1. SEISMIC DATA ACQUISITION

It is the first step in seismic prospecting. It includes acquiring raw data from

the field using field instruments and operations. The field instruments used for

acquisition are: a source (dynamite, explosive, shaped charges, vibrosies, air gun,

and thumper), a receiver (geophone, hydrophone, and marsh phone), the dog house

(recording unit, magnetic tapes, on-screen display).

For acquisition a survey has to be planned. This is done using the survey

design techniques. There might be 2D and 3D seismic surveys.

In 2D seismic survey, the source and receiver are placed in a line. There can

be split spread (source in the middle and receiver on either sides) or end on

spread (source on one end and receivers on the other).

In 3D seismic survey, there are a series of receiver and source arrays

covering an area. The source and receiver are orthogonal. For petroleum

exploration purpose, 3D surveys are mainly used.

Figure 1.1.1: Geometry of acquisition.

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Geophone Shot

ReflectedSeismic waves

Layer-2Layer-3

Layer-1

In-line

X-line

2D SEISMIC DATA ACQUISITION

In the 2D data acquisition source and geophone are in line. Acquisition

of data is first and important part of seismic. Any data processing technique

cannot add any frequencies that were not recorded nor enhance information

outside the bandwidth of the seismic data acquired in the field. Hence we

should be careful during acquisition of data. Before acquisition, first we

design field parameter. Inappropriate or poorly designed parameters can

severely limit the quality and utility of the seismic data. Properly designed

parameter, based on the knowledge of the area and the exploration target,

normally lead to greatly enhance and interpretable seismic section.

1.2 Design of field parameters:

The well-designed seismic survey begins with a clear knowledge of

the survey objectives in general terms. Several factors merit consideration in

the design of ultimate field parameters, including economics, time of the

survey, type of energy source type of geophones and their patterns.

Some parameters of a seismic acquisition program are

Maximum offset: distance from the source to most remote

receiver.

Minimum offset: distance from the source to nearest receiver.

Group interval: distance between geophone arrays. Constant for

a survey.

Shot interval: distance between two shots.

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Fold coverage: number of times a subsurface point is surveyed

by different source and detectors.

Sample interval: the time interval between digital samples of

the signal. Varies from less than 1 ms to 4 ms. This sample rate

is chosen not to limit the vertical resolution and to record the

desired maximum frequencies.

Choice of source and geophone arrays.

No. of recording channel.

Direction of shooting.

Before conduct the survey we clearly mark the area of survey with

reference of any fixed structure like pillar, bridges etc. while in offshore we

define co-ordinates by satellite navigation.

LayoutIn reflection seismic survey two type of layout are most commonly used.

1. End-on2. Split spread

1. End-on: In survey we used several no. of channels or geophone group. The

most commonly used is 96 or 120 channels. In end-on shooting, source

is placed on side of geophone array.

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Fig. -1.1.2 End-on shooting

2. Split-spread

In this layout source is placed in between the geophone array. There

are two type of split-spread layout.

(a) Symmetrical Split-spread: in this layout equal geophones are placed on both side of source. This layout is used when depth of interest is shallow.

Fig.1.1.3 Symmetrical split-spread

(b) Asymmetrical split-spread: In this spread different no. of geophones

are placed on both side of source. This spread is used when our depth of

interest is both shallow and deeper.

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Fig. 1.1.4 asymmetrical split spread

3D SEISMIC DATA ACQUISITION

Seismic data are usually collected along lines of traverse that form same

sort of grid and 3-D picture of structure is deduced by interpolating between

the lines. However features seen on such lines may be located off to the side

of the lines rather than underneath the lines and small but important features

(like fault) can occur between the lines. This produce error in interpretation.

3-D surveys are done to obtain data uniformly distributed over an area rather

than long lines; in order to correctly locate the geological features, 3-D

techniques also reduces the spatial noise.

1.3 Acquisition requirementsIn 3-D, we wish to have uniform acquisition conditions and a uniform

surface distribution of CMP’s that (1) data distributing on a uniform grid (2)

same CMP multiplicity (3) utilizing the same mix of offset distances & (4)

same mix of azimuth.3-D seismic data can be acquired in number of ways.

The usual method is to run a series of closely spaced lines, to have

geophones laid out in two or more parallel lines. In other land work,

geophones are laid out on lines at right angles to source lines.

Different Field Parameters and Their Selection

Box

In an orthogonal design the box corresponds to the area encompassed by two

consecutive receiver lines (spaced Ry) and two consecutive source lines

(spaced Sx). Box area is then:

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Sb = Ry *Sx

Directions

Two types of directions have to be considered:

In-line direction: Which is parallel to receiver lines. Sampling in this

direction is generally satisfactory.

Cross-line direction: Which is orthogonal to receiver lines. Sampling in this

direction is generally weak and has to be investigated carefully.

Fig.1.1.5 Source and Receiver line direction

Fold of coverage

The 3-D fold is the number of midpoints that fall into the same bin and that

will be stacked. The nominal fold (or full fold) of a 3D survey is the fold for

the maximum offset. The majority of the bins is filled by the nominal fold.

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Run-in: is the distance necessary to bring the fold from its minimum to its

nominal value in the shooting direction.

Run-out: is the distance necessary to bring the fold from its nominal value

to its minimum in the shooting direction.

Foldage (F)= inline fold (FIN) x cross line fold (FXL)

No of receiver station x receiver station interval in inline direction

Inline fold (FIN) = -----------------------------------------------------------------------------

2 x source station interval in the inline direction

No of receiver line x receiver station interval in cross line

Cross line fold (FXL) = -----------------------------------------------------------------------------

2 x source station interval in the cross line direction

Fig 1.1.6 Inline and cross line fold

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Midpoint

Midpoint is a point located exactly in the middle of the source – receiver

distance. It is not necessarily located along a receiver line as in 2-D. Instead,

midpoints are usually scattered within the survey area. In practice, they

rarely form a regular grid.

Common mid point (CMP):

In an horizontal layered Medium with constant velocity, common mid

point(CMP) is the point located in the middle of different Source-receiver

pairs which reflection corresponds to the same subsurface point. It is

desirable that source-receiver pairs are different in direction and in offsets.

CMP bin:

CMP bin is a square or rectangular area, which contains all midpoints that

correspond to the same CMP. Traces that fall in the same bin are stacked.

Their number corresponds to the fold of the bin.

Bin size:

The bin size corresponds to the length and to the width of the bin. Smallest

bin dimensions are equal to half source point interval and half receiver

interval (Sy/2*Rx/2).

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Fig 1.1.7 Bin size and midpoint

Move-Ups

Two types of move-ups can be considered for 3-D surveys:

In-line move-up: Occurs when the template moves up along the survey

from its initial position after completion of a salvo of shots.

Cross-line move-up: Occurs when the template reaches the edge of the

survey area and moves up across the survey to start a new in-line move-up.

Fig 1.1.8 Inline and cross line move-up

Offsets

Taking into account the configuration of the 3-D template, different offsets

can be defined:

In-line offset: is the distance representing half-length of the template in the

in-line direction.

Cross-line offset: is the distance representing half-length of the template in

the cross-line direction.

Maximum offset (Xmax): is the distance of half-diagonal of the template.

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Maximum Minimum offset (Xmin): is the length of the diagonal of the box

formed by two consecutive receiver lines and two consecutive source lines.

Patch

A patch is an acquisition technique where source lines are not parallel to

receiver lines. If source and receiver lines are orthogonal the spread is called

orthogonal (cross spread). If receiver and source lines are not orthogonal the

spread is called slant spread. The survey area will be covered by the

juxtaposition of patches. Each one represents a unit area obtained by several

template moves. Shot points can be inside the template or outside.

Receiver Line

Receiver line is a line where receivers are located at a regular distance. In

land 3-D surveys receiver lines are kept as straight as possible. In marine 3-

D surveys receiver lines correspond to the towed streamers.

Receiver line interval (Ry): Receiver line interval is the distance between

two consecutive receiver lines. It is also called receiver line spacing.

Receiver interval (Rx): Receiver interval is the distance between two

consecutive receivers located on the same receiver line. It is also called

receiver spacing.

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Fig 1.1.9 Source Line

Receiver density (Rd): Receiver density is the number of receivers per

surface unit, in general square kilometer (sq.km). Number of receiver lines

per kilometer and number of receivers per kilometer determine the receiver

density (Rd).

Roll-Along

Roll-along is the distance of two consecutive positions of the template. It is a

number.

In-line roll-along: Corresponds to the in-line move-up of the template and

represents the distance between two consecutive positions of the template.

The number of columns of receivers left behind the template is equal to the

in-line-roll-along.

Cross-line roll-along: Corresponds to the cross-line move up of the

template and represents the distance between two consecutive positions of

the template .The number of receiver rows left behind the template is equal

to the cross-line-roll-along.

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Fig 1.1.10 Inline and cross line roll-along

Source Line

Source line is a line where source points are located at a regular distance. In

land 3-D surveys source lines can be orthogonal or parallel to receiver lines

or have any other direction (slant). In marine 3-D surveys source lines

correspond to the lines followed by airgun arrays.

Source line interval (Sx): Source line interval is the distance between two

consecutive source lines. It is also called source line spacing.

Source interval (Sy): Source interval is the distance between two

consecutive source points located on the same source line. It is also called

source spacing.

Shot density (Sd): Shot density is the number of shots per surface unit, in

general square kilometer (sq.km). Number of source lines per kilometer and

number of sources per kilometer determine the shot density (Sd).

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Fig 1.1.11 Source line and source line interval

Salvo

A salvo is the number of fired shots before the template moves up along the

survey.

Fig1.1.12 Salvo and Template

Swath

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When the template moves in one direction and reaches the edge of the

survey area, it will generate a swath. Usually the first move occurs in the in-

line direction.

Swath-shooting mode: The swath-shooting mode is an acquisition

technique where source lines are parallel to receiver lines.

Fig 1.1.13 Swath shooting

Template

All active receivers corresponding to one given shot point corresponds to a

template These receivers are located on several parallel lines.

3-D Data Volume

3-D data volume is the result of data processing It is a migrated volume

obtained after sorting the data in CMP bins (binning) and stacking the data.

Data are gathered in (X, Y, Z) coordinates with:

– OX in the in-line direction;

– OY in the cross-line direction;

– OZ in two way time (or depth).

In some surveys different volumes can be generated and separately

interpreted with:

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– Near offsets;

– Mid offsets;

– Far offsets.

Geophysical Parameters

Geophysical parameters of 3-D can be gathered into imaging, edge,

geometrical and recording parameters. All of them have an impact on the 3D

data quality. However some of them have a great impact on the cost of the

survey and have to be adjusted carefully. They correspond mainly to the

imaging parameters and are related to fold of coverage, bin size and

migration aperture. They are thus related to sampling and aliasing criteria,

to resolution and signal enhancement and to migration efficiency: Edge

parameters include in-line and cross-line tapers. Geometrical parameters

correspond to offsets and source and receiver lay outs. Recording parameters

are related to recording length and sampling rate.

Imaging Parameters

Fold of Coverage

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The fold of coverage of a 3-D seismic survey represents the number of

traces that are located within a bin and that will be summed. Minimum bin

dimensions correspond to half the source interval and half the receiver

interval. Each trace is generated in the middle of a source-receiver pair.

Source-receiver pairs have different directions. Traces within the bin thus

have a range of azimuths and offsets but they correspond to the same

subsurface location (Fig.1.16).

When summed all traces carry the same signal, which is enhanced as it is in

phase. However all traces have different random noise which is out of phase.

The summation process decreases the level of noise. Then the fold

contributes greatly to the enhancement of the signal to noise (S/N) ratio.

After stacking each bin contains one single trace, whose S/N ratio is

multiplied by √F (F being the fold).

Bin Size:

The bin size will affect the lateral resolution of the survey and its frequency

content.

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Resolution and bin size:

Resolution is defined as the ability of a seismic method to distinguish two

events of the subsurface that are close to each other. Lateral resolution (also

called horizontal resolution) corresponds to the direction parallel to the

seismic measurement plane. It is related to the Fresnel zone. The Fresnel

zone is defined as the subsurface area, which reflects energy that arrives at

the earth’s surface within a time delay equal to half the dominant period

(T/2). In this case ray paths of reflected waves differ by less than half a

wavelength. Commonly accepted value is one-fourth the signal wavelength

(/4). Then a recorded reflection at the surface is not coming from a

subsurface point, but from a disk shape area, which dimension is equal to the

Fresnel zone. The radius of the Fresnel zone is given by:

Rf = (V/2)(t0/fdom)1/2……………………………………(1)

This shows that high frequencies give better resolution than low frequencies

and resolution deteriorates with depth and with increasing velocities.

Migration technique drastically improves resolution

The 3-D migration is a major factor that drastically improves the 3-D

imaging compared with 2-D data as the energy is by far better focused. In

3-D processing, out of the plane events are restored to their correct

subsurface location and become additional energy. As a matter of fact the

migration can be considered as a downward continuation of receivers from

the surface to the

reflector making the Fresnel zone smaller and smaller. The3-D migration

will shorten the radius of the Fresnel zone in all directions improving

drastically the resolution. Bin size must be equal to the lateral resolution

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after migration. This value is equal to half the dominant wavelength dom

associated with the dominant frequency fdom

Bin size = 1/2dom ……………………………………(2)

Spatial sampling and bin size:

Spatial sampling is a common operation in seismic acquisition. The recorded

samples must allow the reconstruction of the original signal without

ambiguity. A proper sampling is given by Nyquist condition (or Shannon

theorem), which states that two samples per period are minimum to

reconstruct a discrete signal. Then sampling interval is:

t ≤T/2 or t ≤1/2 fmax

According to Gijs Vermeer, in the (f, k) plane there is a maximum wave

number kmax such that the energy is nil for frequency superior to fmax and

there is a minimum velocity Vmin .The spatial sampling for shots and

receivers is thus:

x(r,s) ≤Vmin / 2fmax ……………………………………(3)

Whereas the spatial sampling in the midpoint domain is:

xm ≤Vmin / 4fmax ……………………………………...(4)

For dipping events (with dip ), the above formulae become:

x(r,s) ≤Vmin / 2fmax sin…………………………………..(5)

xm ≤Vmin / 4fmax sin……………………………………(6)

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These formulae give the maximum-recorded frequency and wave numbers

and no alias occurs.

However, if Vmin is very small or Fmax is very high the above formulae lead

to very small x, which is very difficult to implement. Then it is common in

acquisition to accept some kind of signal that is aliased such as ground roll

with low velocity or noise with high frequency.

Diffractions and bin size

Diffractions are useful for migration and should be sampled correctly. The

sampling formula is (Liner and Underwood, 1999):

x ≤Vrms / 4fmax sin………………………………………..(7)

Where is the take-off angle from the diffraction point. It is considered

that if the take-off angle is equal to 30° the corresponding wave front carries

95% of the diffracted energy. Then the above formula gives an antialias

sampling value equal to:

X ≤ Vrms / 2fmax ………………………………………...(8)

Practical rules

In summary, bin size must be selected as the minimum value of the

following three formulae:

Bin size = 1/2 dom

x(r,s) ≤Vmin / 2fmax sin

x ≤Vrms / 2fmax

In addition the sampling paradox must be considered either by square

sampling in shots and receivers or by implementing additional shots or by

two dimensional interpolation procedure.

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Migration Aperture

Migration aperture is defined as a fringe that must be added around the

subsurface target area in order to correctly migrate dipping events and

correctly focus diffracted energy located at the edge of the target area.

Migration aperture is then related to the two aspects of migration techniques:

moving dipping events to their true subsurface locations and collapsing

diffractions. The external limit of the migration aperture corresponds to the

full fold area.

Migration aperture and migration displacements Migration restores the

dipping reflector to its true position with three effects: shortening the

reflector, increasing reflector dip and moving reflector in the up-dip

direction with horizontal and vertical displacement. Horizontal and vertical

displacements are given by the following formulae (Chun and Jacewitz,

1981)

Dh = (V2 *t * tan s)/4…………………………………. (9)

s being the dip angle on the time section:

Dv = t{ 1 - [1 – (V2* tan2s)/4]1/2} ……………………………(10)

tan s = Dv/ Dh

The migrated angle m is given by:

tanm = tans / [1 – (V2 * tan2s)/4]1/2 …………………………(11)

Migration aperture and diffractions

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The following considerations discussed in 2D are also available in 3D.

Diffractions are generated by subsurface features whose dimensions are

smaller than the incident seismic signal such as pinch-out, erosional surface,

abrupt lithology changes, reefs, flanks of salt dome, faults, etc. In the (x, z)

plane each discontinuity will generate a circular diffracted wavefront which

will be recorded at the surface at different offsets x1, x2,…xn at times t1,t2,…

tn. In the (x, z) plane, couples (x1, t1), (x2,t2), etc. give a diffraction hyperbola

in the stacked data. The apex of this hyperbola indicates the diffraction point

and its equation is:

t = 2 (z2 + x2) 1/2 /Vrms

In theory the hyperbola extends to infinite time and distance. However in

practice, for the migration, the diffraction hyperbola will be truncated to a

spatial extent within which the migration process will collapse the energy to

the apex of the hyperbola. This extent is called migration aperture and its

width determines the accuracy of the migration. It is accepted to limit the

extension of the hyperbola to 95% of the seismic migration energy. This

corresponds to a take-off angle from the apex of 30° as shown in

Figure1.21a. Figure 1.21b gives the value of the migration aperture as:

Ma = z * tan

With minimum equal to 30°, this gives:

Ma = z * tan30° = 0.577 * z

Ma ≈0.6 * z = 0.6 * (Vt0 / 2) …………………………….(14)

Where V is the average velocity and t0 is the zero-offset time. In case of

dipping event the migration aperture is:

Ma = z * tan

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It then follows that:

Ma = (Vt0 / 2) * tan…………………………………. (15)

Where is the maximum geological dip.

Migration aperture and migration algorithms: The migration algorithms

give another limitation of the migration aperture. These algorithms, in

general, take into account dips of 45 to 60 degrees and too steep dips are not

well imaged after migration. Dips can then be limited to these values.

Migration aperture and velocity: (Yilmaz, 1987) Shows that migration

aperture increases with

Velocity as indicated in the above formulae and the deeper the geological

targets the higher the migration aperture.

Practical rules:

Migration aperture will be: Ma ≈0.6 * z = 0.6 * (Vt0 / 2)

if the maximum geological dip is less than 30°. If this angle is higher than

30° the migration aperture will be Ma = z * tan= (Vt0 / 2) * tan

In addition the maximum dip can be limited by the dip limit of migration

algorithms.

ADVANTAGES OF 3-D SURVEY:

1. Azimuth Information is available.

2. Detailed delineation of subsurface formations and thus visualizing them in

3Dimension.

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2. Survey Planning

Pre-Survey Planning

At the time of prospect identification, seismic data could be only

available to the geoscientist in the life cycle of an exploratory initiative in an

area. Seismic data acquisition endeavors require for formalization of a

systematic work plan.

1. Physical planning

Physical planning aspects of the seismic survey operation are initiated

as soon as the plan is received from geological department in regards to the

area to be covered with 3D seismic surveys, generally, three-four months

ahead of the actual recording operations.

2. Technical planning

a. Reconnaissance Survey

For efficient planning & execution of seismic survey operation in the

area detailed reconnaissance survey was carried out. The primary objective

was to identify the physical and topographical features in the area of

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operation. The physical aspects such as road networks, access constraints,

and other features such as Oil and gas pipelines, factories, etc. falling in the

block were identified. The topographical aspect such as rivers left over

remnant river channels, oxbow lakes, lowlands, forest, cultivation, tea-

gardens etc. were identified and the same were documented. The

information so gathered would provide immense aid in planning and

designing of seismic survey.

b. Establishing a Grid of GPS Points

Satellite based positioning system is used for fixing the reference

benchmarks in the area of operation. These reference benchmarks fixed with

the GPS system enable for better control and precise spatial positioning

requirement in the area of operation during the course of control traversing

in the area and final implantation work for staking out the position of source

and receiver on the surface as per the predetermined theoretical grid.

c. Acquisition Geometry and Parameters

Standard procedures were followed to decide on the various

acquisition parameters. We approached to selection of acquisition

parameters for 3D seismic surveys as a two-step.

Pre-survey Design ( Preliminary Inputs )

Detailed Design (finalizing the acquisition geometry and

parameters)

Pre-survey design primarily involves gathering of various available

information viz. exploration objectives, review of existing geo-scientific

data, socio-cultural data from the operational area including logistics and so

on. The information was analyzed to broadly estimate the geophysical

requirements of the survey consistent with the exploration objectives, as also

the financial implications of implementing the survey. The pre-survey

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design sets the constraints in terms of fold, offset & azimuth distribution, bin

size etc i.e. sets the preliminary inputs to the survey designing.

A large number of geometries are simulated based on the technical

requirement as observed in the pre-survey design which serves as the input

to the second step i.e. detailed design. The detailed design process

incorporates the choice of critical acquisition parameters such as shooting

pattern, spacing of shots, shot-lines receivers and receiver-lines as well as

the inline and cross line spread length that are consistent with the broad

technical requirement as observed during the pre-survey design process.

Field Operation

1. Survey

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APPROACH TO SELECT THE ACQUISITION PARAMETERS

GEOPHYSICAL / GEOLOGICAL OBJECTIVE

REVIEW OF AVAILABLE GEOSCIENTIFIC DATA

DECIDING THE PRILIMINARY INPUTS

SURVEY DESIGNING

IT MEETS THE REQUIREMENTS? NO YES

FINALIZE THE GEOMETRY

Surveying is the science and art of making the measurement necessary

to determine the relative position of points above, on or beneath the surface

of the earth, or to establish such points. The surveying work consists of

primarily making such measurements and can be divided into three parts-

Field work, computing and mapping.

In seismic surveys the main objective of the survey work is to

mark/fix and provide the precise position of sources and sensors to be laid

out on the ground prior to commencement of recording operations. In order

to achieve the desired level of precision in geophysical positioning the

surveying work was divided into three steps.

DGPS Survey

Control Point Survey

Implantation Survey.

a. DGPS Survey

DGPS is a differential mode of operation of GPS and involves in the

measurement of the relative position of the unknown point (rover) with

respect to a known point (reference or Master). The technique is extensively

used in the exploration industry for precise positioning of the sources and

receivers in almost all seismic survey endeavors.

The study area was adjacent to Moran, Thowara, Borbil-Diroi and

Dipling 3D block which have been already covered by 3D seismic survey.

The satellite point fixed in the adjacent block viz. Borbil-Diroi were used as

Master Control points.

Practice Adopted for fixing DGPS Points

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There are certain standard practices that were followed during the

course of GPS observations to avoid operational errors and ensure precision

for further computations.

DGPS surveyed points were distributed uniformly in the block to have

better quality control of the surveyed grid during the course of control

and implantation survey.

An observation site was selected, where 15o degree clearance from

horizon to sky was available.

Observation site was chosen to avoid High Tension lines and radio

signal transmitter station.

Battery status and memory card status checked initially before going to

field.

Proper centering and leveling of receivers at the master and rover point

was ensured.

Since reference station is set up at a point of known coordinates, the

coordinates of this reference point were entered carefully before starting

the observations.

Receiver antenna height were measured accurately and documented on

the DGPS sketch sheet provided to the surveyor.

The time of observation was fixed based on the base line length and

was always kept more than the required specifications to avoid

repetition of observation at the same point.

A person was engaged at each receiver station site to make sure that

receivers should not be disturbed during the course of field observation.

The field data was processed to resolve the ambiguity with GDOP value

less than 5 as against a minimum of 8 specified in the SKI-PRO

manual. Lower GDP values helps in providing more accurate solutions.

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b. Control Point Survey

Control points surveys were carried out along village roads and approaches

in tea gardens etc. using Total Stations. Utmost care was taken to avoid

operational errors during the course of traversing for minimizing the error in

computed coordinates of control points. The traverses of the Total Station

were tied up with the bench mark points obtained by the DGPS survey.

Triangulation methods were applied to verify the coordinates of the control

points with respect to bench mark points.

Practices Adopted in Control Point (CP) Surveying

Survey was always started from two known DGPS positioned points

and tied to the other two or same DGPS positioned points.

After a CP was confirmed, its position was marked by fixing wooden

peg engraved deep into the ground and the identification number of the

control point written on it.

The visibility of two consecutive CP was required for their subsequent

use during the line opening and line tying. Site selection in the above

backdrop was always done carefully so as to avoid any problem during

the course of implantation survey work.

The control traverses were choosen and run carefully so that no trace

line or shot point line is more than a maximum of two and a half

kilometers away from for better control.

Detailed line sketches of the topographic and other features were

prepared during the course of control survey.

c. Implantation Survey

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The purpose of implantation survey was to mark and implant the survey

lines on the ground as per the planned grid using Electronics Total Stations.

Pickets painted with red color and white color on top were fixed on the

ground for the identification of trace point and shot point respectively.

Corresponding trace no. and shot point no. were written on it with black

marker. Shot points were marked with a circle on the ground whereas trace

point marked with cross mark.

Practices Adopted in Implantation Survey

Implantation survey was always started from a pair of control points or

established DGPS points available nearest to the line to be surveyed.

The staked out points were tied to the nearest control points or DGPS

points available.

Detailed line sketches of the topographic and other features were

prepared during the course of implantation survey along each line.

The source and receiver points were staked out on the ground and the

line was closed with respect to the known points. The data was

subsequently processed to identify the quality of the survey and if it

was found to be within tolerances it was accepted or otherwise the line

was resurveyed.

The difference between theoretical coordinates and field coordinates

were checked on a daily basis.

All out precautions were taken to avoid operational errors due to wrong

input of co-ordinates, incorrect centering and leveling of the equipment

including measurement of height etc.

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2. Recording Operation

Successful implementation of the survey design during the recording phase

is the key to the acquiring seismic data with good geophysical attributes as

envisaged during the design process. For efficient implementation of the

survey design the jobs, roles and responsibilities of recording crew were

divided into the following three groups.

Layout of the Acquisition Spread & Monitoring

Drilling & monitoring of shot- hole

Loading and blasting of Shot-holes

a. Layout of the Acquisition Spread & Monitoring

The primary role of the line supervisor was to ensure proper physical

connection between the Station Units (S.U.) and proper plantation of

geophones at their staked out positions. For this purpose each acquisition

line, divided into three parts viz. Low, Middle & High, was manned by three

company supervisors and three contractor supervisors. Besides ensuring the

correct position and proper physical connection their job included

replacement of any faulty cables, geophones or SU’s, PSU’s during the

course of line checking as communicated by the observer.

Besides the physical checking of layout of acquisition spread, the quality

of acquisition spread was controlled through the online monitoring of spread

on the instrument. The main role of the observer was to check the line status

through trouble shooting, to record & maintained the quality of data and to

make proper communication with crewmembers.

b. Shot hole Drilling

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Since the area of the acquisition spread in 3D seismic survey on any

day is much- much larger than a conventional 2D spread, efficient control

and management needs to be exercised for proper location and drilling of

shot holes including their depths.

Three nos.of company drilling supervisor were entrusted the responsibility

to monitor the shot hole depth and their positions.

Manual drilling was used to drill shot holes of depth of 60 feet. For

Shot locations falling in low lying areas and near river channels

precautionary measures were taken to load the holes immediately as soon as

they were drilled to avoid hole collapse. In essence, such types of areas were

identified one day in advance to the recording operations so that proper

planning of blasters movement in a systematic way to these points can take

place without any loss of operation time.

c. Loading and Blasting of Shot Holes

As dynamite is used as a subsurface source of energy to generate the

elastic waves in the seismic survey operation so it require awareness in the

handling. The loader crews again verified shot hole depth and used 10 feet

long steel rods to load and proper coupling of explosive charge varying 2.5-

5.0 Kg. In many occasions shot holes were either washed properly or

redrilled upto desired depth to generate good seismic signal.

Quality Control

1. The accuracy of the surveyed grid was maintained by adopting the

best practices in DGPS, Control Point Survey and Implantation

survey. (Field Operation: Survey).

31

2. Before going to field, we ensured the proper functioning of ground

electronics in order to avoid the loss of operational time and any

interference in the data due to faulty electronic equipments.

3. A small geophysical laboratory equipped with Test and Maintenance

System (TMS), Line Tester (LT 388) and Geophone Analyzer was

established for the repairing and calibration of faulty ground

electronics.

4. Bit to Bit verification test of the instrument was carried out to ensure

the error free seismic data acquisition.

5. Company line supervisors, contractor line supervisors and executives

ensured correct positioning of receiver lines and shot hole positions

through the following:

Shot point and trace point interval was checked and verified by

step traversing, wherever there were any doubts.

It was ensured through physical checking that every geophones

was implanted vertically and their coupling with the ground were

firm.

No compromises were made regarding the shot hole depth. Every

shot hole drilled up to desired depth to generate good seismic

signal. In many occasions shot holes were washed properly to put

the explosives inside for having proper coupling and desired

depth. Always shots were tamped with water and mud for proper

coupling & energy penetration.

6. The Crosstalk, Impulse and Leakage tests were run every day in the

field prior to and during the moment of seismic data acquisition. The

results were analyzed to replace the faulty cable, SU, CSU, geophones

etc. with the new one.

32

7. Raw monitor records was used as QC measure tool during the field

operation as follows

First break on the monitor records depicts the shot position.

Slope of the first arrivals; direct wave energy and refracted

energy used to verify the trace line alignment.

Noise analysis and map ability of deeper horizons or target

horizons on the monitor records used to have a rough idea about

the shot hole depth and charge size used.

The geophone response in terms of polarity and plantation

verified from the monitor records.

Utmost care was taken not to let the noise come into data. During

the course of production shooting all the lines in the swath were

monitored on a continuous basis to avoid any form of undesired

noise in the recorded seismic signatures. The shots were only

taken when the noise level was at its minimum. This assumed

significant importance as several trace lines crossed through

highways with heavy traffic plying on them.

8. Planning of recovery shots had to be done on continuous basis due to

obstacles, local problems and other access constraint in the area of

operation. Subsequently, effective recovery shots with suitable spread

pattern were planned through simulation in such a way that the

missing geophysical attributes are recovered to the best possible

extent.

Up hole Survey and Data Interpretation

Earth is assumed to be made of different homogeneous layers with different

physical properties but the near surface layer known as weathering layer

33

shows a great variation in its physical properties and it is of great importance

in hydrocarbon exploration. To delineate the deeper horizons, it is necessary

and required to know the near surface’s physical properties because the

heterogeneity in the physical properties of the near surface effects the data

recorded for deeper horizons. The main objective of the uphole survey is to

know the velocity and thickness of weathering layer as well as sub-

weathering layer. The results of uphole survey are used to calculate the

source statics and receiver statics correction.

3. Seismic Energy source

Seismic energy sources are used to generate energy which propagates

inside and undergo various phenomenons like refraction, reflection and

diffractions which return to the earth surface and recorded by detectors

situated near the earth. There are a number of energy source which are

related to explosive and non explosive .We use these energy sources for land

and marine seismic data acquisition.

The main difference between land and marine seismic is the water

layer, which has to be penetrated by the signal. The physical processes by

which seismic energy is generated in the water are different from those in

solid earth materials.

3.1 Land energy sources & Marine energy source

Dynamite

34

Dynamite is an ideal seismic source for land data acquisition. because of the

impulsive nature of the seismic signal it creates and convenient storage and

mobility it provides for energy that can be converted into ground motion.

There are several disadvantages associated wit the use of dynamite.

1) In seismic operations, the dynamite is planted in sticks or cans in

boreholes that may range from 30 ft. to several hundred feet in depth. This

requires drilling the holes, which is a difficult and expensive procedure. It is

difficult to use in hilly terrain where the heavy drilling equipment is not easy

to move and in deserts where the water is not readily available.

2) Dynamite is dangerous to use. Any mishandling can be costly and

harmful.

Dynamite are also used in marine seismic data acquisition .in shooting

explosive at sea, it has been customary to detonate the charge at such a

shallow depth that bubble would break through surface of the water and not

oscillate the maximum depth “d” (in feet) at which the bubble will break is

releated to the charge weight “w” (in pound) by the formula d=3.8w1/3

There are several disadvantages associated wit the use of dynamite

1) It causes loss of marine lives and property.

2) Low efficiency since large portion of energy goes into the air.

3) Danger in handling in explosives.

Buried Primacord

Primacord (an explosive extruded into a rope like form), detonating it at one

end or its center, and letting the explosive disturbance propagate along it at a

speed 22,000 ft/s. Geoflex source system operates on this principle.

35

Vibroseis:

Vibroseis is a method used to propagate energy signals into the earth over an

extended period of time as opposed to the near instantaneous energy

provided by impulsive sources described above. The signal was originally

generated by a servo-controlled hydraulic vibrator or shaker unit mounted on

a mobile base unit but electro-mechanical versions have also been

developed. Vibroseis was developed by the Continental Oil Company

(Conoco) during the 1950s and was a trademark until the company's patent

elapsed.

Air Gun

A source of seismic energy used in acquisition of marine seismic data. This

gun releases highly compressed air into water. Air guns are also used in

water-filled pits on land as an energy source during acquisition of vertical

seismic profiles.

Fig 3.1.1 Single Air gun Schematic Array Air gun arrangement

Armed and Fired Position

36

Weight dropping Early experiments were carried out in 1924 but use of magnetic recordings

made it possible to merge impulses from multiple drops in close propinquity

in order to produce from such energy sources. The first commercial system

of this type was invented by McCullom and put to use for oil exploration in

1953. The source he developed is called a Thumper.

A high level of noise is generated by weight dropping, mostly in the form of

surface waves. Procedure involves dropping of a 3-ton iron slab, attached to

a special crane on a truck hoisted 9ft. up in the air. As soon as the fist drop is

made, the truck is moved 10ft. to another spot within a few seconds. Waves

from each drop are picked up by the detector spread ad recorded on

magnetic tape for later analysis.

The main disadvantage of using this mechanism is that dropping in no way

produces synchronized impacts from multiple units.

Flexotir

This is a small pellet of dynamite weight about two ounces .This is

detonated at the center of a perforated cast-iron spherical shell about 2ft in

diameter which is towed behind at the depth about 40ft .the perforation

breaks the bubble so that undesired effect of bubble pulsing on the signal are

suppressed .Here the shooting depths ¼ of wavelength of typical seismic

reflection wave .therefore ,the efficiency of the explosion for generation

seismic energy is much greater than foe detonation just below the surface.

Maxipulse

37

Another source containing dynamite, the maxipulse is also designed for

detonation under conditions that combine safty ,efficiency ,and elimination

of bubble-pulse effects. In this the charge is about half pound packed in a

can which is injected into the water at a depth of about 20to 40ft. The

detonation tackes place about 1 second after the injection. After detonation,

a bubble is formed which expands and and collapses with a period of

100millseconds .In order to reduce the bubble oscillation a filter is used.

4. SEISMIC DATA PROCESSING

Alteration of seismic data to suppress noise, enhance signal and migrate

seismic events to the appropriate location in space is termed as Seismic

Processing. It facilitates better interpretation because subsurface structures

and reflection geometries are more apparent.

4.1 OBJECTIVES

To obtain a representative image of the subsurface.

Improve the signal to noise ratio: e.g. by measuring of several

channels and stacking of the data (white noise is suppressed).

Present the reflections on the record sections with the greatest

possible resolution and clarity and the proper geometrical relationship

to each other by adapting the waveform of the signals.

Isolate the wanted signals (isolate reflections from multiples and

surface waves).

38

Obtain information about the subsurface (velocities, reflectivity etc.).

Obtain a realistic image by geometrical correction.

Conversion from travel time into depth and correction from dips and

diffractions

4.2 PREPROCESSING Preprocessing is the first and important step in the

processing sequence of and it commences with the reception of field tapes

and observers log .Field tape contains seismic data and observers contains

geographical data(shot/receiver number, picket number, latitude and

longitude etc.)

DEMULTIPLEXING

Field tapes customarily arrive at the processing center written in

multiplexed format (time sequential) because that is the way generally the

sampling is done in field. In general the early stages of processing require

channel ordered or trace ordered data. Demultiplex is therefore done to

convert the time sequential data into trace sequential data.

39

Mathematically, demultiplexing is seen as transposing a big matrix so that

the column of the resulting matrix can be read as seismic traces recorded at

different offsets with a common shot pint. At this stage, the data are

converted in a convenient format that is used throughout the processing.

This format is determined by the type of the processing system and

individual company. A common format used in seismic industry fro data

exchange is SEG-Y, established by the society of exploration geophysicists.

Nowadays demultiplexing is done in the field.

REFORMATTING

The formats generally used for data recording are SEG-D (Demultiplexed

data) and SEG-B (Multiplexed data). Hence they are called field formats.

Demultiplexed is done on data recorded in SEG-D format. In this stage the

data are converted to a convenient format, which is used throughout

processing. There are many standards available for data storage. Format

differs with the manufarcturer, type of recording instrument and also with

the version of operating system.

Field Geometry Set Up

Field geometry is created with the help of information provided by

field party. That is as follows.

1. Survey information

(I) X and Y coordinate of shot/vib. Points.

(II) Elevation of geophone/shot points

2. Recording instrument

(I) Record file numbers

40

(II) Shot interval, group interval, near offset and far offset

(III) Layout, no. of channels, foldage.

3. Processing information

(I) Datum statics

(II) Near surface model

(III) Datum plane elevation

EDITING

Edit traces, which consists of killing extremely noisy traces and

muting the first-arrivals on all traces. Traces from poorly planted geophones

may show sluggishness and introduce low frequency and sometimes cause

spiky amplitudes and therefore degrade a CMP stack. These traces are

identified during manual inspection/editing phase of all the shot records and

flagged in the header so that they will not be included (they are “killed”) in

processing steps and in display.

Traces so noisy that they don’t visually correlate with strong arrivals

on adjacent traces should be killed. We have to be conservative in trace

killing because the fold of this data is low and eliminating only a few traces

may have noticeable effect on the stacked traces.

Editing involves leaving out the auxiliary channels & NTBC traces

and detecting and changing dead or exceptionally noisy traces. Bad data may

be replaced with interpolated values. Noisy traces, those with static glitches

or mono-frequency high amplitude signal levels are deleted. Polarity

reversals are corrected. Output after editing usually includes a plot of each

file so that one can see what data need further editing and what type of noise

attenuation are required.

41

Fig.4.1.2 (a) before editing (b) after editing

SPHERICAL DIVERGENCE CORRECTION

A single shot can be thought of a point source which gives rise to a

spherical wave field. There are many factors which affect the amplitude of

this wave field as it propagates through the earth.

Two important factors which have major effect on a propagating wave

field are spherical divergence and absorption. Spherical divergence causes

wave amplitude to decay as 1/r, where r is the radius of the wave front.

Absorption results in a change of frequency content of the initial source

signal in a time-variant manner, as it propagates. Since earth behaves as a

low pass filter so high frequencies are rapidly absorbed.

There are some programmes used for gain-AGC, PGC, geometric spreading

correction

STATIC CORRECTION

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When the seismic observations are made on non flat topography, the

observed arrival times will not depict the subsurface structures. The

reflection time must be corrected for elevation and for the changes in the

thickness of the weathering layer with respect to flat datum. The former

correction removes difference in travel time due to variation of surface

elevation of the shot and receiver location. The weathering corrections

remove differences in travel time to the near surface zones of unconsolidated

low velocity layer which may vary thickness from place to place. These are

also called static corrections, as they do not change with time. The static

corrections are computed taking into account the elevation of the source and

receiver locations with respect to seismic reference datum (such as Mean

Sea Level), velocity information in the weathering and sub weathering

layers. Often, special surveys (up hole surveys, shallow refraction studies)

precede the conventional acquisition to obtain the characteristics of the low

velocity layer.

MAIN PROCESSING

Main processing starts. It includes three major steps. They are as follows:

1. DECONVOLUTION

2. STACKING

3. MIGRATION

43

Fig 4.1.3 Seismic data volume represented in processing coordinate:

midpoint- offset-time

Deconvolution acts on the data along time axis and increase temporal

resolution.

Stacking compresses the data volume in the offset direction and yields

the plane of stack section (the frontal face of the prism)

Migration then move dipping events to their true subsurface position

and collapses diffraction and thus increases lateral resolution.

DECONVOLUTION

Deconvolution is a process that improves the temporal resolution of seismic data by compressing the basic seismic wavelet.

The need for deconvolution: In exploration seismology the seismic wavelet generated by the source

travels through different geologic strata to reach the receiver. Because of the

many distorting effects encountered the wavelet reaching the receiver is by

no means similar to the wave propogation by source.

Objective of deconvolution:

Shorten reflection wavelets

44

Attenuate ghost , instrument effects , reverberation and multiple reflection

The convolutional model for deconvolution

(I) The earth is made up of horizontal layers of constant velocity.

(II) The source generates a compressional plane wave that impinges on

layer boundaries at normal incidence.

(III) The source wave form does not change as it travels in the surface.

(IV) The noise component n(t) is zero.

(V) The source waveform is known.

(VI) Reflectivity is a random series.

(VII) Seismic wavelet is minimum phase.

There are two type Deconvolution

1) Deterministic Deconvolution:

Deconvolution where the particular of the filter whose effects are to

be removed are known is called deterministic Deconvolution .The

source wave shape is sometime recorded and used in a deterministic

source signature correction .No random are involved For e.g. where

source wavelet accurately known we can do source signature

deconvolution.

2) Statistical deconvolution:

A statistical deconvolution need to derive information about the

wavelet from the data itself where no information is available about

any of the component of the model .Statistical deconvolution is

applied without prior application of deterministic deconvolution in the

45

case the of a land data taken with an explosive source. In addition we

make certain assumption about the data justifies the statistical

approach

There are two type of statistical deconvolution

(I) Spiking Deconvolution – The process by which the seismic

wavelet is compressed into a zero lag spike is called Spiking decon

(II) Predictive deconvolution – The process uses prediction distance

greater than unity and yields a wavelet of finite duration instead of a

spike. This is helpful in suppressing multiples

CMP Shorting:

Seismic data acquisition with multifold coverage is done in shot-receiver

(s,g) coordinate. Seismic data processing, on other hand conventionally is

done in midpoint-offset (y, h) coordinates. The required coordinate

transformation is achieved by sorting the data into CMP gather based on the

field geometry information , each individual trace is assigined to the mid

point between shot and receiver location associated with that trace .Those

traces with the same mid point are grouped together , making up a CMP

gather

46

Fig 4.1.4 Seismic data in shot-receiver coordinates

Fig 4.1.5 Seismic in common midpoint gather

Velocity Analysis

Velocity analysis is the most important and sensitive part of the

processing. Without velocity we cannot change seismic section into depth

domain, which is very necessary. For applying NMO correction we need

NMO velocity. Thus we perform velocity analysis on each CDP gather but it

is not feasible to perform velocity analysis on each CDP gather. Hence we

perform velocity analysis on one CDP gather from a group of CDP points

(generally group size is 50 VDP points). There are several methods to do

velocity analysis like constant velocity scan, constant velocity stacks (CVS),

47

velocity spectrum method and horizontal velocity analysis. Out of these

methods, now a days velocity spectrum method is mostly used because it

distinguishes the signal along hyperbolic paths even with a high level of

random noise. This is because of the power of the cross correlation in

measuring coherency. The accuracy of the velocity is limited.

(I) Constant Velocity Stacks (CVS):Fig shows this method. In this example, a portion of a line consisting

of 24 common-depth-point gather have been NMO corrected and stacked

with velocities ranging 1000 m/s to 3000 m/s. The resulting stacked 24

traces, displayed as one panel, represent one constant velocity. These panels

are displayed side by side with the velocity value indicated, where velocity

values increase from left to right. Stacking velocities are picked directly

from these panels by selecting the velocity that yields the best coherency and

the strongest amplitude for a velocity value at a certain time.

Care must be taken in using this kind of velocity analysis to estimate

the best stacking velocities. One should know the velocity range of an area,

especially if there are structure changes.

(II) Velocity spectrum method: The velocity spectrum approach is unlike the CVS method. It is base

on the correlation of the traces in a CMP gather, and not on lateral continuity

of staked events. This method, compared with the CVS method, is more

suitable for data with multiple reflection problems. It is less suitable for

highly complex structure problems. Suppose we repeatedly correct the

gather using constant velocity values from 2000-4300 m/sec, then stack the

gather and display the stacked traces side by side. The result is a display of

velocity versus two-way time, called a “velocity spectrum”.

48

There are two commonly used ways to display the velocity spectrum: power plot and contour plot

(III) Horizontal Velocity Analysis:One method to estimate velocities with enough accuracy for structural

and stratigraphic application to analyze the velocities of a certain horizon of

interest continuously. Such a detailed velocity analysis is called Horizontal

Velocity Analysis. The velocity is estimated at every CMP along the selected

key horizon of interest on the stacked section. The principle of estimating

the velocities by this method is the same as that of the velocity spectrum.

The output coherency values derived by hyperbolic time gates are displayed

as a function of velocity and CMP position.

One of the applications of horizontal velocity analysis is to improve

the layered velocity variation along marker horizon, especially if these

velocities are used in post-stack depth migration.

49

Fig 4.1.5 Two way of displaying velocity spectrum derived from the CMP gather (a), (b) power plot (c) contour plot.

Fig 4.1.6 The CMP gather and its velocity spectrum , the curve to the right

of the semblance peaks is the interval velocity function derived from the

picked rms velocity function.

NORMAL MOVEOUIT CORRECTION

None zero offset data is characterized by a travel time increase with

increase in offset distance from the source to the reflector. on zero offset to

zero offset conversion is achieved through a correction called as NMO

(normal move out) correction.

For the single constant horizontal velocity layer the trace time curve

as a function of offset is a Hyperbola. The time difference between travel

time at a given offset and at zero offset is called normal moveout (NMO).

50

The velocity required to correct for normal moveout is called the normal

moveout velocity. For a single horizontal reflector, the NMO velocity is

equal to the velocity of the medium above the reflector .

The simple case of single horizontal layer, using by Pythagorean

Theorem the travel time equation as a function of offset is

t2(x) = t2(0) + x2v2

Where x is the distance (offset) between the source and receiver

position. V is the velocity of the medium above the reflecting interface. And

f (0) is twice the travel time along the vertical path. The NMO correction is

given by the difference between t(x) and t(0)

∆tNMO = t (x) – t (0)

= t (0) {[1- (x / vNMO.t (0))2]1/2 -1}

Fig 4.1.7 The simple geometry for NMO correction in single layer

NMO in a horizontal stratified earth

51

Now we consider a medium, composed of horizon isovelocity layers

Fig 2.9. is each layer has a certain thickness that can be defined in terms of

two way offset time. The layers have interval velocities (v1,v2,….vN) where

N is Number of layers. Travel time equation for the path SDR is

T2(x) = c0 + c1x2 + c2x4 + c3x6 + …………

Where c0 = t(0), c1 = 1 / v2rms and c2, c3, …… are complicated

functions The rms velocity vrms down to the reflector on which depth point D

is situated is defined as

V2rms = 1 / t(0) ∑ vi

2 ∆ti(0)

Where ∆ti is the vertical two way time through the i th layer and t(0) =

∑ ∆tk. by making small spread approximation the series in equation … can

be truncated as follows:

T2(x) = t2(0) + x2 / v2rms

Here we see that the velocity required for NMO correction for a

horizontally stratified medium is equal to the rms velocity

Fig 4.1.8 NMO for horizontal layer

52

Fig 4.1.9 Before and after NMO correction

NMO Stretching:In NMO correction, a frequency distortion occurs, particularly for

shallow events and at large offset. This is called NMO stretching The

waveform with a dominant period T is stretched so that its period becomes

T’. Stretching is frequency distortion in which events are shifted to lower

frequencies, stretching is quantifies as

∆f / f = ∆tNMO / t (0)

Where f is the dominant frequency. ∆f is change in frequency

53

Because of the stretched waveform at large offset, stacking the NMO

corrected CMP gather will severely damage the shallow events. This

problem can be solved by muting the stretched zone in the gather.

Fig 4.1.8 NMO Stretch

RESIDUAL STATIC CORRECTION

They are statics deviation from a perfect hyperbolic travel time after

applying NMO and elevation statics corrections to trace within the CMP

gather. These statics cause misalignment of the seismic events across the

CMP gather and generate a poor stack trace. We need to estimate the time

shifts from the time to perfect alignment, then correct them using an

automatic procedure.

A model is need for the moveout corrected travel time from a source

location to point on the reflecting horizon, then back to a receiver location.

The key assumption is that the residual statics are surface consistent,

meaning that statics shift are time delays that depend on the sources and

receiver on the surface. Since the near-surface weathered layer has a low

velocity value, and refraction in its base tends to make the travel path

54

vertical, the surface consistent assumption usually is valid. However, this

assumption may not be valid for high-velocity permafrost layer in which

rays tend to bend away from the vertical.

Residual static corrections involve three stages:

1. Picking the values.

2. Decomposition of its components, source and receiver static,

structural and normal moveout terms.

3. Application of derived source and receiver terms to travel times

on the pre-NMO corrected gather after finding the best solution

of residual static correction. These statics are applied to the

deconvolved and sorted data, and the velocity analysis is re-run.

A refined velocity analysis can be obtained to produce the best

coherent stack section.

DMO (dip move out) CORRECTION

The DMO correction says that-post-stack migration is acceptable

when the stacked data are zero-offset. If there are conflicting dips with

varying velocities or a large lateral velocity gradient, a prestack partial

migration is used to attenuate these conflicting dips. By applying this

technique before stack, it will provide a better stack section that can be

55

migrated after stack. Prestack partial migration only solves the problem of

conflicting dips with different stacking velocities. Its applications are:

(I) Post-stack migration is acceptable when the stacked data is zero-

offset. This is not the case for conflicting dips with varying velocity or

large lateral velocity variations.

(II) Prestack partial migration or dip Move out provides a better stack,

which can be migrated after stack.

(III) PSPM solves only conflicting dips with different stacking

velocities.

STACKING

(I) Each common mid point gather after normal move out correction is

summed together to yield a stacked trace.

(II) Stacking enhances the in-phase components and reduces the random

noise.

(III) Stacking yields Zero offset section (in the absence of dipping layers

in the subsurface)

Stacking is combining two or more traces into one. This combination

takes place in several ways. In digital data processing, the amplitudes of the

traces are expressed as numbers, so stacking is accomplished by adding

these numbers together.

Peaks appearing at the same time on each of two traces combine to

make a peak as high as the two added together. The same is true of two

troughs. A pear and a trough of the same amplitude at the same time cancel

56

each other, and the stack trace shows no energy arrival at that time. If the

two peaks are at the different times, the combined trace will have two

separate peaks of the same sizes as the original ones. After stacking, the

traces are “normalized” to reduce the amplitude so that the largest peaks can

be plotted. Figure 2.11 illustrates the principle of stacking.

MIGRATION

Migration is the processes that repositions reflected energy from its

common mid point to its true subsurface location. Dipping reflector on a

CMP stack are plotted down dip from with less dip than their true position.

A seismic section is assumed to represent a cross-section of the earth.

The assumption work best when layers are flat, and fairly well when they

have gentle dips. With steeper dip the assumption breaks down; the

reflections are in the wrong places and have the wrong dips.

57

Fig 4.1.9 Stacking process

In estimating the hydrocarbons in place, one of the variables is the

areal extent of the trap. Weather the trap is structural or stratigraphic; the

seismic section should represent the earth model.

Dip migration, or simply migration, is the process of moving the

reflections to their proper places with their correct amount of dips. This

results in a section that more accurately represents a cross-section of the

earth, delineating subsurface details such as fault planes. Migration also

collapse diffractions.

Migration is mainly divided into six parts 1) 2D migration 2) 3D migration

3) Time migration 4) Depth migration 5) Pre stack migration 6) Post stack

migration.

Bow-tie effect

A concave-upward event in seismic data produced by a buried focus and

corrected by proper migration of seismic data. The focusing of the seismic

wave produces three reflection points on the event per surface location. The

name was coined for the appearance of the event in unmigrated seismic data.

Synclines, or sags, commonly generate bow ties.

58

Fig 4.1.10 A syncline might appear as a bow tie on a stacked section and can

be corrected by proper migration of seismic data.

Migration algorithms

Migration algorithms can be classified under three main categories:

(I) Those that are based on the integral solution to the scalar wave equation,

(II) Those that are based on the finite- difference solution

(III)Those that are based on frequency-wavenumber implementations

Migration parameters

After deciding on the migration strategy and appropriate algorithm.The

analyst then decide the migration parameter

(I) Migration aperture width is the critical parameter in Kirchhoff migration.

59

(II) Depth step size in downward continuation is the crietical parameter in

finite –difference methods.

(III) The stretch factor is the critical parameter for stolt migration.

Migration principles

The migration principles are

(I) The dip angle of the reflector in the geologic section is greater than in the

time section thus migration steepens reflector.

(III) The length of the reflector , as seen in the geologic section is shorter

than in time section; thus , migration shortens the reflector.

(III) migration move reflector in the updip direction.

0 A B x

C True Dip C’

t D D’

Apparent Dip

Fig 4.1.11 Migration principle

Methods of Migration

There are different types of migrations:

Kirchhoff’s migration: It is a statistical approach technique. It is

based on the observation that the zero-offset section consists of a single

60

diffraction hyperbola that migrates to a single point. Migration involves

summation of amplitudes along a hyperbolic path. The advantaged of this

method is its good performance in case of steep-dip structures. The method

performs poorly under low signal-to-noise ratio.

Finite difference migration: It is a deterministic approach. It is

modeled by an approximation of the wave equation that is suitable for use

with computers. On e advantage of the finite difference method is its ability

to perform well under low signal-to -noise ratio condition. Its disadvantage

includes long computing time and difficulties in handling steep dips.

Frequency Domain or F-K Migration: It is a deterministic approach

via the wave equation instead of using the finite difference approximation.

2-D Fourier Transform is the main technique, use here. Its advantage is its

fast computing time, good performance under low signal-to-noise ratio and

excellent handling of steep dips. But it includes difficulty with wide varying

velocities.

Depth Migration:Time migration is appropriate as long as lateral velocity variations are

moderate. When these variations are substantial, depth migration is needed

to obtain a true picture of the subsurface.

Time migration generally describes a simpler migration method than

depth migration, though depth migration is more accurate, and can handle

more complex situations. Usually, the output from time migration is a time

section, and the output from depth migration is a depth section. Depth

migration also deals with lateral velocity variations thus it involves large

computational time.

61

Migration Effects

Using perpendicular reflection principle, some subsurface features and how

they will look when converted to sections with vertical traces can be

considered. Then some rules can be formed for how the features of the

section will have to change to be migrated back to their correct

configurations. For simplicity at this stage, it will be assumed that the

velocity of sound is constant all through the geologic section, and that the

lines are shot in the direction of dip, so they do not have any reflections from

one side or the other of the line.

1 Reflections move up-dip.

2 Anticlines become narrower.

3 Anticlines may have less or the same vertical closure.

4 The crest of the anticline does not move.

5 Synclines become broader.

6 The low point of the syncline does not move.

7 Synclines may have more or the same closure.

8 Crossing reflections may become a sharp syncline (Bow-tie effect)

9 An umbrella shape, diffraction, becomes a point.

10 The crest of diffraction does not move, and is the diffraction point.

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5. INTERPRETATION

The interpretation of seismic data in geologic terms is the objective

and end product of seismic work. Seismic data are usually interpreted by

geophysicists or geologists. Since, drilling wells is very costly, it is

preferable to interpret from the seismic data as much information as possible

about the geologic history of the area and about the nature of the rocks in an

effort to form an opinion about the probability of encountering petroleum in

the structures which we map.

There are some basic steps that should be followed while interpreting

a seismic section. Interpreting seismic data is straightforward provided that a

simple procedure is adopted. The technique is to divide up the seismic

section into areas of common dip families and then mark the boundaries

where these families end. The nature of these boundaries can then be

interpreted geologically and a geological history for the seismic section

produced.When data is first loaded onto a seismic workstation it is very

important not to begin detailed interpretation immediately but to stand back

and make sure that a few preliminaries have been observed.

Some basic steps of seismic interpretation are:

(1) Look at the horizontal and vertical scales and makes sure you have a

feeling for the dimensions of the data that you are looking at.

(2) Familiarize yourself with the orientation of the data and how it relates

to the base map. In particular ensure that, for any geological structure,

you know which is the dip and which is the strike direction.

63

(3) Look at the data on a scale that enables you to see an entire inline or

cross line and look at the near surface to see if there are any features of

note in the upper section. In particular, things to look out for are:

a. near surface channels filled with fast or slow velocity material

which have a time effect on all horizons below.

b. near surface amplitude anomalies. These could be shallow

hydrocarbon deposits and constitute drilling hazards.

c. if land data, have a look at the statics that were applied and see

if there is any time structure related to these static corrections.

This structure may be spurious if the statics were applied with

the wrong velocity.

d. look for velocity anomalies creating time structure. For

example pull up under salt or fault shadow effects. These time

artefacts are much easier to see on sections displayed at a large

scale, i.e. 1:50,000 or 1:100,000.

e. and finally have a look at the migration that was applied to the

data and see if you think that the data are correctly positioned..

The interpretation procedure:

(1)The section is divided into dip families.

(2)The boundaries are drawn around each dip family

(3) If the horizontal boundaries are not well defined, the dips of the

overlying family are extended downwards as far as possible. The dips

of the underlying family are extended up as far as possible. A best

estimate of the position of the boundary is made and marked.

(4)The nature of the boundaries are decided upon:

(a) vertical or inclined

faults

64

rock or facies boundaries, e.g. salt

edge

(b) horizontal or inclined

unconformities

structural growth stages

rock or facies boundaries, e.g. reefs

fans, deltas, channels, etc

(5)Seismic features are separated from geology. For example, multiples,

velocity anomalies, sideswipe.

(6)The structural and depositional history is developed.

(7)A geological model is decided on, tested and revised..

(8)The geological model is built and restored in depth at a 1 to 1 scale.

(9)Mapping horizons are selected along with dip families controlling

Figure 5.1.1: Characteristics of different types of bed inclination found in

the seismic trace.

65

A synthetic example of the relationship of dip families and how they can be

interpreted geologically is shown in the diagram below. The geological

history derived from such a seismic interpretation would be along the

following lines, in time order.

Figure 5.1.2 Pattern of Dip and Boundaries.

(i) Horizons 6, 7 and 8 were laid down flat

(ii) Uplift occurred which created the anticline that now contains

these horizons

(iii) Erosion created the unconformity that separates horizon 5 from

those below.

(iv) Horizons 1 to 5 were laid down flat over the unconformity

66

(v) Compression created the thrust which moved horizons 1 to 4

over the top of horizon 5.

An example of an interpreted seismic section is shown in the Figure .

Figure 5.1.3 An interpreted section

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6. PETROLEUM SYSTEM

6.1 INTRODUCTION The geologic components and processes necessary to generate and store

hydrocarbons, including a mature source rock, migration pathway, reservoir

rock, trap and seal are collectively called the petroleum system. Appropriate

relative timing of formation of these elements and the processes of

generation, migration and accumulation are necessary for hydrocarbons to

accumulate and be preserved. Exploration plays and prospects are typically

developed in basins or regions in which a complete petroleum system has

some likelihood of existing

6.2 PETROLEUM

Petroleum is a complex mixture of naturally occurring hydrocarbon

compounds found in rock and it can exist as solid, liquid and gaseous

according to the pressure-temperature-composition, with or without

impurities such as sulphur, oxygen and nitrogen; and there is considerable

variation in its physicochemical properties like colour, gravity, odour,

sulphur content and viscosity in petroleum from different areas.

Fig 6.1.1 Petroleum System

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In addition to these four basic components, a petroleum system by

definition includes all the geologic processes required to create these

elements. Crucial factors of proven (i.e., economic) petroleum systems

include:

Organic richness/type and volume of generative source rock

Adequate burial history to ensure proper time-temperature conditions

for source rock maturation

Timing of maturation and expulsion in relation to timing of trap

formation

Presence of migration pathway linking source and reservoir rocks

Preservation of trapping conditions from time of entrapment to

present day

Relative efficiency of sealing layers

Petroleum systems may be identified according to three levels of certainty: known, hypothetical, and speculative (Magoon, 1988). In a known system, a good geochemical match exists between the source rock and accumulations; in the hypothetical case, a geochemical match is lacking but geochemical evidence is sufficient to identify the source rock. In the case of a speculative petroleum system, the presence of economic accumulations are lacking, but the existence of source rocks and oil/gas accumulations are postulated on the basis of geologic or geophysical evidence. 

6.3 ELEMENTS OF PETROLEUM SYSTEM

The essential elements of a petroleum system include the following:

Source rock

Reservoir rock

Cap rock

69

Trap

Migration

Source Rock:

1. Production, accumulation and preservation of organic matter are

prerequisites for the existence of petroleum source rocks.

2. Photosynthesis is the basis for mass production of organic matter.

About 2 billion years ago in the Precambrian photosynthesis emerged

as a world wide phenomenon.

3. Favourable conditions for the deposition of the sediments rich in

organic matter are found on the continental shelves in the area of

restricted circulation. Continental slopes are also favourable for

accumulation of organic matter

4. There are three major phases in the evolution of organic matter from

the time of deposition to the beginning of metamorphism.

a) Diagenesis:

This phase occurs in the shallow subsurface at near normal

temperatures and pressures. It includes both biogenic decay, aided

by bacteria, and abiogenic reactions. Methane, carbon dioxide and

water and given off by the organic matter leaving a complex

hydrocarbon termed Kerogen.

b) Catagenesis:

This phase occurs in the deeper subsurface. Thermal degradation

of the kerogen is responsible for the generation of most

hydrocarbons i.e., oil and gas

70

c) Metagenesis;

This third phase occurs at high temperatures and pressures verging

on metamorphism. The last hydrocarbons, generally only methane

are expelled.

5. The types of Kerogen present in a rock largely control the type of

hydrocarbons generated in that rock. Different types of Kerogen contain

different amounts of hydrogen relative to carbon and oxygen. The

hydrogen content of Kerogen is the controlling factor for oil vs. gas yields

from the primary hydrocarbon-generating reactions.On the basis of

chemical composition in the nature of organic matter the kerogen is

classified into four basic types as:

Kerogen

Type

Predominant Hydrocarbon

Potential

Amount

of

Hydrogen

Typical

Depositional

Environment

I Oil prone Abundant Lacustrine

II Oil and gas prone Moderate Marine

III Gas prone Small Terrestrial

IV Neither (primarily composed

of vitrinite) or inert material

None Terrestrial(?)

Table 6.1.2 Types of Kerogen

a)Type-I Kerogen or saprophilic

This is essentially algal origin.it has high hydrogen carbon ratio(H:C

is about 1.2-1.7)

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b) Type-II Kerogen or Liptinic

The organic matter of this type of kerogen consisted of algal

detritus,but also contain material derived from zooplankton and

phytoplankton.It has H:C ratio greater than 1.

c) Type-III kerogen or humic

This kerogen has a much lower H:C ratio(<0.84).Humic kerogen is

produced from the lignin of the higher woody plants which grow on

land.Type III sorce material is good for gas source.

A source rock is a rock that is capable of generating or that has generated

movable quantities of hydrocarbons. Typical source rocks, usually shales or

limestone, contain about 1% organic matter and at least 0.5% total organic

carbon (TOC), although a rich source rock might have as much as 10%

organic matter. Rocks of marine origin tend to be oil-prone, whereas

terrestrial source rocks (such as coal) tend to be gas-prone.

Source rocks can be grouped into four basic categories, which are described

in the table-1. To be a source rock, a rock must have three features:

1. Quantity of organic matter

2. Quality capable of yielding moveable hydrocarbons

3. Thermal maturity.

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Table 6.1.3: Types of Source Rocks

Table 6.1.4: The most common methods used to determine the potential of a

source rock.

6.4 Generation

The most important factor in the generation of crude oil from the organic

matter from the sedimentary rocks is temperature. A minimum temperature

of 1200 F (500 C) is necessary for the generation of oil under average

sedimentary basin condition. The generation end sat 3500 F (1750 C).Time is

also an important factor. The older the sediments lower the temperature of

generation. Younger sediments need higher temperature to generate oil than

the average. Heavy oils are generated at the lower temperature where as the

73

light oils are generated at high temperature. It takes millions of years to

generate oil from organic matter. The youngest known source rock that has

generated oil is Pliocene. At temperature higher than 3500 F crude oil is

irreversibly transformed into graphite and natural gas. Because the oil

generation has a ceiling (1200 F) and a floor (3500 F), the depth in the earth

where oil is generated is called the Oil Window. The type of organic matter

in the source rock controls the type of petroleum generated.

Reservoir

A subsurface body of rock having sufficient porosity and permeability to

store and transmit fluids is a called a reservoir rock. Sedimentary rocks are

the most common reservoir rocks because they have more porosity than

most igneous and metamorphic rocks and form under temperature conditions

at which hydrocarbons can be preserved. The most significant property of

reservoir rock is its effective permeability. Obviously, since sandstones are

the best in permeability with respect to other rocks, they act as good

reservoir rocks.

Cap rock

It is an impermeable rock-material to prevent further migration of

hydrocarbons by buoyancy, and to seal petroleum within reservoir. Cap

rocks are commonly of shale or of chemically precipitated evaporite deposits

such as salt or gypsum, or biochemical alteration products of petroleum like

tar.

74

Traps

Trap is a configuration of rocks suitable for containing hydrocarbons and

sealed by a relatively impermeable formation through which hydrocarbons

cannot migrate. Traps are described as structural traps (in deformed strata

such as folds and faults) or stratigraphic traps (in areas where rock types

change, such as unconformities, pinch-outs and reefs) or their combinations.

A trap is an essential component of a petroleum system. Petroleum migrates

upwards and laterally from source to reservoir by buoyancy.

Being lighter than water, petroleum will displace groundwater and flow

upwards, as well as laterally and will seep to the surface via faults and

porous overburden unless confined under special circumstances to become

trapped and to form economic petroleum deposits. Migration of petroleum is

aided by its low surface tension, so that molecular attraction creates a film of

water around grains, whereas the petroleum occupies the central pore spaces

and is separated from the water.

Structural Traps

By juxtaposition of porous reservoir and impermeable cap rock due to

folding or faulting, structural traps are created. So some tectonic or

deformational mechanism (either brittle or ductile) are always involved

(Figure 5). Approximately, 80 - 90% of the world's proven oil reserves are

located in anticlinal traps. Anticlinal traps are commonly tens of kilometres

long or even greater, and may be thousands of metres in amplitude (e.g.

Bombay high), or they may be combination of several small anticlines.

Traps may be stacked vertically on top of each other where alternating

reservoir and cap rocks have been folded in the same anticline. Fault traps

are numerous, but only small. Faults can also be detrimental by breaching

75

the seal of the cap rock and allowing the flow of petroleum through the fault

to the surface, where it may form an oil seep.

Fig 6.1.5 Schematic diagrams of structural traps

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Stratigraphic traps

By juxtaposition of porous reservoir and impermeable cap rock due to

depositional variations in grain-size of different kinds of sediments

stratigraphic traps are formed. This may be due to the thinning of lenses of

sand and gravel (wedge-end traps), the morphology of carbonate reefs in

sub-circular mounds (reef traps) or by the juxtaposition of rock types at

unconformity surfaces (unconformity traps). Although unconformities are

numerous, unconformity traps account for only 4% of world reserves,

possibly because petroleum may have already escaped at the ancient surface

prior to the formation of the unconformable beds. In Indian offshore region,

especially, in the East Coast, most of the deep-water traps are stratigraphic

traps like pinch-outs, unconformities etc. In Rudrasagar Oil Field of Assam

is an example of stratigraphic trap, where petroleum exists in shoestring

fluvial sandstone.

77

Fig 6.1.6 Schematic diagrams of stratigraphic traps

Combination situations

There are several combinations of situations. Rising salt-dome has

stratigraphic traps draped against the edge with normal-fault trap caused by

tension stress over the top. Some oil also accumulates in porous cap of salt-

dome. In Assam Oil-field, there exists Naga Thrust upon which Tipam

Sandstone terminates forming thrust propagation fold. This arrangement is a

typical example of combination trap in India. Unfortunately, no salt-dome

trap is yet known in India.

78

Fig 6.1.7 Schematic diagrams of Combination Traps

Migration

Migration implies movement of hydrocarbon through rocks. There are two

types of migration in a petroleum system as described below.

79

Fig. 7. Schematic diagram of salt plug or

Fig 6.1.8 Migration of petroleum

Types of petroleum migration

1. Primary Migration

Primary migration is the process by which hydrocarbons are expelled

from the source rock into an adjacent permeable carrier bed. It is a

paradoxical situation, because most source rocks are black shale’s, which

have very low permeability’s.

2. Secondary Migration

Secondary migration is the movement of hydrocarbons along a "carrier

bed" from the source area to the trap. Migration mostly takes place as one

or more separate hydrocarbons phases (gas or liquid depending on

pressure and temperature conditions). Main Driving force for migration is

buoyancy. This force acts vertically and is proportional to the density

difference between water and the hydrocarbon. So, it is stronger for gas

than heavier oil.

80

.

Examples of Different Kinds of Non-sandstone Reservoir Rocks in

India

Limestone with secondary porosity: Bombay High.

Fractured shale: Indrora and Wadu Oil Field of Cambay Basin.

Igneous rock: Fractured syenite of Borholla Oil Field of Assam, India.

Reserve Estimation

,

Where A is the area in km2, H the thickness in m, Φ the porosity, S0 the oil

saturation, RF the recovery factor (the fraction of hydrocarbons, which can

be or has been produced from a well, reservoir or field; also, the fluid that

has been produced) and B0 is the reservoir formation volume factor.

B0 may be of two types. It can be defined as follows:

Gas FVF

It is gas volume at reservoir conditions divided by gas volume at surface

conditions. This factor is used to convert surface measured volumes to

reservoir conditions, just as oil formation volume factors are used to convert

surface measured oil volumes to reservoir volumes.

Oil FVF

It is oil and dissolved gas volume at reservoir conditions divided by oil

volume at standard conditions. Since most measurements of oil and gas

production are made at the surface, and since the fluid flow takes place in

the formation, volume factors are needed to convert measured surface

volumes to reservoir conditions. Oil formation volume factors are almost

always greater than 1.0 because the oil in the formation usually contains

81

dissolved gas that comes out of solution in the wellbore with dropping

pressure.

Accumulation

Once oil and gas migrates into the trap, it separates according to density.

The gas, being lightest. Goes to the top of the trap to from the free gas cap.

The oil goes to the middle, and the water, which is always present, is on the

bottom. The oil portion of the trap is saturated with a certain percentage of

oil and water. The gas-oil and oil-water contacts are buoyant and are usually

leveled. In some traps, only gas and water or oil and are found.

82

7. WELLSITE OPERATIONS

MEASUREMENT WHILE DRILLING (MWD)

Measurement While Drilling (MWD) technology has become an important

tool for reservoir evaluation in the past 10 years. It provides downhole

evaluation of formation gamma ray, resistivity, and porosity at the time of

drilling. This tool also measures and records some mechanical parameters

such as:

Well deviation and azimuth,

Rate of Penetration (ROP),

Downhole Weight on Bit (WOB) and downhole Torque.

Annular pressure

Annular temperature

ECD (Equivalent Circulating Density)

83

LOGGING WHILE DRILLING

INTRODUCTION

Logging While Drilling tools measure in-situ formation properties with

instruments that are located in the drill collars immediately above the drill

bit, hence forming a part of the bottom hole assembly(BHA). LWD data are

transmitted to the surface by mud pulse telemetry where variations in

pressure exercised by the tool can be sensed on the surface via a computer,

and stored in memory for retrieval on the surface.

OBJECTIVES OF LWD TECHNOLOGY

1) To get real time drilling data thus enabling quick decision-making on rig.

2) To get quick and correct formation evaluation.

MEASURED PARAMETERS

A suite of LWD tools attached to the bottom hole assembly record different

parameters of the drilled rocks:

Natural Gamma Ray(GR)

o Average Gamma Ray

o Gamma Ray Spectrometry (Potassium, Thorium, Uranium)

Electric

o Spontaneous Potential (old)

o Resistivity (Phase Shift & Attenuation)

84

Fig 7.1.1 Location of MWD hardware (not drawn to scale). (From Anadrill, 1988.)

Laterolog

Induction logs

Density & Porosity

o Bulk density logs

o Neutron Porosity

o Ultra Sonic Caliper

Nuclear Magnetic Resonance (NMR)

o Porosity

o Permeability

o Free and Bound Fluids

Acoustic (Sonic) response

o Compressional Slowness (Δtc)

o Shear Slowness (Δts)

o Estimated Porosity

ADVANTAGES OF LWD TECHNOLOGY

LWD, while sometimes risky and expensive, has the advantage of

measuring properties of a formation before drilling fluids invade deeply.

Further, many well bores prove to be difficult or even impossible to measure

with conventional wireline tools, especially highly deviated wells. In these

situations, the LWD measurement ensures that some measurement of the

subsurface is captured in the event that wireline operations are not possible.

85

Fig 7.1.2 Components of a BHA, showing position of LWD tools

86

INTRODUCTION TO LOGGING

RESISTIVITY LOGS

INTRODUCTION

Resistivity of a body or sample is defined as a physical property of a material to

resist or oppose the movement of charge through the material. Well logs, which

depend on electrical resistivity and are function of porosity, pore fluid content,

mineralogy and temperature in rocks, are resistivity logs. Two types of logs are

generally used, laterolog and induction log.

LATEROLOG

Laterolog tools send an electric current from an electrode on the sonde directly

into the formation. The return electrodes are located either on surface or on the

sonde itself. Complex arrays of electrodes on the sonde (guard electrodes) focus

the current into the formation and prevent current lines from fanning out or flowing

directly to the return electrode through the borehole fluid. Most tools vary the

voltage at the main electrode in order to maintain a constant current intensity. This

voltage is therefore proportional to the resistivity of the formation. Because current

must flow from the sonde to the formation, these tools only work with conductive

borehole fluid. Actually, since the resistivity of the mud is measured in series with

the resistivity of the formation, laterolog tools give best results when mud

resistivity is low with respect to formation resistivity, i.e., in salty mud.

86

INDUCTION LOG

Induction logs use an electric coil in the sonde to generate an alternating current

loop in the formation by induction. This is the same physical principle as is used in

electric transformers. The alternating current loop, in turn, induces a current in a

receiving coil located elsewhere on the sonde. The amount of current in the

receiving coil is proportional to the intensity of current loop, hence to the

conductivity (reciprocal of resistivity) of the formation. Multiple transmitting and

receiving coils are used to focus formation current loops both radially (depth of

investigation) and axially (vertical resolution). Since the 90’s all major logging

companies use so-called array induction tools. These comprise a single

transmitting coil and a large number of receiving coils. Radial and axial focusing is

performed by software rather than by the physical layout of coils. Since the

formation current flows in circular loops around the logging tool, mud resistivity is

measured in parallel with formation resistivity. Induction tools therefore give best

results when mud resistivity is high with respect to formation resistivity, i.e., fresh

mud or non-conductive fluid. In oil-base mud, which is non conductive, induction

logging is the only option available.

OBJECTIVE

Resisitivity log is generally shown on logarithmic scale. The resisitivity of

hydrocarbon is higher than the resisitivity of formation water. The resisitivity of

fresh water is also high and it decreases with increasing salinity. The formation

resisitivity depends on the formation fluid and porosity. If the rock has low

porosity or rock is compact then resistivity of formation is high. We can calculate

water saturation using Archie equation.

Sw = [(a / m)*(Rw / Rt)](1/n)

96

Sw: water saturation, Rw: formation water resistivity, R t: observed bulk

resistivity porosity, ‘a’ is a constant (often taken to be 1), m: cementation

factor (varies around 2).

GAMMA LOG

INTRODUCTION

Gamma-ray measurements detect variations in the natural radioactivity

originating from changes in concentrations of the trace elements uranium (U) and

thorium (Th) as well as changes in concentration of the major rock forming

element potassium (K). Since the concentrations of these naturally occurring

radioelements vary between different rock types, natural gamma-ray logging

provides an important tool for lithologic mapping and stratigraphic correlation.

Gamma-ray logs are important for detecting alteration zones, and for providing

information on rock types. For example, in sedimentary rocks, sandstones can be

easily distinguished from shales due to the low potassium content of the sandstones

compared to the shales.

In sedimentary rocks, potassium is the principal source of natural gamma radiation,

primarily originating from clay minerals such as illite and montmorillonite. In

igneous and metamorphic geologic environments, the three sources of natural

radiation may contribute equally to the total gamma radiation detected by the

gamma probe. Often in base metal and gold exploration areas, the principal source

of the natural gamma radiation is potassium, because alteration, characterized by

the development of sericite, is prevalent in some of the lithologic units and results

in an increase in the element potassium in these units. The presence of feldspar

porphyry sills, which contain increased concentrations of K-feldspar minerals,

would also show higher than normal radioactivity on the gamma-ray logs. During

96

metamorphism and hydrothermal alteration processes, uranium and thorium may

be preferentially concentrated in certain lithologic units.

Older gamma-ray logs are recorded in "counts" whose numbers vary according to

the tool design. Almost all modern gamma-ray logs are recorded in API (American

Petroleum Institute) units, which make a common standard for log comparison.

The scale was chosen so that a value of zero would mean no radioactivity and a

value of 100 would match a typical Mid-continent shale. In practice, shales can be

somewhat variable in their radioactivity according to their silt content, types of

clay mineral, and the occurrence of small amounts of uranium.

APPLICATION

Open-hole as well as cased-hole correlation(as γ rays have a good

penetrating power)

Computation of shale volume.

Different types of clay can be identified and discriminated

Environment of deposition can be inferred depending on Th:U ratio(Th is

present in terrestrial realm and U is mainly presenting marine realm)

To locate radioactive ores, uranium in particular.

SP LOG (SPONTANEOUS POTENTIAL LOG)

INTRODUCTION

The spontaneous potential tool measures natural electrical potentials that occur in

boreholes and generally distinguishes porous, permeable sandstones from

intervening shales. The "natural battery" is caused when the use of drilling mud

with a different salinity from the formation waters, causes two solutions to be in

96

contact that have different ion concentrations. Ions diffuse from the more

concentrated solution (typically formation water) to the more dilute. The ion flow

constitutes electrical current, which generates a small natural potential measured

by the SP tool in millivolts.

When the salinities of mud filtrate and formation water are the same, the potential

is zero and the SP log should be a featureless line. With a fresher mud filtrate and

so, more saline formation water, sandstone will show a deflection in a negative

potential direction (to the left) from a "shale base line". The amount of the

deflection is controlled by the salinity contrast between the mud filtrate and the

formation water. Clean (shale-free) sandstone units with the same water salinity

should show a common value, the "sand line". In practice, there will be drift with

depth because of the changing salinity of formation waters. The displacement on

the log between the shale and sand lines is the "static self-potential" SSP.

The SP log is used to: (1) detect permeable beds, (2) detect boundaries of

permeable beds, (3) determine formation water resistivity (Rw), and (4) determine

the volume of shale in permeable beds. An auxiliary use of the SP curve is in the

detection of hydrocarbons by the suppression of the SP response. The concept of

static spontaneous potential (SSP) is important because SSP represents the

maximum SP that a thick, shale free, porous and permeable formation can have for

a given 'ratio between Rmf / Rw. The SP value that is measured in the borehole is

influenced by bed thickness, bed resistivity, invasion, borehole diameter, shale

content, and most important is the ratio of Rmf / Rw. measurement of SP is

controlled by various factors.

1. Bed thickness.

2. Bed resistivity.

3. Invasion profile.

4. Shale content in permeable bed.

96

APPLICATION

Bed boundaries delineation.

Shale volume determination. Vsh = 1- (SP/SSP).

Formation water resistivity (Rw) determination.

POROSITY LOGS

The three porosity logs are

Density Log

Neutron Log

Sonic Log

DENSITY LOG

Density logging tools contain a Cesium-137 gamma ray source which irradiates

the formation with 662-KeV gamma rays. These gamma rays interact with

electrons in the formation through Compton scattering and lose energy. Once the

energy of the gamma ray has fallen below 100 KeV, photolectric absorption

dominates: gamma rays are eventually absorbed by the formation. The amount of

energy loss by Compton scattering is related to the number electrons per unit

volume of formation. Since for most elements of interest (below Z = 20) the ratio

of atomic weight, A, to atomic number, Z, is close to 2, gamma ray energy loss is

related to the amount of matter per unit volume, i.e., formation density.

96

Fig 7.1.3 Variations in spectrum for formation with constant density but different z

APPLICATIONS OF DENSITY LOG

(1)Measurement of density of formation

(2)Calculation of porosity

(3)When combined with sonic travel times, it is used to calibrate seismic data

(4)Detection of gas in reservoirwhen used in combination with neutron log

(5)PEF is good indicator of lithology

Fig 7.1.4 Schematic drawing of the dual spacing formation density-log

96

The distance between the face of the skid and the extremity of the eccentering arm

is recorded as a caliper log, which helps to assess the quality of contact between

the skid and the formation.

NEUTRON LOG

Neutron porosity logging tools contain an Americium-Beryllium (Am241 – Be9)

neutron source, which irradiates the formation with neutrons having a mean energy

of 4.2 MeV or Californium (Cf252) source. These neutrons lose energy through

elastic collisions with nuclei in the formation. Once their energy has decreased to

thermal level, they diffuse randomly away from the source and are ultimately

absorbed by a nucleus. Hydrogen atoms have essentially the same mass as the

neutron; therefore hydrogen is the main contributor to the slowing down of

neutrons. A detector at some distance from the source records the number of

neutron reaching this point. Neutrons that have been slowed down to thermal level

have a high probability of being absorbed by the formation before reaching the

detector. The neutron counting rate is therefore inversely related to the amount of

hydrogen in the formation.

APPLICATIONS OF NEUTRON LOG

(1)Porosity Determination

(2)Locate gas when combined with Density or acoustic Log

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SONIC LOG

The acoustic velocity log or sonic log is a porosity log that measures interval

transit time (Δt) of a compressional sound wave traveling through one foot of

formation. Transit time is the time required for the wave to travel 1ft of the

formation. The transit time will be more in case of liquid and vice versa. Less

transit time will indicate low porosity, i.e., it is proportional to the porosity. The

sonic log device consists of one or more sound transmitters, and two or more

receivers. Interval transit time (Δt) in microseconds per foot is the reciprocal of the

velocity of a compressional sound wave in feet per second. The interval transit

time (Δt) is dependent upon both lithology and porosity. Sonic porosity can be

used to determine porosity in consolidated sandstones and carbonates with

intergranular porosity or intracrystalline porosity (sucrosic dolomites). In sonic

logging only the first arrivals are noted.

Porosity (Ф) = {(t – tma) / (tf – tma)}

Fig 7.1.5 Schematic diagram of principles of acoustic velocity logging tools.

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8. CONCOLUSION

During the training period, we got an opportunity to know the seismic methods

of prospecting of hydrocarbon. In the first stage, we learned seismic acquisition

techniques with special emphasis on 3D seismic design and the logistic problems

in the field. We visited the camp area and came to know about the functionality of

the instruments during field acquisition. Some software’s were also introduced for

the survey designing like MESSA. For data processing, we used PROMAX

software using which we could learn the different stages of data processing. This

session also improved our mathematical background for the processing.

In the second stage, interpretation techniques were taught with correlation of

other data like well logs and VSP. Different steps of interpretation were introduced

and using geology of the area, some of the sections were interpreted. Log

correlations and synthetic seismogram were also used in this analysis which gives

the true subsurface image of the earth. .

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9. References

.

Yilmaz, Oezdogan, 2001 Seismic Data Analysis Second Edition.

Dobrin M.B., 1949 Introduction to Geophysical Prospecting, McGraw Hill

Publication.

Telford, W.M., Geldart, L.P., Sheriff, R.E., 1990.Applied Geophysics

Second Edition, Cambridge University Press.

Serra, O., 1984 Fundamental of Well Log Interpretation, Elsevier

Publications.

Schlumberger, The essentials of Log Interpretation practice, Schulmberger.

Website References:

http://www.glossary.oilfield.slb.com/

www.expogroup.com

www.petropep.de/w

www.strata.geol.sc.edu

www.wikipedia.com

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