4-Exploration Geophysics Jan 02

8/3/2019 4-Exploration Geophysics Jan 02

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MSc Field & Well Management

Reservoir Geology - Exploration Geophysics

Contents

Introduction 2Books

Geophysical Techniques

Seismic Reflection Surveys and the Petroleum Industry

Seismic Reflection Surveys and an Exploration / Production Programme

The Principle of Seismic Reflection

DataAcquisition 5Seismic Sources and Detectors

Recording and Presentation of Data

Source-Detector Lay-Out5

SeismicWaves 6P-wave

P-WaveletShape 8Pressure Variation Across WavefrontFrequency Content and Bandwidth

What Limits Bandwidth?

P-WaveTransmissionPaths:SingleInterface 9Ray-Paths and Wave-Fronts

Direct and Reflected Waves

The Process of ReflectionSeismicVelocity 11Why is Velocity So Important?

How Is Velocity Defined?

How Is Velocity Measured Or Calculated?

What Controls Velocity?

DataProcessing 13Common Mid-Point Stacking

Multiple Suppression By CMP Stacking

Velocity Analysis

Importance of CMP Stacking

The Complete CMP-Stacked Section: Summary Of Benefits

Other Data Processing Steps

InterpretationOfSeismicDataForStructure 16Interpretation of 2-Dimensional Data

Uncertainty In Seismic Depths

Interpretation of 3-D Data

InterpretationOfSeismicDataForSubsurfaceProperties 19Acoustic Impedance Inversion: Sonic Logs From Seismograms

Direct Hydrocarbon Indicators: Bright Spots, Flat Spots

4-D Seismic

DownholeSeismicTechniques 21Vertical Seismic Profiling (VSP)

Seismic-While-DrillingReferences 22

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BooksAn excellent introductory text is An Introduction to Geophysical Exploration by P. Kearey and M.

Brooks, published by Blackwells (1991)and priced at about 25. It covers all geophysical surveytechniques, but about half the book is devoted to the seismic technique.

GeophysicalTechniquesGeophysical methods of sub-surface investigation are intensively used in both exploration and pro-

duction phases of hydrocarbon development. The main techniques and their fields of application are

summarised below. This course focuses on the seismic reflection technique.

Reconnaissancetechniques :

i Gravity surveys,

i Magnetic surveys

i Seismic refraction surveys

These techniques yield location, extent, depth (to c. 10% accuracy)and age of sedimentary basins and

location of some of the controlling structural features. Wide area covered quickly and cheaply, butresolution of geological detail is low and results imprecise.

Detailingtechniques

i Seismic reflection surveys

Yield precise (2%) thickness of main sedimentary sequences and show bedding and structure down

to a scale of about 10 m. May enable an estimate of lithologies and direct detection of the presenceof oil and gas.

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Introduction


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SeismicReflectionSurveysandthePetroleumIndustry

SeismicReflectionSurveysandanExploration/ProductionProgramme

Literature study

u

Geological field work/sampling

u

2-D seismicsurveyu

First well ("Wildcat")

u

3-D seismicsurveyu

Evaluation/production wells

u

4-D seismicsurveys

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Introduction

Structure (all scales) Subsurface properties

Basin geometry and burial history Sedimentary facies Hydrocarbon detection

Field geometry, traps Porosity calculation Overpressuring

Reservoir geometry

Sedimentary units Fault distribution and compartmentalisation Porosity distribution Hydrocarbon volume


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ThePrincipleofSeismicReflection

The principle is one of echo-sounding. A source of seismic energy (traditionally a dynamite charge)

sends a travelling wave of elastic deformation (a sound impulse) down through the rocks. Whereverthe speed of sound changes at the interface between two different rock types, some of the energy is

reflected back to the surface. The time the energy takes to travel down to the reflector and back

up to the surface at the source position (the Two-Way Time or TWT) is measured. If we know the

velocity at which the sound travels through the rock then we can measure the depth to the reflec-

tor.

The electrical output of the detector is recorded each time and displayed as an oscillogram (a seis-

mogram or seismic trace) which is a graph of signal amplitude plotted against TWT running vertically

down the recording display. If many shots are successively detonated and recorded along a line of

traverse and the seismograms are displayed in sequence on a big sheet of paper, they show shallow

reflections as impulses recorded near the top of the display and deeper reflections as impulses fur-

ther down the display. The reflections can be followed easily across the display so that the whole

resembles a geological cross-section of the subsurface. The horizontal dimension is distance along

the line of survey and the vertical dimension is TWT, approximately proportional to depth. Rock

strata as close together as 10 m or so can be distinguished and the seismic section so produced

resembles a gigantic cliff face several kilometres high and tens of kilometres long showing much of

the detail of the rock stratification (see practical interpretation examples).

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Introduction


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Dataacquisitionis a difficult operation on both land and sea requiring a lot of skill and experienceon the part of operating personnel and so, like much of the technically difficult operations in the oil

business, is placed in the hands of specialist contractors. Firms such as Schlumberger Geco-Prakla,

Western Geophysical, PGS and CGG provide data acquisition and processing services and may pro-

vide specialist interpretation of the results. However most interpretation is handled by the client oilcompanies. Personnel in acquisition and processing largely come from a background in mathematics,

physics or computing science, but interpreters generally come from a geological background.

SeismicSourcesandDetectorsSources and detectors vary according to the field conditions as tabulated below:-

Land Sea

Source dynamite airgunvibrator

Detector geophone hydrophone

RecordingandPresentationofDataAnalogue seismograms are displayed in the field for quality control, but the data is digitized and

recorded in that form for later processing. A typical exploration seismogram may be 6 seconds long

with data sampled at 4 ms intervals, so it is digitised into a string of 1501 numbers.

The time-honoured mode of presentation is a 'wiggle-trace' seismogram with peaks of positive

amplitude shaded black as in Fig. 1, generally described as variable-area recording or VAR for short.

However a seismic section can be treated as just a sheet of numbers and so can be displayed in any

of the innumerable ways of displaying such data e.g. as colour contours, variable shades of grey etc.

The way in which the data is presented can make a big difference in how it is interpreted

Source-DetectorLay-OutThe configuration where the source and detector are at the same location is not very practical,

since the detector is in danger of being either blown up or squashed by the source! In practice the

detectors are laid out in a long line on the ground typically as far as 3-4000 m from the source (or

towed in a long line behind a ship) and the source is activated at one end of the line of detectors.

The data is recorded and then processed later to make it appear as if the source and a single detec-

tor were coincident at the surface location.

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Data Acquisition


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P-wave

The compressional or P-wave is the most important mode of propagation of the seismic disturbance

for petroleum exploration. The 'P' is for Primary, a hang-over from earthquake seismology, since theP-wave travels fastest of all and is always the first disturbance on an earthquake recording. Other

waves are created as well, shear waves and surface waves, but they have only limited application or

nuisance value and will not be considered further.

If a solid rod is struck at one end, the initial P-wave compression is transmitted onwards through

the material at a velocity controlled by the degree of compressibility of the material. If the material

is crudely modelled as a matrix of particles joined by springs, then the initial compression will be

transmitted onwards faster if the the springs are stiff (incompressible) and the particles light (low

density) and so easily moved. The quantity that describes incompressibility is the bulk modulus,

where dp is the change in pressure that causes a change in volume da in an element of volume a.

Strong materials require a large dp to induce a small da so have a high k value.

Hence the velocity of propagation of the P-wave (Vp) must be proportional to k and inversely pro

More detailed physical analysis shows that the exact relation is

for fluids or

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Seismic Waves

=

a

da

dpk

portional to density,

Vp

k

Vp =

p

k

Vp =

+

3

4k


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= shear modulus, a measure of the material's resistance to shear distortion.

Solids are sheared as they are compressed and the resistance to shear is an extra restoring force

tending to spring the material back to shape as the wave passes, so speeding it up.

From all this it is clear that any factor that tends to weaken a rock, making it more compressible or

susceptible to shearing, will reduce the velocity of propagation of the P-wave. It is no surprise that

the rocks with the highest velocity (6000 to 8000 m/s) are the strongest rocks, the crystalline rocks

such as granite or gneiss, in which the mineral grains form an interlocking mosaic of crystals bound

together by strong inter-molecular forces. Sandstones and shales range from near water velocity

(1500 m/s) to about 5000 m/s, depending on age and depth.

Note that velocity is inversely proportional to density in the above equations (for ideal solids), but in

real rocks strength, measured by elastic moduli, varies over a much wider range than density and so

it is strength which controls velocity. In general the stronger rocks are also the denser, so in prac-

tice density is found to rise with velocity. Empirical relationships have been established between

velocity and density of which the best known is Gardner's Law expressed as

= (0.31) V 3.1.1

is in gm/cc and V in m/s.

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Seismic Waves

for solids; here

where


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PressureVariationAcrossWavefrontThe simplest type of P-wave waveform occurs when a particle oscillates once to and fro about its

rest position as the wave passes. You can show by plotting successive positions of the particles that

the material develops a zone of compression followed by a zone of rarefaction followed in turn by asecond zone of compression. These zones travel through the material as time goes on in the

manner.

If the material is water and a hydrophone is measuring the variation in pressure at a point in the

water as time goes by, then the graph of pressure against time is of the shape shown in a rise in

pressure followed by a fall, followed by a second rise. Similar twin-peak waveforms will be recorded

on land by geophones which respond to the velocity of particle motion.

FrequencyContentandBandwidthA wavelet may be made up from the summation of an infinite number of sinusoidal waveforms

covering a range of frequencies (a bandwidth). In deep reflection seismology the bandwidth is

typically 10 to 60 Hz. The frequency of the sinusoids and their relative amplitudes and time shifts

are the factors that determine the shape of the wavelet. The best shape for interpretation purposes

is the symmetrical wavelet, called a zero-phase wavelet. The data are processed to ensure that a

single reflection from one interface has this form. Such a simple reflection is rarely seen because the

recorded seismogram typically consists of many such simple wavelets which overlap and interfere

with one another. An exception is the sea-floor reflection which may well display a simple zero-

phase waveform. An interface between rock units of uniform composition should show a zero phase

wavelet if the processing has been good.

Wavelets of wide bandwidth (wide in frequency) are of short duration (narrow in time). Since we

wish to see the stratification of the sediments in as fine detail as possible, it is clearly of the greatest

importance to retain as wide a bandwidth as possible through all the steps of data acquisition and

processing.

WhatLimitsBandwidth?Real rocks are not perfectly elastic, so as the wavefront passes through the earth the alternate

squeezing and expanding action generates heat through a variety of lossy mechanisms like inter-

granular friction: this heat is lost forever. Since the high-frequency components of the waveform

take the rock through more cycles of oscillation per km than the low-frequency components, the

high frequencies lose more energy than the low frequencies over the same travel path.. It is this

unfortunate fact of physics that determines the ultimate bandwidth of seismic data. Shallow

reflections will have wide bandwidth, up to c. 200 Hz in the first 500 ms of TWT, but below 3000 ms

bandwidth will have dropped to c. 60 Hz.

At the low-frequency end, bandwidth is limited by the nature of the recording device, geophone orhydrophone, which cannot record frequencies below 5-10 Hz.

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P-Wavelet Shape


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Ray-PathsandWave-Fronts Just as in optics, we describe the passage of seismic energy through the ground by using the

concepts of ray-paths and wave-fronts. The wave-front is a snapshot of the position of the elastic

deformation at a particular instant of time after the shot, showing it 'frozen' in time some distancefrom the source. The ray-path is a trace of the path taken through the subsurface by the energy on

a small piece of the wave-front. The ray-path is always at right angles to its associated wave-front.

DirectandReflectedWavesA single horizontal interface is shown between two rock layers of velocity V1 and V2 where V2 = 2V1. Wave-fronts are shown at an instant of time shortly after detonation of the shot at the surface.

The DirectWave (D) travels in the upper layer of rock at velocity V1 and is the first disturbancerecorded by geophones near to the shot. Where it has just struck the interface between the two

rock types and a ReflectedWave (R) is rising off the interface towards the surface. energy has alsopassed through the interface into the lower layer where it has travelled on some way at velocity V 2and forms a RefractedWave (Rf).

Where a recording is shown of a shot fired at the end of a spread of 12 geophones, the

horizontal dimension is one of distance from shot to geophone and the vertical dimension is one of

travel time. The direct wave sweeps across the geophone spread at a steady rate determined by the

velocity of the upper layer, travel time and distance being related simply by the equation:-

The reflected wave sweeps across the near-shot geophones very fast, but then slows as the distance

increases: it forms a characteristic hyperbola described by the equation:-

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P-Wave Transmission Paths: Single Interface

1

x

V

XT =

(Tx)2

= (T0)2+

2

1

2

V

X..5.4.1


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TheProcessofReflectionThe geometry of ray-paths for reflection is determined by Snell's law of reflection which states that

the angles of incidence and reflection of a ray-path on a reflector are equal, a fact familiar to every

snooker player. If the angle of incidence is 0o we are dealing with a normal-incidence reflection

('normal' = 'at right angles to').

The amplitude of a normal-incidence reflection is determined by the contrast in acoustic impedance

V) across the interface. The reflection coefficient of an

interface (R) is a measure of how good the interface is as a reflector and is simply the ratio of

reflected to incident wave amplitude:-

Excellent reflectors have a value of R about 0.3; in an average sand-shale succession values may

range from 0 to about 0.1. If the velocity drops across the interface R is negative and the physical

significance of this is that the wavelet reverses its polarity i.e. if it travels down as the pressure

sequence compression-rarefaction-compression it comes back up as rarefaction-compression-

rarefaction.

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P-Wave Transmission Paths: Single Interface

(product of density and velocity or

R =( )( )

1122

1122

r

i

VV

VV

A

A

+

= .5.4.1


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WhyisVelocitySoImportant?Velocity is a key quantity that we need to look at more closely for at least 4 reasons:

1. You will recall from Section 3 that we measure reflection time and so calculate depth provided we know the velocity at which the P-waves pass through the rock. So if the velocity is V

and the TWT is T, then the depth is (T/2)V.

2. The amplitude of reflections is largely determined by contrasts in velocity.

3. Since velocity depends on the lithology of the rock we can map rock types or physical prop

erties such as porosity across sections by measuring the velocity of the rocks..

4. It is essential to know velocity to correctly process seismic data.

HowIsVelocityDefined?A widely used velocity model is the 'layer-cake' model in which the subsurface is considered to be

built up from layers of uniform velocity. Two different definitions of velocity are used in this context:

1. Interval (layer) velocity (Vi) is the velocity of a particular layer and will depend on the litholo

gy and physical properties of the rock .

2. Average velocity (Va) is the velocity of the subsurface averaged over the whole travel path

from surface to reflector. It is least for the shallow reflectors and gradually increases for

each reflector at greater depths.

3. Stacking velocity (Vs) is the velocity which best stacks the seismic data in the process of

CMP stacking (see section 7.3).

HowIsVelocityMeasuredOrCalculated?Vi may be measured in several different ways:

1. From the down-hole sonic log which records the transit time of a short ultra-sonic pulse

through a vertical metre of rock in the side of the hole

2. From the velocity survey in a well. In this survey the travel time from shots at the surface ismeasured to a geophone down the well. This shows how these times and the known

geophone depths will yield interval velocities. A more detailed set of down-hole velocity

measurements is made in a VSP survey (see section 10.1).

3. From the seismic data itself by a procedure called Velocity Analysis (see Section 7.3).

Va may be measured as follows:

1. From the velocity survey in a well.

2. From the seismic reflection data (see Section 7.3).

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Seismic Velocity


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WhatControlsVelocity?

In a sedimentary rock the main factors controlling seismic velocity are:-

1. Lithology: the mineralogy of the grains is a primary control. In general sandstone and shale

will have lower velocities than limestone, dolomite and anhydrite. However the physical state

of the rock resulting from its burial history and diagenesis is just as important.

2. Porosity is the single most important petrophysical property that determines seismic

velocity. The time-honoured relationship for clean sandstones or limestones is Wyllie's time-

average equation, an empirical relationship linking velocity of the whole rock to the velocity

of pore fluid and matrix:-

= fractional porosity,Vr = velocity of the whole rock,Vfl = velocity of pore fluid and

Vm = velocity of matrix.

3. Pore fluid. Gas in the pores makes the rock more compressible than if a liquid such as water

or oil is present and the velocity of the rock drops by as much as 20%; hence the presence

of gas is directly detectable by seismic surveys (see Section 9.2). Generally the presence ofoil cannot be distinguished from that of water unless the oil is light and gassy, for example, in

the Foinaven Field.

4. Pore fluid pressure. Overpressuring tends to 'blow up' the rock and so weakens it: once

again it will reduce the seismic velocity.

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Seismic Velocity

( )Vm1

VflVr

1

+= 6.4.1

where


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Theseismogram is recorded digitally and stored as a string of numbers on magnetic tape ready forprocessing in the computer. In digital processing arithmetic operations are carried out on the num-

bers to alter the nature of the signal in some way. . The general aim of all signal processing is to

improve the signal/noise ratio (S/N) in the seismogram. Such operations are called applying filters to

the data by analogy with filter paper in chemistry which traps dirt (noise) and allows a clarifiedsolution (signal) to pass through. A simple example is to take the mean of the data within a short

window, perhaps 5 samples long, that runs along the seismogram and output the means as the

modified signal. This process will smooth out rapid fluctuations in the signal that may be judged to

be some form of noise and is analogous to the treble-cut filter that cuts out hissing noises in a hi-fi

audio amplifier. Many of the techniques are common to other fields of signal conditioning, but there

is a particular process called common mid-point (CMP) stacking that is unique to reflection

seismology and yields such great benefits in improving S/N and in providing information on velocity

that we need to look at it more closely.

CommonMid-PointStacking

The general procedure may be illustrated where a ship is shown pulling a hydrophone streamer

along. For the sake of simplicity only 12 hydrophones are shown: in reality 120 might be used. Each

time the ship moves up by one survey interval (typically 25 m) the navigation computer fires a shot.

If we fasten attention on a particular reflection point in the subsurface then the first hydrophone in

the streamer records a reflection seismogram that has travelled along almost a normal-incidence

ray-path down to A and back to the surface. As the streamer moves across and each shot goes off,

successive hydrophones along the streamer record seismograms from A that have travelled along

increasingly oblique ray-paths. Eventually the last hydrophone on the streamer records the lastseismogram that can be recorded from reflection point A, giving 6 seismograms in total, from

odd-numbered hydrophones. Data from the other 6 even-numbered hydrophones refer to a CMP

over reflection point B. This collection of 6 seismic traces, gathered out of all the seis mograms

recorded for a succession of shots, has as its common feature the fixed point on the surface mid

way between source and detector and hence is known as the common mid-point 'gather'.

Note that each seismogram is recorded over successively more oblique and therefore longer, travel

paths as offset increases, so that the reflection wavelet is shifted to progressively greater times. The

amount of extra time is measured relative to the reflection time on the normal-incidence trace andis called the Normal Move-Out (NMO). We can calculate the NMO for each oblique reflection and

shift the traces back in time to bring the reflections all into alignment with the normal incidence

trace. Now the traces can be summed together ('stacked') to form a single enhanced normal-

incidence trace. The aligned signal waveforms will stack up together, but random noise will tend

not to stack coherently, so that the S/N ratio is improved. It turns out that if n traces are

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Data Processing

stacked then S/N improves by a factor of n.


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MultipleSuppressionByCMPStackingOne of the worst forms of noise on seismic records is generated when a good shallow reflection

comes up, hits the ground or sea surface and is thrown back down into the subsurface to be

reflected back up a second time. It would appear on the seismic section as a reflection with twicethe TWT of the shallow primary reflection and so interfere with deep primary relections. CMP

stacking effectively suppresses multiples of this type and that was one of the main reasons for the

widespread adoption of the technique in the 1960's.

VelocityAnalysisFor each reflection there is only one value of velocity that will correct it for NMO and enable signal

stacking to take place. This value of velocity is called the stacking velocity (Vs) and is close to the

average velocity down to the reflector,Va, but is a few % higher. The best value for each reflector

(i.e for each TWT) is found by a process of trial and error at selected CMP locations spacedperhaps every 500 m along the seismic section. Vs values are interpolated between these locations

on to all the other CMPs so that the data may be corrected for NMO and stacked all the way along

the section.

From the Vs values it is possible to calculate interval velocities (Vi) and so average velocities (Va), so

that the complete layer-cake velocity model for the section is determined and available for later

conversion from time to depth. Values of TWT,Vs and Vi are normally printed out on the final

seismic section at the CMP locations where they were obtained (see practical interpretation).

ImportanceofCMPStackingCMP stacking is a make-or-break step in the data processing sequence: in the worst case it would be

possible to choose such velocities as to stack the multiples and destroy the primary reflections!

Picking the wrong velocities can have a startling effect on data quality (see practical example). So

important is this step that it is never left entirely to the contractor. A company representative will

carry out some velocity analyses independently to monitor and maintain data quality in this crucial

step. Moreover the velocities so derived will also be used later in further processing of the data

(migration) and in conversion from time to depth.

TheCompleteCMP-StackedSection:SummaryOfBenefitsThe stacked seismograms are plotted out at their CMP locations on the final section, each one now

being the sum of (typically) 60 original field seismograms recorded about the CMP. The three

principal benefits can be summarised as:

i. Improvement in S/N ratio against random noise.

ii. Suppression of surface multiples.

iii. Measurement of the variation of velocity with time (and depth) in the subsurface.

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Data Processing


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OtherDataProcessingStepsTwo other data processing steps have major impact on the final quality of the seismic section, but

not quite the make-or-break property of stacking, so will only be briefly considered.

Deconvolution is a process which treats short-period multiples or reverberations of the seismic

energy, most notably reverberation between the sea bed and sea-surface in marine data. The aim is

to replace the long, complex wavelet produced by reverberation with a simple zero-phase wavelet.

Seismic work in shallow seas would be impossible without this process.

Migration is the somewhat grandiose term given to the lateral shift that has to be made to the

stacked data if the reflectors are dipping, in order to place them under the correct surface location

and so depict the structure properly. The migration process preserves the entire waveform,

effectively taking it apart in the stacked section and re-building it at its correct location on a new

migrated section. Modern data is always migrated prior to interpretation. However, it is still scaled

in time and part of the work of interpretation is to convert the reflections of interest to true depth

through a knowledge of average velocity.

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Data Processing


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Interpretationof2-DimensionalDataOnly a summary of the steps taken is given here since a practical interpretation exercise is a key

part of the course. The general process is that a few chosen reflections are picked out of the

sections and delineated by coloured lines across each section. Reflection travel times are measured

to each picked reflection and the times are plotted up on a map and contoured as a rough indication

of structure. If a structure looks prospective the time map will converted to depth, a new

depth-structure map prepared and a drilling location identified. At the well location a prognosis will

be given of depths to formation tops from the seismic data and a prognosis of lithologies based on

wells elsewhere in the sedimentary basin and lithological indications from the seismic data.

It is assumed that we are dealing with 2-dimensional seismic data i.e. widely-separated seismic lines

yielding sections with only X,T dimensions. Paper sections or workstation data are treated in a

similar way.

Step1: choose reflectors to pick. The tops of the main formations that have distinctive layervelocities should be picked as that will facilitate conversion from time to depth.

Step2: mark reflectors across sections (with erasable colour pencil) using trace-to-trace continuityand reflection character. Where faults occur the fault plane is marked and the reflection

taken across to the other side by correlating reflection sequence pattern and character.

Reflections can be transferred from one section to another by folding on the line of intersec

tion and direct comparison of reflection sequences, which should be same on both sections

at the point of intersection.

Step3: at suitable intervals measure TWT to the target horizon; transfer the times to the shot-point (SP) base map.

Step4: transfer faults to the SP map, marking downthrow side and indicating approx size of verticaldisplacement.

Step5: connect up faults into a coherent system, bearing in mind what is known about fault trendsand regional geology. A good approach is to stack up 4 or 5 sections that seem to runacross the major fault trend and try to identify which faults have the same style of expres

sion from section to section. It may be possible to identify large master faults that form a

structural framework. The plotted TWT values may also help if they define areas of the tar

get horizon at about the same structural level, which are separated off by faults. However,

this step is the most difficult part of an interpretation of widely-separated seismic lines.

Different interpreters may at this stage produce very different interpretations, which is one

of the reasons for shooting 3-D seismic data (see Section 8.3).

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Interpretation of Seismic Data for Structures


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Step6: draw a contour map of TWT to the target horizon, treating each fault-bounded block as aseparate surface, so contours terminate against faults.

Step7: from velocity analyses, pick off stacking velocities to the target horizon and compare themwith average velocities measured at well locations, if available. Suitably adjust the stacking

velocities to equal average velocities and prepare a contour map of average velocity across

the area. Bearing in mind that average velocity should only vary slowly across an area (unless

there is some obvious cause such as salt ridges) some heavy smoothing of the velocity

contours may be in order.

Step8: at each data point where TWT was measured, interpolate a value of average velocity fromthe map of Va and use that value to calculate depth at the point.

Step9: plot the depths and faults on a new base map and contour the depths in the same way astimes in Step 5.

The structure can now be assessed for area, amount of closure etc. and if all else is favourable in the

area (presence of suitable source, reservoir and sealing rocks) may be drilled to test for the

presence of hydrocarbons.

Workstations enable the work to go ahead much faster because reflections can be computer picked

and timed and the times transferred automatically to a mapping package for contouring. However,

the crucial step of deciding how the faults should be connected still falls to the human interpreter.

UncertaintyInSeismicDepths

Depth is a function of TWT and velocity and of these the biggest source of uncertainty is velocity.

Time can be measured to about 1 ms and at a middling velocity of 3000 m/s that means an error

of 1.5 m in calculated depth. However velocity is generally not known to better than 1%, which

means 40 m in the calculated depth at typical depths of about 4000 m. For the first well in a newprospect, where only seismic-derived velocities are available, it may easily be twice that figure.

However, forecast depths to a deep target should be updated to higher accuracy as the well

progresses and velocity information is progressively acquired through the sedimentary column.

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Interpretationof3-D Data

Three-dimensional seismic data is acquired by shooting seismic lines that are very close together

and processing them so that the final seismograms are located on a surface grid of (typically) 12.5 mspacing. The interpreter may now look at the data along 'in-line' sections, in the direction of original

shooting, or on 'cross-lines' at right angles to the shooting direction, because the seismograms are

just as closely spaced in that direction. Special sections that run from well to well across the survey

area in zig-zag fashion may be interpolated from the data. However the most significant advance in

data presentation is the ability to display horizontal sections through the data set. Short reflections

that may have looked like bursts of noise on vertical sections may then be seen to join up in the

horizontal plane and indicate, say, a meandering river channel system across the survey area.

Interpretation is invariably done on workstations. The main benefits in interpretation for structure

are:

1. There is no uncertainty about following faults from line to line.

2. Velocity control is much more detailed, so depth conversion is much better.

3. Structural control is much more detailed and of similar quality all over the area: one

result is that many more faults are picked and displayed on the final maps.

Hydrocarbon volume calculations are more accurate and uncertainty in general is

reduced.

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Seismicdata is being used more and more to provide information about the subsurface. In generalany numerical attribute of the seismic trace such as amplitude or frequency content may be taken

out of the data and presented as a new seismic section or mapped on a horizon across a 3-D data

volume. Such features may now be the target of a drilling programme. Data quality has to be much

higher than for structural interpretation and the old maxim of "garbage in, garbage out" applies withspecial force.

AcousticImpedanceInversion:SonicLogsFromSeismograms

In section 5.4 it was explained that the amplitude of a reflection was determined by the reflection

coefficient, R, itself a function of the difference in acoustic impedance (AI) above and below the

interface. If we start in a formation of known AI (r1V1) and we know the value of R at the interface

with the formation below (= amplitude of the reflection, suitably scaled to a fraction) then we canturn equation 5.4.1 around to:-

and so calculate the AI of the formation below the interface. This value could be used in turn to

calculate the AI of the next formation down. The calculation may be carried on through a sequence

of reflections, so converting the seismogram to a log of AI. A further step is to convert AI tovelocity (or sonic log transit time) via such empirical relationships as Gardner's Law (equation 3.1.1),

re-written as:-

is in gm/cc and V in m/s. The final sheet of numbers will be values of interval velocity (Vi)

plotted against depth down through the subsurface.

The significance of converting the data in this way is that we pass from a description of interfaces

(reflections) to a description of layers (AI) and it is the properties of layers that we are really

interested in. For example by using equation 6.4.1 we can convert a velocity section so derived

into a porosity section. Seismically derived porosity is now commonly used to control the

interpolation of porosity across a reservoir between measurements made in wells.

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Interpretation of Seismic Data for Subsurface Properties

r2V2 = r1V1( )( )R1

R1

+

V =

8.0

31.0

V

where


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DirectHydrocarbonIndicators:BrightSpots,FlatSpots

The presence of gas reduces the velocity of a rock by about 20% (see section 6.4) and a high-

amplitude reflection (bright spot) is commonly seen over a shallow gas-bearing sand. If the gascolumn is thick enough, a flat spot will be seen, a reflection from the horizontal interface

between gas-saturated and water-saturated rock within the sand. Additional, more subtle, features

may aid the interpreter: the drop in acoustic impedance into the low-velocity gas sand will give a

negative reflection over the top of the bright spot, which may change in polarity down the flanks: the

flat spot itself will be positive. Interpreters look for this type of indication in the high-resolution

seismic surveys that are carried out over planned drilling sites where shallow, over-pressured gas is a

potential drilling hazard.

The mode of data presentation is often important. Positive parts of the waveform are rendered as

red, negative parts as blue and the low-level background reflections are left white or grey. Shallow

gas then shows up as a blue top over a red flat spot. Note how this display also brings out the base

of the sand horizon down the flanks.

4-D Seismic

If the gas/water (or gas/oil) interface in a reservoir can be detected seismically, the possibility arises

of monitoring its position over a period of years by shooting successive 3-D surveys. Since this adds

a sort of time dimension to the seismic technique it goes by the name of '4-D' seismic. An initial 3-D seismic survey of the highest possible quality is made just before production commences and fur-

ther surveys are carried out at intervals that will vary with the size and complexity of the field: per-

haps every 6 months initially. If a clear seismic indication of a fluid interface was seen on the initial

survey (and proved through well control), then it should be possible to monitor the progress of the

interface as the hydrocarbons are flushed out of the reservoir. The best known example of this is

the Oseberg Field (Johnstad et al. 1993), but several companies are now involved in such studies,

even going to the lengths of installing permanent sea-bed hyrophone arrays which can be re-visited

time and again to provide updates of the data.

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Interpretation of Seismic Data for Subsurface Properties


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VerticalSeismicProfiling(VSP)

This technique is a development of the down hole velocity survey (Section 6.3). An array of

geophones (typically 4 or 6 spaced at 20 m) is progressively moved up the hole and a shot fired atthe surface for each new array position. The entire seismogram from each geophone is displayed

(Fig. 20). Downwards- and upwards-travelling energy can be recognised separately so that

reflections recorded at the surface can be unequivocally tied to geological horizons in the

subsurface. By firing a line of shots at the surface across the well location an image of a short

section (or even 3-D volume) of the strata around the well can be obtained, especially useful when

conventional seismic data is obscured by noise, for example because of the presence of gas or salt in

the overlying section.

If a VSP is shot prior to reaching TD the seismic data coming from the undrilled section below can

be converted to a pseudo sonic log as in 9.1 above and a prognosis of lithologies to be encountered

to TD can be made.

The main advantage of the VSP technique is that the travel path through the subsurface is shorter, so

frequency-selective absorption is less and the bandwidth of the data is greater. However it has

operational disadvantages in that it ties up rig time for several hours at the very least and one or

two days in the case of a 3-D VSP. The risk of equipment snagging and breaking off in the hole is

also greater with a multi-geophone array.

Seismic-While-Drilling

The noise made by the drill bit itself can be used as a seismic source. It is recorded on a

conventional seismic spread at the surface over a time of several minutes. The noise signal is very

far from being the ideal short wavelet produced by the classic explosive seismic source, but can be

compressed into a wavelet by data processing, provided a reference signal of the waveform as it

leaves the bit can also be recorded. Such a reference signal is transmitted through the drill string

and recorded over the same period of time at the top of the hole.

As for VSP, travel paths are shorter so bandwidth is greater and resolution better. Drilling prognosis

can be progressively updated as drilling proceeds.

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Downhole Seismic Techniques


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AshcroftW.A.andRidgway,M.S. 1996. Early discordant diagenesis in the Brent Group, MurchisonField, UK North Sea, detected in high values of seismic-derived acoustic impedance. Petroleum

Geoscience, 2,

Johnstad,S.E.,Uden,R.C.andDunlop,K.N.B. 1993. Seismic reservoir monitoring over theOseberg Field. First Break, 11, 177-185.



References

4-Exploration Geophysics Jan 02

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