 degrees. It is not possible to ascertain to what degree event C is dipping due to its very low amplitude and small lateral extent. From its manifestation in the data, however, it is almost certain that the event exhibits a degree of dip, why one asks should this be the case? The easiest and most likely explanation of the shape of these events, is that the bed cuts the well, but only just, the bed terminating up-dip, extremely close to the well location (event C). The termination is effected by a fault in the bed which decreases the depth of the bed (event B); the bed is then faulted again, raising the event higher and possibly positioning it closer to the well location. In the normal run of events, this scenario would be considered somewhat unlikely to say the least, when one considers the resultant shape of the subsurface model, a representation of which is provided at the bottom of figure 5.16. As the well was drilled through a salt swell, however, this interpretation is quite possible due to the mobility of the salt material. A further point to notice is that there may be a slight problem with the deconvolution applied to this data set. If one looks further into the data, it is possible to see a spatially extensive black event occurring at approximately 2.25 seconds, this exhibits much the same moveout and lateral extent as the anhydrite event, indeed it appears to terminate in much the same manner within the data as the event of interest. It is possible to interpret this event as a multiple from the anhydrite and it is still resident in the data probably due to an incompatibility of propagation paths between the downwave and upwave. Further drilling in a deviated hole near and to the right the location of the subject well, indicates a high degree of support for this interpretation. The anhydrite layer was encountered shallower than in the first well with approximately 10 degrees of dip .It is clear from this example, that one must be careful in areas of complex or unusual structure, not to push the interpretation of a VSP past its useful limits. Inferences from the data may well be made quite easily on the basis of the common-sense application of the simple rules for identifying primary and multiple events, but the complexity of the structure may entail a distinct "bending" of these rules.


Figure 138 VSP interpretation example 1


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