Analysis of Geological & Geophysical

techniques of Petroleum Exploration

Training Report June10-July9 2016 ONGC

Under the Guidance of : Submitted by :

SH. Santanu Mukherjee (DGM Geology) Sparsh Jain

SH. Suryansh Suyash (Geologist)

ACKNOWLEDGEMENT

In this context, I would like to express my sincere gratitude to all the persons without

whom my Industrial Training work in India’s leading Oil and Gas Company, Oil and

Natural Gas Corporation Limited. (ONGC), would not have been possible.

I am thankful to Shri P.H. Mane, GGM - Basin Manager, Frontier Basin who provided me

with the much needed help at any point of time. I render my deep sense of

gratefulness and sincere thanks to Dr. D.K. Srivastava, GM-Block Manager, Vindhyan

Block for rendering me full support & help during the industrial training.

I am also highly indebted to Shri Shantanu Mukherjee, DGM(Geology), Frontier Basin,

ONGC Dehradun, my mentor for his demonstrations, instructions, guidance and

constant support and supervision throughout the course of the training. My deepest

thanks and gratitude goes towards Shri Suryansh Suyash (Geologist, Vindhyan Block)

without whom our project could not have been completed and also to Mr. A.K.

Naithani, DGM (Geophysics), Academy, ONGC, Dehradun for guiding us in the

workshop on SEISMIC API for Academia – Industry Interaction, 2016. I would also like to

thank the members of the Training and Development Department, especially Shri

Sanjay Bhutani, DGM(Chemistry)- ONGC Academy who provided me with the needed

help and administrative support without whom training in ONGC would not have been

possible.

Lastly, I would also like to express my heartfelt thanks to my colleagues for their

continuous help.

Sparsh Jain

Place: Dehradun

ABSTRACT

The current study deals with various aspects of hydrocarbon exploration including a

detailed study of logs interpretation. The set of logs used comprises logs such as

Caliper, Gamma Ray, SP, Sonic and Resistivity. Gamma Ray log and SP log are lithology

logs and their trend depicts the fining or coarsening upwards within a sequence. The

set of logs have been further used to predict the lithology, zone of hydrocarbon

saturation and various other reservoir and petro physical parameters. The logs are

further very useful to estimate the Hydrocarbon saturation in a formation and calculate

the reserve in a given area.

The study also covers an overview of the Vindhyan basin which includes it’s geological

and tectonic settings. A log of one of the wells drilled in that region has been

interpreted. It’s lithology has been identified and an endeavor to calculate it’s water

saturation has been done.

In an unconventional reservoir set-up, with very low porosity and permeability values,

the role of fracture induced secondary porosity becomes very important. The fractured

zones in a well may be delineated using XRMI log which is based on contrast of

resistivity. The log has very high resolution and thereby enables in identifying the highly

fractured zones of interest. The orientation of the fracture data gives an insight into the

paleo-stress regime which prevailed in the area and resulted in generation of the

fractures. The log of Lower Vindhyan Rohtas Formation has been studied in the

following report.

The study also includes the working of one of the most popularly used geophysical

exploration technique i.e. Seismic Survey method which helps in looking at the earth’s

subsurface using the seismic waves which are either used in their natural form (caused

by earthquakes) or created artificially. The study covers all steps involved in this method

starting from seismic data acquisition, its processing and finally its interpretation. It is

used most widely for the exploration of oil and gas all around the world.

CONTENTS

CHAPTER 1

1.1 Introduction to Petroleum Exploration.

1.2 Remote Sensing.

1.3 Geological Field Mapping.

CHAPTER 2

2.1 Geophysical Techniques for Petroleum Exploration.

2.2 Seismic Acquisition.

2.3 Seismic Data Processing.

2.4 Seismic Data Interpretation.

CHAPTER 3

3.1 Well Logging

3.2 Typical Well Log of Clastic Reservoir

A) Interpretation

B) Reservoir Quantitative Analysis

3.3 Typical Well Log of Non Clastic Reservoir

A) Interpretation

B) Reservoir Quantitative Analysis

3.4 Volumetric Analysis

3.5 XRMI

CHAPTER 4

Reservoir Dynamics

CHAPTER 5

5.1 The Vindhyan basin-A case Study

5.2 Brief Geology of the area and Petroleum System

5.3 Son Valley Log, Vindhyan Basin (WELL A)

5.4 XRMI Log of Vindhyan Basin

1.1 Introduction to Petroleum Exploration

Petroleum exploration is a very old pursuit. The market for liquid hydrocarbons expanded

rapidly in the mid­nineteenth century. Initially the demand was satisfied by oil shales and from

oil in natural seeps, pits, hand-dug shafts, and galleries. Before exploration for oil began, cable-

tool drilling was an established technique in many parts of the world in the quest for water and

brine. Present-day exploration for 0il and gas calls upon a wide variety of professional skills.

Those require in-depth knowledge of the disciples in Earth Sciences such as geology,

geophysics and geochemistry, associated with engineering and data acquisition techniques

such as well logging, seismic lines acquisition, treatment and interpretation, remote sensing,

etc. The process relies on the methodical application of technology by creative geoscientists

that leads to viable prospects to drill and the actual drilling of these prospects with exploratory

and appraisal wells. It is the commitment of large amounts of risk capital to explore prospects

that have an uncertain outcome. Petroleum is the result of the deposition of plant or animal

matter in areas that are slowly subsiding. These areas are usually in the sea or along its

mar­gins in coastal lagoons or marshes and occasionally in lakes or inland swamps. Sediments

are deposited along with the organic matter, and the rate of depo­sition of the sediments must

be sufficiently rapid that at least part of the organic matter is preserved by burial before being

destroyed by decay. As time goes on and the area continues to sink slowly [because of the

weight of sediments deposited or because of regional (tectonic) forces], the organic material is

buried deeper and hence is exposed to higher tem­peratures and pressures. Eventually

chemical changes result in the generation of petroleum, a complex, highly variable mixture of

hydrocarbons, including both liquids and gases (part of the gas is in solution because of the

high pressure). Ultimately the subsi­dence will stop and may even reverse.

Exploration work flow

1.2 Remote Sensing

Remote sensing is the science (and to some extent, art) of acquiring information about the

Earth's surface without actually being in contact with it. This is done by sensing and recording

reflected or emitted energy and processing, analyzing, and applying that information. the

process involves an interaction between incident radiation and the targets of interest. This is

exemplified by the use of imaging systems where the following seven elements are involved.

1. Energy Source or Illumination (A)

2. Radiation and the Atmosphere (B)

3. Interaction with the Target (C)

4. Recording of Energy by the Sensor (D)

5. Transmission, Reception, and Processing (E)

6. Interpretation and Analysis (F)

7. Application (G)

1.3 Geological Field Mapping

Mapping geologic units consists primarily of identifying physiographic units and determining

the rock lithology or coarse stratigraphy of exposed units. These units or formations are

generally described by their age, lithology and thickness. Remote sensing can be used to

describe lithology by the color, weathering and erosion characteristics (whether the rock is

resistant or recessive), drainage patterns, and thickness of bedding.

Unit mapping is useful in oil and mineral exploration, since these resources are often associated

with specific lithologies. Structures below the ground, which may be conducive to trapping oil

or hosting specific minerals, often manifest themselves on the Earth's surface. By delineating

the structures and identifying the associated lithologies, geologists can identify locations that

would most feasibly contain these resources, and target them for exploration.

But, the geological information from outcrops and the addition of

remote sensing and GIS technology greatly enhances our ability to

locate areas where further subsurface studies are to performed,

thereby reducing the risk of failure of locating the correct spot and

hence making it cost-effective. The selection of effective

exploration targets is an important step in achieving success in

hydrocarbon exploration. Integrating geological cross-sections

with the sub-surface structural trends leads to interpretation of

accurate geometric shapes of sedimentary basins and thus the

identification of prospect areas.

In reality, the topography, structure, surficial materials, and vegetation combine to facilitate

geologic unit interpretation and mapping. Optimal use of remote sensing data therefore, is one

that integrates different sources of image data, such as optical and radar, at a scale appropriate

to the study.

Even once geological unit maps are created, they can still be presented

more informatively by encompassing the textural information provided

by SAR data. A basic geological unit map can be made more

informative by adding textural and structural information. In this

example of the Sudbury, Ontario region, an integration transform was

used to merge the map data (bedrock and structural geology

information, 1992) with the SAR image data. The resulting image can be

used on a local or regional scale to detect structural trends within and

between units. The areas common to each image are outlined in black

2.1 Geophysical Techniques of Petroleum Exploration

Petroleum exploration and production are largely concerned with the geological interpretation

of geophysical data, especially in offshore areas. Petroleum geol­ogists need to be well

acquainted with the methods of geophysics. The following account of geophysical methods of

petroleum exploration has two objectives. It seeks to explain the basic principles and to

illustrate the wonders of modern geophysical display.

Three main geophysical methods are used in petroleum exploration: mag­netic, gravity, and

seismic. The first two of these methods are used only in the predrilling exploration phase.

Seismic surveying is used in both exploration and development phases and is by far the most

important of the three methods.

Gravity Survey

Gravity surveying measures spatial variations in the Earth's gravitational field caused by

differences in the density of sub-surface rocks In fact, it measures the variation in the

acceleration due to gravity. It is expressed in so called gravity anomalies (in milligal, 1 o-5 ms-2),

i.e. deviations from a predefined reference level, geoid (a surface over which the gravitational

field has equal value). Gravity is a scalar. Gravity prospecting involves measurements of

varia­tions in the gravitational field of the earth. One hopes to locate local masses of greater or

lesser density than the surrounding formations and learn something about them from the

irregularities in the earth's field. It is not possible, however, to determine a unique source for an

observed anomaly. Observa­tions normally are made at the earth's surface, but underground

surveys also are carried out occasion­ally.

Gravity prospecting is used as a reconnaissance tool in oil exploration; although expensive, it is

still considerably cheaper than seismic prospecting. Gravity data are also used to provide

constraints in seismic interpretation. In mineral exploration, grav­ity prospecting usually has

been employed as a sec­ondary method, although it is used for detailed fol­low-up of

magnetic and electromagnetic anomalies during integrated base-metal surveys.

Magnetic Survey

Magnetic and gravity methods have much in com­mon, but magnetics is generally more

complex and variations in the magnetic field are more erratic and localized. This is partly due to

the difference between the dipolar magnetic field and the monopolar gravity field, partly due to

the variable direction of the magnetic field, whereas the gravity field is always in the vertical

direction, and partly due to the time­dependence of the magnetic field, whereas the grav­ity

field is time-invariant (ignoring small tidal varia­tions). Whereas a gravity map usually is

dominated by regional effects, a magnetic map generally shows a multitude of local anomalies.

Magnetic measurements are made more easily and cheaply than most geophysical

measurements and corrections are practically unnecessary. Magnetic field variations are of­ten

diagnostic of mineral structures as well as re­gional structures, and the magnetic method is the

most versatile of geophysical prospecting techniques. However, like all potential methods,

magnetic meth­ods lack uniqueness of interpretation.

Seismic Method for Exploration

It is the most popularly used geophysical exploration technique i.e. The Seismic Survey method

which helps in looking at the earth’s subsurface using the seismic waves which are either used

in their natural form (caused by earthquakes) or created artificially. It includes seismic data

acquisition, its processing and finally its interpretation. It is used most widely for the exploration

of oil and gas all around the world.

2D Seismic Survey

The seismic method is by far the most important geophysical

technique in terms of expenditures (see Table 1.1) and number of

geophysicists involved. Its predominance is due to high accuracy,

high resolu­tion, and great penetration. The widespread use of

seismic methods is principally in exploring for petroleum: the

locations for exploratory wells rarely are made without seismic

information. Seismic meth· ods are also important in groundwater

searches and in civil engineering, especially to measure the depth

to bedrock in connection with the construction of large buildings,

dams, highways, and harbor surveys. Seismic techniques have

found little application in direct exploration for minerals where interfaces be­tween different

rock types are highly irregular. How­ever, they are useful in locating features, such as buried

channels, in which heavy minerals may be accumulated. Much seis­mic work consists of

continuous coverage, where the response of successive portions of earth is sampled along lines

of profile. The basic technique of seismic exploration con­sists of generating seismic waves and

measuring the time required for the waves to travel from the sources to a series of geophones,

usually disposed along a straight line directed toward the source. From a knowledge of travel

times and the velocity of the waves, one attempts to reconstruct the paths of the seismic waves.

Seismic data or a group of seismic lines acquired individually such that there typically are

significant gaps (commonly 1 km or more) between adjacent lines. A 2D survey typically

contains numerous lines acquired orthogonally to the strike of geological structures (such as

faults and folds) with a minimum of lines acquired parallel to geological structures to allow line

to line tying of the seismic data and interpretation and mapping of structures.

The seismic data recorded by 2-D survey is seismic line.

3D Seismic Survey

The acquisition of seismic data as closely spaced receiver and shot lines such that

there typically are no significant gaps in the subsurface coverage. The seismic data

recorded by 3 D survey is seismic cube.

Types of Seismic arrays (spread):

A. Split Dip Spread: the source in center of spaced geophone groups.

• Split dip Spread: source is in line with geophone groups with no gaps.

• Deviated dip Spread: source is deviated by small distance perpendicular to the line.

• Gapped dip Spread: geophone groups near the source is

turned off

B. End on Spread: the source is at one end of geophone

groups

C. Broad Side Spread: source has offset 500-1000m

perpendicular to seismic line.

• T Broad side spread: source is opposite the line center.

• L Broad side spread: source is opposite one end of the line.

Geophones Arrays

1. Longer arrays attenuate more ground roll.

2. Longer arrays also attenuate high frequency components from reflections, Shallow

reflections have longer reflections.

3. New processing software makes a good difference and handle surface wave efficiently.

4. Modern recording system with high dynamic range can handle amplitude noise, low

amplitude signals from deeper depths.

5. In 3D seismic waves, we can measure thousand’s of arrays of channels.

Geophones Plantation

In coupling of geophones, we have following benefits

1. Good Coupling

2. Protection from bend noise

3. It should be properly fix inside so that good interaction with reflectors.

Equipments, Sources and Detectors

Land:

• Conventional survey instruments such as Theodolite.

•Electromagnetic distance devices (EDM)

•Global positioning system (GPS), which is

commonly, used method.

Marine:

•Radio positioning, Transit satellite positioning

• Streamer locations by using Tail Buoy

• Global positioning system.

A.Impulsive sources: which are divided to Explosive

sources such as Dynamite

(common in Petroleum exploration), and Non Explosive

such as Weight drop &

Hammers (common in shallow seismic investigation).

B.Non impulsive sources: The main common is

Vibroseis which is a designed

vehicle lift its weight on large plate in contact with

ground surface in sweeps.

• Up Sweep: Frequency begins low & increase with time.

• Down Sweep: Frequency begins high & decrease with time.

Land detectors (Geophone):

It is a device is used to detect the sound waves. It consists of coil of wire suspended from spring

& surrounded by (W) shaped magnet. Upward energy from seismic source is recorded as

electrical current generated by movement of coil.

Marine detectors (Hydrophone):

It is a device used to detect the pressure waves. Upward energy is

recorded as electrical current generated by piezoelectric device

(which generates a voltage if acted with pressure).

2.2 Seismic Acquisition:

It is the generation and recording of seismic data. Acquisition involves many different receiver

configurations, including laying geophones or seismometers on the surface of the Earth or

seafloor, towing hydrophones behind a marine seismic vessel to record the seismic signal. A

source, such as a vibrator unit, dynamite shot, or an air gun, generates acoustic or elastic

vibrations that travel into the Earth, pass through strata with different seismic responses and

filtering effects, and return to the surface to be recorded as seismic data.

Requirements and Methodology

Elements of a seismic reflection data acquisition system include the following:

1. Surveying/navigation system - Precise locations of source and receiver positions must be

known.

2. Energy sources - Seismic waves having appropriate amplitudes and frequency spectra must

be generated.

3. Receivers - Seismic waves must be detected and converted into electrical signals.

4. Cables -Signals output from the receivers must be transmitted to the recording system with

minimum attenuation and distortion.

5. Recording system- Signals transmitted via the cables must be recorded in a form that

provides easy retrieval while preserving as much as possible of the information contained in the

original signal.

Variations in seismic data acquisition methodology depend upon whether 2-D or 3-D data are

to be acquired and whether the environment in which data are collected is land, marine, or

ocean-bottom.

Objectives of Seismic Data Acquisition

1) To maximize the recording of primary reflections & minimize the recording of noise i.e.

Maximum S/N ratio.

2) Record a high resolution data that fulfils the exploration objects.

3) Ensure continuous coverage

4) In cost effective and environmentally sensitive manner.

5) Acquisition Geometry and field parameters.

6) Topographic survey methods and accuracy.

7) Quality of ground electronics and recording instrument.

8) Near surface conditions.

9) Logistics and socio-economic environment.

10) Field practice.

2.3 Seismic Data Processing:

Alteration of seismic data to suppress noise, enhance signal and

migrate seismic events to the appropriate location in space.

Processing steps typically include analysis of velocities and

frequencies, static corrections, Deconvolution, normal moveout,

dip moveout, stacking, and migration, which can be performed

before or after stacking. Seismic processing facilitates better

interpretation because subsurface structures and reflection

geometries are more apparent.

Editing:

Step is used to remove bad traces, noisy channels or open channels.

Muting:

Zero out arrivals that are not primary P-wave

reflections.

Deconvolution:

A step in seismic signal processing to recover high frequencies, attenuate multiples, equalize

amplitudes, produce a zero-phase wavelet or for other purposes that generally affect the wave

shape. Let’s consider a simple case as shown in figure.

In ideal case, Geophone still stationary until the first reflection arrived, then it makes one

movement & return to its stationary position again so the ideal seismogram reflections shows a

series of spikes. In real case, Seismogram for these layers would be presented by short

wavelets. Because spike passes through earth layers which act as a filter & applies an operator

to Spike & transform it into short wavelets, applying this operator known as Convolution.

The process used to return short wavelets to spikes known as Deconvolution.

Types of filters:

• Band-Pass filter:

This filter doesn’t alter phase, only extract a defined band of frequencies.

Any high or low frequencies outside this range will be attenuated.

Low-Cut filter (High pass):

In this case, the analysts only want to eliminate low frequencies. Low-cut

filter is used to filter out low frequency Ground Roll.

High-Cut filter (Low-Pass):

In this case, the analysts only want to eliminate high frequencies.

Notch filter:

It is used to filter out narrow band of frequencies within frequency range

of Data. The most common use of this filter is to attenuate noises caused

by power lines.

Variable amplitude spectrum filter:

In this case, the analysts don’t want to keep the amplitude of filter constant.

This type of filters is used for special processing.

Techniques for Corrections of Seismic Data

Static correction:

It is often called statics, a bulk shift of a seismic trace in time

during seismic processing. A common static correction is the

weathering correction, which compensates for a layer of low

seismic velocity material near the surface of the Earth. Other

corrections compensate for differences in topography and

differences in the elevations of sources and receivers.

Elevation method

For each station, there is an elevation is measured. This difference in

elevation causes the horizontal reflector appears as curved. So this

method is used to shift all of data up or down to datum level.

Uphole method:

This method is used to estimate the thickness & velocity of weathered layer. This

method involves drilling a hole into the weathering layer (up to 300ft) An uphole

geophone placed near the hole & a seismic source (usually charges of dynamite)

are set in the hole The geophone records seismic waves at each depth. These

depths & times can be plotted on Time-distance curve from time-distance curve,

we can estimate the thickness & velocity of LVL (low velocity layer).

Refraction method:

The refractions or first breaks can be used to calculate statics, By measuring Δt & Δd values for

the first refraction line, we can estimate the velocity of LVL.

CDP and CMP stacking

Common depth point defines as sum of traces which

correspond to the same subsurface reflection point but

have different offset distances.

At this step, we gather these CDP traces & then

integrate all of these traces as one trace (Stacking).

The main reason of using CDP method is to improve

the signal to noise ratio of data because when trace is summed, signals can be built where

random noise can be cancelled.

Before stacking, the traces must be shifted to its original place by NMO.

Normal Move out (NMO):

The effect of the separation

between receiver and

source on the arrival time of

a reflection that does not

dip, abbreviated NMO. A

reflection typically arrives

first at the receiver nearest

the source. The offset

between the source and

other receivers induces a

delay in the arrival time of a

reflection from a horizontal

surface at depth. A plot of arrival times versus offset has a hyperbolic shape.

Move out correction is time correction applied to each offset.

Advantages of CDP

1. Reduction of Noise

2. Attenuation of Multiples.

3. The redundancy in CDP surveys is more tolerant skipped shorts or receiver locations.

4. Send more energy into subsurface

5. Generate more signals, less noise

Why Seismic Data Processing

1. After Processing Raw data looks like

geological

2. To improve S/N ratio

3. To meet Exploration objectives of client.

Migration

A step in seismic processing in which reflections in seismic data are moved to their correct

locations in the x-y-time space of seismic data, including two-way travel time and position

relative to shot points .Migration improves seismic interpretation and mapping because the

locations of geological structures, especially faults, are more accurate in migrated seismic data.

It attends to deal with diffractions & dipping interfaces.

Types of Migration:

• Time Migration: A migration technique for processing seismic data in areas where lateral

velocity changes are not too severe, but structures are complex. Time migration has the effect

of moving dipping events on a surface seismic line from apparent locations to their true

locations in time.

• Depth Migration: A step in seismic processing in which

reflections in seismic data are moved to their correct

locations in space, including position relative to shot points,

in areas where there are significant and rapid lateral or

vertical changes in velocity that distort the time image. This

requires an accurate knowledge of vertical and horizontal

seismic velocity variations.

• Pre Stack Depth Migration: if the migration process

occurred before stacking.

• Post Stack Depth Migration: if the migration occurred after stacking.

Post Stack Processing:

Sometimes, we have a seismic section & already had been processed in past but we need to

enhance & filtering this data again.

Usually, this data came in seismic section papers (not in tapes), So at first we scan this data &

convert it to SEG-Y format by Vectorization process.

Sometimes also, we digitize the shot point maps & put X-Y directions in the SEG-Y trace

header.

Post Stack Processing steps:

• Resampling: convert the trace into digital form (or from 2ms to 2ms for example).

• Interpolation: is to estimate a synthetic trace between two traces.

• AGC & Trace Balance: is automatic gain control is used to build up weak signals.

• Trace Mix: control the gain like AGC but laterally (from trace to other).

2.4 Seismic Data Interpretation

Seismic interpretation provides an assessment of a prospect’s hydrocarbon potential and, if

favourable, identifies best locations for drilling wells. It is used to generate reasonable models

and predictions about the properties and structures of the subsurface. To start interpretation,

We must have:

• Base Map: shot point location

• Seismic sections: Inline & Crossline

• Available Wells:

• Velocity data from wells : from Check Shot, VSP.

• Formation Top of the well: to determine the top of horizon

• Logs & reports : Sonic, GR, Density & other logs.

Steps for Interpretation

1-Loading the data:

• Seismic sections: (post stack data).

• Available Wells data: Well logs & formation tops

• Velocity Data of wells: from Check-shot survey or Vertical Seismic

Profiling.

2-Picking interested Horizon:

Picking is a reflection on a seismic section. It involves

deciding what wiggles from trace to trace are from the same

reflection.

3-Well Tie: We create a Synthetic Seismogram to know the

accurate location of the formation tops of intersected horizon

then tie it with the seismic section. Synthetic indicates also

that if the horizon response is peak or trough. From the well,

we know the depth of the event (Formation tops). From

plotting values of depths & times which came from the

check-shot survey, we can extract the time value for certain depth ( to mark that depth on

seismic section).

a-Arbitrarily Line:

It is a seismic line contains the data of the available wells (called

also Key line in 2-D interpretation). This line contain the most

accurate data because it contains a real data about the depth of

interested horizon became from already drilled wells.

This arbitrary line is determines from a map view of data then

flattened as one seismic section in section view. Then, we

determine the formation tops under each well to mark the

horizon location.

In 2-D interpretation case, we use the Key line as a reference line.

The Key Line is a seismic line passes through which contain many

wells data as much as possible.

Structure:

It is finding & marking structures at the horizon (Faults for example).

We pick the fault on seismic section & find it at the other seismic

lines. The fault in seismic section is called Fault Segment. The fault on map view is called Fault

Polygon.

Picking

We start marking of intersected horizon under each well in

the arbitrary line. Then, complete picking the horizon in the

seismic line.

b-Loop

Loop is tie between Inline & Crossline. The main idea of loop,

is to correlate between two line have the same shot point

(one of them is accurate data) to detect the interested

horizon accurately at the unknown one. we start to pick the

horizon at the crossline. Then we repeat this process to

complete the loop, & run the process to pick the horizon at all lines.

Mis-Tie:

The same event doesn`t have the same absolute

values. A situation in interpretation of seismic

data in which predicted and actual values differ,

or when an interpreted reflection does not close,

or tie, when interpreting intersecting lines.

Static Shift: when the difference is constant at all

horizons & fixed easily by Mis-Tie analysis

Correction.

Dynamic Shift: The difference is not constant & fixed by specific softwares & sometimes, we

just adjust the interested horizon & don’t care about the other horizons.

4-Two Way Time Map: (TWT)

At first, we take the time values of horizon at each shot point. Then, put these values at the line

on base map. Repeat this step at each line. After that, contour these values to get TWT map

with

suitabl

e

conto

ur

interv

al.

5-Velocity map: First, put the average velocity determined at each well. The average

velocities in well became from Check-shot survey or VSP (from time/depth scale in check-shot

we can determine the velocity). then, we repeat this step at each well in survey area &

contouring the velocity values of wells to get Velocity map.

6-Depth contour map:

We extract the depth map values from the velocity & one way time map. The depth converted

map shows the depths of intersected horizon. we usually prefer to drill at the higher areas

(which called hot areas).

Things to consider

• We must know the datum of survey (datum survey in seismic called Seismic reference datum).

• If the Check-shot time is one way time, we must convert it to two way time.

• We must know the type of well depth (TVD, MD, or TVD subsea).

• If there is no well, we choose the section which has most clearly structures & keep it as a

reference line

• The direction of faults in arbitrary line depend on level of formation tops at each well

• The dip angle of faults depend on the bottom of horizon.

• The seismic line must be perpendicular to fault to show fault on seismic section.

• Before contouring, First we load the fault polygons on map

• The contour map must have: Map name: (ex: Al-Dol time map), Contour Interval: (ex: 20ms),

Scale: (ex: 1:100000), Scale Bar: . 5km .

• The velocity required for the map is Average velocity

• If there is no wells in area, we use velocity extracted from seismic data

• In this case, we use the Stacking Velocity or RMS velocity.

• These velocities is estimated by Velocity Analysis.

• In case of determining velocity from check-shot survey, the result velocity will multiplying by 2

(to convert it to one way time).

• Ex: if the time is 1980ms & depth is 8000ft, so the velocity will equal.

• At most cases, the shape of two way time map is look like the Depth map

• If there is a closure occurred in TWT map & not existed in Depth map, the error usually come

from the velocity map then try to fix it.

• If there is a closure occurred in Depth map & not existed in TWT map, so there is a big error

occurred & can`t to drill in this closure depending on Depth map only.

• The values in TWT map must be divided by 2 (to convert it to One Way Time map).

3.1 Well Logging

This study deals with the study and interpretation of logs to interpret the lithology of sub-

surface formation. The set of logs used comprises logs such as Caliper, Gamma Ray, SP, Sonic

and Resistivity. Gamma Ray log and SP log are lithology logs and their trend depicts the fining

or coarsening upwards within a sequence. The set of logs have been further used to predict the

lithology, zone of hydrocarbon saturation and various other reservoir and petro physical

parameters. The logs are further very useful to estimate the Hydrocarbon saturation in a

formation and calculate the reserve in a given area. Well logging is the process of recording

various petro-physical properties of rock/formations penetrated by drilling. Log responses are

functions of lithology, porosity, fluid–content and textural variation of formation. This

information coupled with characteristics of sedimentary structures derived from high resolution

dipmeter surveys provide detailed insight into the sedimentary environment and allows

estimation of the reservoir geometry & orientations. As such, logs are ideal tools not only for

quantitative evaluation of fluid content of each potential reservoir but also for understanding

the geometry of the reservoir.

WELL LOGGING – The Eye of Oil Industry

Well logging provides a cheaper, quicker method of obtaining accurate sub-surface petro-

physical data. Well Logging measurements can:

• Ascertain hydrocarbon potential of the well.

• Determine hydrocarbon type and volume.

• Determine what types of fluid will flow and at what rate.

• Optimize well construction and hydrocarbon production.

Well Logging finally serves to:

• Identify Hydrocarbon Reservoirs.

• Define Total and Recoverable Reserves

Well logging Techniques

Well Logging Measurements are carried out through the drilled borehole. The drilled borehole

may be either an Open Hole or a Cased Hole.

•Open Hole: A borehole drilled in the formation, usually available immediately after drilling. All

basic petro-physical measurements for Formation Evaluation.

•Cased Hole: A borehole where steel casing pipes have been placed and cemented suitably.

Measurements mostly concern with Reservoir Development & Production.

Process: Modern drilling uses a lubricating mud that is pumped down through the drill pipe

to cool and lubricate the drilling area. The drilling mud is usually a mixture of bentonite clay

and oil or water, plus barite to regulate density. It is forced up the well to the surface so that

mud constantly flows toward the mud tanks, carrying the cuttings, or chips, away from the

drilled formation to prevent the well from clogging. These chips are a primary source of

information about the subsurface unit. The site geologist usually keeps a continuous log and

sample of the chips as they come up and are screened out of the drilling mud. The chips are

the only record of the lithology. If the density of one unit greatly differs from the next the chips

may rise to the surface at different rates and give an erroneous impression of the sequence.

Tools of well logging: - In well logging two types of tools are used.

A. Basic log

B. Advanced log

Basic log: - we have seven basic log and these are as follows:-

i.) Caliper log: - A tool that measures the diameter of the borehole, using either 2 or 4

arms. It can be used to detect regions where the borehole walls are compromised and the well

logs may be less reliable.

ii.) Gamma Ray log: - A log of the natural radioactivity of the formation along the

borehole, measured in API, particularly useful for distinguishing between sands and shales in a

clastic environment. This is because sandstones are usually nonradioactive quartz, whereas

shales are naturally radioactive due to potassium isotopes in clays, and adsorbed uranium and

thorium.

iii.) Self/spontaneous potential: - The Spontaneous Potential (SP) log measures the natural

or spontaneous potential difference between the borehole and the surface, without any applied

current. It was one of the first wire line logs to be developed, found when a single potential

electrode was lowered into a well and a potential was measured relative to a fixed reference

electrode at the surface.

iv.) Neutron porosity: - The neutron porosity log works by bombarding a formation with

high energy epithermal neutrons that lose energy through elastic scattering to near thermal

levels. The neutron porosity log is predominantly sensitive to the quantity of hydrogen atoms in

a particular formation, which generally corresponds to rock porosity.

v.) Density: - The density log measures the bulk density of a formation by bombarding it

with a radioactive source and measuring the resulting gamma ray count after the effects of

Compton Scattering and Photoelectric absorption. This bulk density can then be used to

determine porosity.

vi.) Sonic log: - A sonic log provides a formation interval transit time, which typically varies

lithology and rock texture but particularly porosity.

vii.) Resistivity log: - Resistivity logging measures the subsurface electrical resistivity, which is

the ability to impede the flow of electric current.

Advanced log: - logs which come under this are as follows :-

i.) NMR (Nuclear Magnetic Resonance) :- Nuclear magnetic resonance (NMR) logging uses

the NMR response of a formation to directly determine its porosity and permeability, providing

a continuous record along the length of the borehole.

ii.) Dip meter: - It computes bed dips and azimuths by recording micro resistivity curves

around the borehole wall.

iii.) XRMI (X-tended Range Micro Imager) :- It is a micro recording resistivity tool with high

vertical resolution. This can then be used to identify the presence and direction of rock

fractures, as well as understanding the dip direction of the stratigraphy

3.2 Log Interpretation (Clastic)

A typical combo-log of an area with known clastic depositional environment was used for

interpretation of lithology, associated reservoir parameters, nature of fluid and the depositional

history and environment of the area. The log set consisted of Spontaneous Potential, Gamma

Ray, Caliper, Resistivity, Neutron Porosity, Density and Sonic logs.

Unit:-2840 to 2821 m

Caliper log curve shows 8 inch as compared to the 8.5 inch bit used. This indicates that the well

bore has a mud cake of 0.5 inch at the particular depth. The formation of mud cake indicate the

porous and permeable nature of the rock formation at this depth. Here, at a depth of 2837 to

2833m and 2823 to 2822m curve shows slight increase in its value i.e. from 8.5 to 9.5 inches

which shows that slight caving is present. This indicates presence of clay rich layer/ shale at the

particular depth which might have caved leading to larger borehole size.

Gamma Ray count is highly variable from 2840 to 2832m depth and becomes

monotonous from depth of 2832 to 2824 m. At the base of this zone the GR count is

high i.e. 70 API which denotes higher radioactivity. Higher gamma ray count indicates

presence of shale, thereby impermeable layer is present. From the depth of 2839 to

2838m the GR count is decreasing and goes upto 38 API which indicates increase of

silt/sand content in the system and thus increasing proportion of permeable rock.

Above this, in the interval between 2838 to 2833m GR count is variably increasing

which again shows an increase of shale content and thereby increase of impermeable

rock. From the depth of 2832 to 2824 m GR value shows 20 API which indicate less

radioactivity, so this indicate a zone of clean (shale free) permeable rock. In the upper

3m of this zone the GR counts again slightly increase which shows increase in

radioactivity therefore increase in impermeable rock proportion.

SP (Spontaneous Potential) is nearly monotonous and indefinable because of the poor

contrast in salinity of mud filtrate and formation water.

The Resistivity curve shows very high value in between 2823 to 2832 m. Therefore this

zone may be hydrocarbon bearing. Below and above this the resistivity curves show

very less value due to increase in shaliness. Here all the three curves are not

superimposed because VR (vertical resolution) of LL3 is more than ILD & ILM. So LL3

gives the resistivity of flushed zone and ILD gives the resistivity of un-invaded zone and

ILM gives the resistivity of transition zone.

Neutron-Density log, we get a cross over between neutron density curves at the depth

of 2,833 to 2,823 m, Neutron-Density separation (ɸd - ɸn) is 0.15 which is less and shows

that the hydrocarbon of this depth is Oil, so this is oil bearing horizon. This cross over

occurs due to matrix effect which indicates that this reservoir rock is Sandstone. Above

this depth i.e. from 2823 to 2821 m there is moderate separation between neutron-

density curve due to increases in shaliness and this indicate Sandy-shale. Below this

depth i.e. from 2,840 to 2,833m there is very large separation between neutron-density

curve due to increases in shaliness and this indicate that the impermeable formation

rock is Shale.

In Sonic log, the transit time curve follows more or less similar curve as neutron

porosity curve. At the depth of 2,832 to 2,823 m the transit time decreases which also

gives an indication of presence of hydrocarbon oil. Below and above this the transit

time is increases which is due to increase of shaliness in the formation.

Unit: 2821-2820m

Caliper log shows increase in bore whole width which indicates caving is occur.

Gamma Ray log shows high value which indicate high radioactivity. This indicates

increase of shaliness and thus a zone of porous and impermeable rock.

SP (Spontaneous Potential) curve is not very well defined. In this zone SP curve is

running corresponding to its GR curve so in this zone we have normal SP curve.

All three Resistivity curves are not superimposed in this porous and impermeable zone

due to some tool defect.

Neutron – Density curves are separating from each other and go towards there higher

values. This indicates that this porous and impermeable rock formation is Shale.

Sonic log curves show higher DT value which shows highly porous formation (i.e. Shale).

Unit:-2,820 to 2,803 m

Caliper log curve showing 8 inch value at the depth of 2,820 – 2,808 m which indicates

formation of 0.5 inch mud cake.

GR log value increases from 2,808 to 2,803 which show increases in radioactivity and

thereby shaliness.

SP (Spontaneous Potential) is not well defined.

Resistivity curves show low values and all are differing from each other due to

presence of porous and permeable rock formation. Therefore LL3 gives resistivity of

flushed zone (high VR), ILM gives resistivity of transition zone and ILD gives resistivity of

un-invaded zone.

Neutron – Density logs show cross over from the depth of 2,818 to 2,808 m with good

amount of porosity. Above this upto the depth of 2,806 m there is separation between

these two curves are very large which shows presence of shale and upto the depth of

2,803 neutron and density curves comes closer which indicate decrease in shaliness.

In Sonic log, the transit time curve follows more or less similar curve as neutron

porosity curve. It shows higher value in shale relative to sandstone.

Unit:-2,803 to 2,792 m

Caliper log curve shows no caving.

GR log shows increase of radioactivity and thereby shale content.

SP (Spontaneous Potential) is not well defined.

Resistivity curves shows very less values and all three Resistivity curves are not

superimposed in this porous and impermeable zone due to some tool defect.

Neutron – Density curves are separating from each other and go towards there higher

values. This indicates that this porous and impermeable rock formation is Shale.

Sonic log curves show higher value which shows highly porous formation (i.e. Shale).

Unit:-2,792 to 2,776 m

Caliper log shows 8 inch values from 2,792 to 2,784 m which denotes the formation of mud

cake at this depth. So this depth interval is porous and permeable till the depth of 2,776 m

caliper value indicates that caving is taking place.

In this unit GR values are highly variable, at the depth interval of 2,792 to 2,784 m value

is less which indicate very less amount of radioactivity and till the depth of 2,776m GR

value is increasing therefore radioactivity is also increasing. Thus the layer shows

alternate sand-shale sequence.

SP (Spontaneous Potential) is not well defined but it follows the same path as GR log.

From 2,792 to 2,784 resistivity curves shows high values which indicate that this porous

and permeable rock is hydrocarbon bearing. Above this, values start decreasing due to

increase in shaliness.

Neutron –Density curves shows cross over at the depth interval of 2,792 to 2,784 m.

Here (ɸd-ɸn =.09 pu) and also a higher resistivity value as seen in resistivity log indicates

that this zone is hydrocarbon (Oil) bearing. Above this the neutron – density curves

started separating which is due to increases in shaliness.

Sonic curves follows more or less similar path as neutron porosity curves.

Unit:-2,776 to 2,772 m

Caliper log shows increase in bore whole width which indicates caving has occur.

Gamma Ray log shows high value which indicate high radioactivity, so this indicate

higher shale content and a zone of porous and impermeable rock.

SP (Spontaneous Potential) curve is not very well defined.

All three Resistivity curves are not superimposed in this porous and impermeable zone

due to some tool defect.

Neutron – Density curves are separating from each other and go towards there higher

values. This indicates that this porous and impermeable rock formation is Shale.

Sonic log curves show lower value which shows highly porous formation (i.e. Shale).

3.2.B QUANTITATIVE ANALYSIS OF CLASTIC RESERVOIR

Estimation of Water Saturated Formation Resistivity- Depth from 2,808 to 2,820 m.

Actual porosity :-

ɸn = .18+.045=0 .225=22.5%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.65 – 2.25)/1.65 = 24.2% [ρma= 2.65 for Sst]

ɸ = (ɸd+ɸn)/2

= (0.242+0.225)/2

= (.467)/2

= 0.2335

= 23.35%

By Archie’s Equation

Sw2= a Rw/ɸmRt =1

Rw = ɸmRt / a

Here, m=2 & a=0.81 (reservoir is sandstone)

Rw= (0.2335)2 × 3/0.81

= 0.2019 Ω-m

Estimation of hydrocarbon Oil Saturation –

1) Depth from 2,833 to 2,823 m

ɸn = .18+.045=0 .225=22.5%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.65 – 2.25)/1.65 = 24.2%

Actual porosity :-

ɸ = (ɸd+ɸn)/2

= (0.242+0.225)/2

= 0.467/2

= 0.2335

= 23.35%

By Archie’s Equation

Sw2= a Rw/ɸmRt

Here Rw = 0.2019Ω-m, Rt = 240Ω-m, m=2 & a=0.81 (reservoir is sandstone)

Sw2= (0.81×0.2019)/ (0.335)2×100 = 0.125

Sw = (0.125)1/2

= 0.1118

Hydrocarbon Oil saturation :-

Sh=1- Sw

= 1-0.1118

= 0.888

= 88.8%

2) Depth from 2,792 to 2,784 m

Actual porosity :-

ɸn = .21+.045=0 .255=25.5%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.65 – 2.25)/1.65 = 24.2%

ɸ = (ɸd+ɸn)/2

= (0.242+0.255)/2

= 0.497/2

= 0.2485

= 24.85%

By Archie’s Equation

Sw2= a Rw/ɸmRt

Here Rw = 0.2019Ω-m, Rt = 20Ω-m, m=2 & a=0.81 (reservoir is sandstone)

Sw2= (0.81×0.2019)/ (0.2485)2×20

= (0.1539)/1.458

Sw2 = 0.1324

Sw = (0.1324)1/2

= 0.3638

Hydrocarbon Oil saturation :-

Sh=1- Sw

= 1-0.3638

= 0.636 = 63.6%

Interpreted Log:-

A typical combo-log of an area with known clastic depositional environment was used for

interpretation of lithology, associated reservoir parameters, nature of fluid and the depositional

history and environment of the area. The log set consisted of Spontaneous Potential, Gamma

Ray, Caliper, Resistivity, Neutron Porosity, Density and Sonic logs.

Unit:-1,400 to 1,382 m

The caliper log curve is nearly monotonous and showing 8.5 inches of bore hole size in

the lower part which is equal to the bit size used in drilling, but in the upper part of this

zone curve has shifted few inches closer to the 8 inches of bore hole showing

development of mud cake on the wall of porous and permeable formation of the well.

The GR counts were less in the upper part but were relatively higher in the lower part

due to the increase of shaliness in that part. Thus, it is shaly limestone intercalated with

few shale layers.

Neutron-Density curves are moving together with small separation between them, and

are converging as shaliness decreases upward. At the depth of 1388m both the curves

are superimposing each other. And again separated upward.

Below the depth of 1389m sonic shows higher value i.e. 90 µsec/feet and above that it

decreases to 80 µsec/feet, which means sonic wave travels faster in the upper part.

The resistivity of this porous and permeable formation is very low due to the presence

of water in the pore spaces.

Unit:-1,382 to 1,378m

The caliper in this zone is slightly higher than 8.5 inches, it shows caving has occurred but bore

hole quality is good because of little caving.

Gamma ray curve is showing higher API unit indicating that formation is more

radioactive and thus shaly.

The Neutron-Density curves are moving opposite to each other i.e. both neutron

porosity and density are increasing, thus separation between the curves become more.

Firstly, sonic increases sharply then it decreases gradually upward showing that sonic

wave travel faster in the upper bed in comparison to the lower beds.

Resistivity of the formation is very low because it is a shale which have free ions so that

it promotes the conduction of electricity, hence resistivity reduces.

Unit:-1,378 to 1,371m

The caliper curve of this zone is in between 8.5 inches and 8 inches that means there is

deposition of mud cake on the wall of the well as well as the formation is porous and

permeable.

Gamma ray counts are low and slightly fluctuating because of the shaliness, thus

resulting serrated cylindrical shaped GR curve.

Both Neutron-Density curves are moving together as well as they are coming close to

each other that represent lithology is limestone. Here, with the increase of porosity

density decreases and vice versa.

Sonic curve is also changing corresponding to the neutron porosity curve i.e. increase

of neutron porosity increases the sonic velocity and decrease of neutron porosity

decreases the sonic velocity.

Resistivity of this porous and permeable layer has found to be higher than other porous

–permeable layers, thus it has been interpreted as hydrocarbon bearing rock i.e.

reservoir rock.

Unit:-1,371 to 1,367 m

The caliper log shows 9 inches of bore hole size that is higher than the bit size used in drilling.

Thus it implies caving has taken place.

Gamma ray counts are increased to 60 API unit from 35 API unit shows that there is

deposition of 2m thick layer of having less radioactivity in between the formation of

high radioactivity.

Neutron-Density curves are moving apart from each other signifying shale lithology.

This horizon is having high density i.e.2.5 cc/g and low porosity of 18%. But at the depth

of 1369m neutron has decreases and density has increased as well as the actual porosity

has decreased to 15% which marks the presence of tight layer.

Sonic curve shows increase in transit time which is due to the presence of shale.

The resistivity in this zone is about 1.5Ωm, 2 Ωm and 5 Ωm by ILD, SN, and MLL3

respectively. Higher MLL reading than other two resistivity curve shows the presence of

the tight layer.

Unit:- 1,367 to 1,356 m

In this zone the caliper log shows 8 inches of bore hole size which is ½ inch less than the bit

size which was used in drilling, thus mud cake has been deposited on the wall of well as well as

it also denote permeability of the formation rock and its middle and upper part has borehole

width equal to its bit size.

Gamma ray count has decreased to 25API unit in the lower part but increased to35 API

unit in the upper part which indicate that the rock has low radioactivity and thus more

carbonate content. The slight increase is due to increasing shaliness in the formation.

Neutron-Density curves are superimposing each other towards left at the depth of

1363 m, hence, actual porosity has increased to 31% in the lower portion. But in the

upper part of this zone neutron porosity is decreasing as well as density is increasing

thus, both Neutron-Density curve has shifted to right hand side, hence actual porosity

became to 18%.

Sonic curve is following the trend of neutron curve thus, increase in neutron porosity

leads to the increase of transit time and decrease of porosity result to decrease of

transit time.

An increase in resistivity curve has been noted in the lower part, which indicates the

presence of hydrocarbon in the pore spaces of the formation. And the upper part is

also hydrocarbon bearing but the water saturation in this horizon is more than the

lower one, thus its resistivity is about 5 Ωm. All the three resistivity curves are separated

from each other which shows that invasion has taken place.

At the depth interval of 1361-1360m of this zone has concluded as a tight layer because

porosity of this layer has decreased to 16% along with the increase of density i.e.

2.5cc/g as well as showing high resistivity of MLL curve i.e.4 Ωm. And it is acting as a

barrier between two reserves of the same formation.

Unit :- 1,356 to 1,349 m

Caliper log curves in this depth fluctuating between 8 inches and 9 inches bore hole size due to

development of thin mud cake on the wall of porous and permeable layer as well as little

caving has occurred in the shale layers. But overall caliper is uniform in this zone.

Gamma ray curve of this region is showing the mirror image of summation (∑) because

of presence of 1m and 2m thick shale layers lying respectively below and above the 4m

thick limestone bed. The GR count for shale is 80APIU and for limestone it is about

35APIU.

The Neutron-Density curve has been wrapped around each other, thus we are seeing

the sequence of their crossing over and separation because of combined effect of shale

layer and limestone bed. Actual porosity of this zones are 19.5%, 22.5%, and 21%

respectively for shale, limestone, shale as moving upward.

Sonic curve in this zone show increase of transit time in the shale layers and decrease of

transit time in limestone, thus the sound wave is faster in limestone than shale.

Here, resistivity curve is also following the sonic and neutron curve. In this zone the

limestone is showing high resistivity i.e. ILD = 8Ωm, and ILM & MLL = 5 Ωm, which is

due to the presence of hydrocarbons in its pore spaces, as well as shale layer has less

resistivity

Unit :-1,349 to 1,328m

In this zone caliper log has recorded 8 inches and 8.5 inches of borehole size upto the

depth of 1342m. Thus, mud cake has been developed on the wall of the well. Above the

depth of 1342m the caliper log shows a sharp increase from 8.5 inches to 12 inches,

which shows that bit size has changed at the depth of 1342m i.e. 8.5 inches and above

this depth bit size of larger size has been used to drill the well. Large caving has been

taken place in the upper part of this zone. Thus, quality of borehole size is not so good

at this part.

The gamma ray count is less compared to shale and is 40 API. Thus, it is a porous and

permeable layer. There are two layers at the depth of 1346-1343m and at 1330m

showing relatively higher GR value than the porous and permeable layer because of the

increase of shaliness in those layers. Beds with less GR counts are limestone and slightly

higher one are shaly limestone.

The Neutron-Density curves are superimposing each other upto a depth of 1340m, 2m

above that these curves have crossed over each other. Then they show a separation

between them in the further upper 1m, and again come closer which further crosses

over each other at the depth interval of 1336m-1333m, then again separation has found.

Here a large cross- over shows the presence of gas and separation between them are

the resultant of shale layer or shaliness. Curves are superimposing each other because

of its lithology i.e. limestone.

The sonic is increasing as we are moving upward in this zone and become maximum in

the depth interval of 1336m-1340m but is decreasing at the depths of 1334m and

1330m, that means sonic velocity has been decreasing (slowing down) throughout this

zone because pore spaces are filled with natural gas which retarded the velocity of

sonic wave( sound wave velocity is slowest in gas medium). In the middle part where

sonic is decreasing is due to the fact that invasion of mud filtrate has taken place and

the mud filtrate is a liquid due to which sonic velocity has increased.

Resistivity log

There is presence of tight layers at the depth of 1329m which was identified by increase

in density as well as MLL resistivity and decrease of neutron porosity (porosity).

The upper horizon of higher resistivity is gas bearing but lower one is oil bearing.

Unit: - 1,328 to 1,326 m

Here the caliper log is showing very high borehole size which is >16 inches, thus a large caving

has taken place so that quality of borehole is very poor.

Gamma ray is showing high API counts which is the characteristic of a shale.

It has high neutron porosity and less density as well as the separation between either

curves is more.

The sonic curve reads higher value that means velocity of sound wave has been slowed

down due to increase porosity and decrease of density.

Resistivity in this zone is very low i.e. <1 (less than 1).

Estimation of Water Saturated Formation Resistivity- Depth zone 1382m-1398m

Actual porosity :-

ɸn = 0.21=21%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.71 – 2.45)/1.71 = 15.2% [ρma =2.71

ɸ = (ɸd+ɸn)/2

= (0.21+0.152)/2

= 18.1%

By Archie’s Equation

Sw2= a Rw/ɸmRt =1

For this condition, Sw2= 1

Rw = ɸmRt / a

Here, m=2, Rt =3 (from log) & a=1 (reservoir is limestone)

Rw= (0.181)2 ×3 /1

= 0.098Ωm

Estimation of hydrocarbon Oil Saturation –

3) Depth from 1,378m to 1,371m

Actual porosity :-

ɸn = 0.255=25.5%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.71 – 2.31)/1.71 = 23.39%

ɸ = (ɸd+ɸn)/2

= (0.255+0.2339)/2 = 24.4%

By Archie’s Equation

Sw2= a Rw/ɸmRt

Here,

Rw =0.098Ω-m

Rt =6Ω-m

ɸ = 0.244

m=2, & a=1 (reservoir is limestone)

Sw2= (1×0.098)/(0.244)2×6

= (0.098)/0.357216

Sw2= 0.274

Sw= (0.274)1/2

= 0.5234

Hydrocarbon Oil saturation :-

Sh=1- Sw

= 1-0.5234

= 0.47

= 47%

4) Depth from 1367m to 1361 m

Actual porosity :-

ɸn = 0.3=30%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.71 – 2.15)/1.71 = .3274%

ɸ = (ɸd+ɸn)/2

= (0.3274+0.30)/2

= 0.6274/2

= 0.3137

= 31.37%

By Archie’s Equation

Sw2= a Rw/ɸmRt

Here, Rw=0.098Ω-m

Rt =10Ω-m

ɸ = 0.3137,

m=2, & a=1 (reservoir is limestone)

Sw2= (1×0.098/(0.3137)2×10

= (0.098) / .9840769

Sw2= 0.099

Sw= (0.099)1/2

= 0.3146

Hydrocarbon Oil saturation :-

Sh=1- Sw

= 1-0.3146

= 0.685

= 68.5%

5) Depth from 1360m to1356m

Actual porosity :-

ɸn = 0.30=30%

ɸd = (ρma- ρd)/ (ρma- ρf) = (2.71 – 2.15)/1.71 = 32.74%

ɸ = (ɸd+ɸn)/2

= (0.3274+0.30)/2

= 0.6274/2

= 0.3137

= 31.37%

By Archie’s Equation

Sw2= a Rw/ɸmRt

Here, Rw=0.098Ω-m

Rt= 19Ωm

ɸ = 0.3137,

m=2,

& a=1 (reservoir is limestone)

Sw2= (1×0.098)/(0.3137)2×19

= (0.098)/1.8697

Sw2= 0.0524

Sw= (0.0524)1/2

= 0.2289

Hydrocarbon Oil saturation :-

Sh=1- Sw

= 1-0.2289

= 0.77

Interpreted Log

The calculation of hydrocarbon volume requires us to know the volume of the formations

containing the hydrocarbons, the porosity of each formation, and the hydrocarbon saturation

in each formation. In practice each reservoir will be made up of a number of zones each with its

own thickness, areal extent, porosity and hydrocarbon saturation. For example, reservoir

sandstones may alternate with non reservoir shales, such that each zone is partitioned. Such

zonation is mainly controlled by lithology.

Hence, it is an early requirement to identify the lithologies in a particular well, identify which

formations have the required porosity to enable it to be a reservoir rock, and determine

whether the formation contains hydrocarbons. Reservoir rocks containing hydrocarbons are

allocated a zone code.

The volume of reservoir rock in a single zone depends upon the area of the zone A, and the

thickness of reservoir rock in the zone h. The area is obtained usually from seismic data (from

the reservoir geologist), and is the only data used in the calculation of hydrocarbon volumes in

place that is not derived from petrophysical techniques. The thickness of reservoir rock is

derived from the zonation of the reservoir based upon an initial lithological interpretation and

zonation of the reservoir from the wireline logs. The bulk volume of the reservoir Vbulk=A ´ h.

The majority of this volume is occupies by the solid rock matrix, and the remainder is made up

of the pore space between the minerals. The relative amount of pore space to the bulk volume

is denoted by the porosity f, where the porosity is the fraction of the bulk volume occupied by

pore volume, and is expressed as a fraction or as a percentage; f=Vpore/Vbulk. The pore

volume in any given zone is therefore Vpore=f ´ A´ h. In general the porosity is completely

occupied by either water and hydrocarbon, where the saturation

of the water is Sw, and that of the hydrocarbon is Sh, and Sw + Sh = 1. In most reservoirs the

hydrocarbon has replaced all the water that it is possible to replace, and under these conditions

the

water saturation is termed the irreducible water saturation Swi. Hence the volume of

hydrocarbon can be written as Vh = Ahf (1- Sw)

Identification of fractures using XRMI Log

Introduction: - XRMI is an advance imaging tool which stands for “Xtended Radio Micro

Imager” introduced by Halliburton in the mid of 1980’s. It gives us a

highly resolved image of borehole sub-surface formations. The image

created by it is a computerised image, based on geophysical

measurements of electrical conductivity or resistivity. The tool provides

high quality images of borehole formations because of its high

resolution.

FMI tool consists of 4 pads on 2 orthogonal arms, 4 flap and total

number of 192 buttons (sensors) mounted on each and every pad as well

as flap. Each pad and flap has 24 buttons, arranged in 2 rows of 12

buttons in each row. The electrical energy has been injected into the

formation by the emitter and are recorded by the sensors in the form of

resistivity curve. The raw data obtained is nothing but the resistivity

curves which has been juxtaposed (arranged closely) side by side to each

other to obtain the sub-surface image. But for our convenience we have

developed colour code method to determine the relative resistivity

variation among the formations.

There are 2 types of image colour designation are possible one in which the colour range

covers a population representing the entire log dataset, called static normalisation; and one in

which the sample population is a screenful (or similar limited quantity) of data values or

processed data and it is called dynamic normalisation. Maximum detail may be recovered by

using dynamic normalisation

Applications: -

1. Bed thickness – The fine resolution of the electrical images allows beds of at least 5cm

to be accurately evaluated.

2. Porosity and Permeability – As per our knowledge, pores and vugs can be larger and

have large electrical contrast to the matrix and obtained images are analysed to

identify individual vugs to define their size and shape from which porosity can be

inferred. Permeability has yet to be derived quantitatively from images.

3. Fracture – Fracture porosity and aperture have been evaluated quantitatively using this

log like open fracture, partially open fracture, and closed fractures.

4. Beds can be plotted by using the tadpoles and their depositional environment were

also interpreted based on their stacking pattern.

5. Maximum stress direction of a well can be determined during hydraulic fracturing in

non-conventional hydrocarbon reservoirs.

6. Well to well correlation has been done for ant tracking, and thus, used in exploring

non-conventional reservoirs of hydrocarbon.

Reservoir Dynamics

Reservoir pressure is a measurement of the fluid pressure in a porous

reservoir. The reservoir pore-fluid pressure is a fraction of the

overburden pressure that is supported by the fluid system. The other

portion is supported by the rock and generates the in-situ rock stress.

The overburden pressure is created by the weight of the rocks

composing the lithostatic column at the point of observation. Hence,

the difference between the overburden pressure and the vertical rock

stress can approximate the pore pressure. Due to the differences in the

buoyancy of the fluids and the reservoir pressure along with the

capillary action, the migration of hydrocarbons take place from the

source rock to the reservoir rock. Rocks contain an array of pores of

different sizes connected together by pore throats of differing size.

More is the permeability, more is the pore throat size. This results in

more movement of oil due to the greater buoyancy forces and less

capillary forces.

Oil Recovery

Reservoir Drive Mechanisms

The natural energy of a reservoir can be used to move the oil and gas

towards the well bore hence, helping in the recovery of oil. These

sources of energy are called reservoir or primary drive mechanisms.

There are three primary reservoir drives – Water drive, depletion gas

drive and gas cap drive.

•Water drive - A strong water drive provides very good pressure

support from the aquifer with minimal pressure drop at the wellbore. The aquifer water

expands slightly, displacing the oil or gas from the reservoir toward the borehole as pressure

drops around the borehole. This mechanism exists only where the aquifer is of equal or better

quality than the reservoir and has a much larger volume than the reservoir (about 10 times) or

is in communication with surface recharge. A strong water drive is more effective in oil

reservoirs than in gas reservoirs.

•Solution/ Depletion gas drive - Crude oil under high pressure can contain large amounts of

dissolved gas. The more gas there is in solution, the more compressible the oil. In oil reservoirs

with little or no water drive, reservoir energy to drive the oil toward the wellbore can be

supplied by expansion of the oil due to gas expanding in solution. This is a solution gas (or

dissolved gas or depletion) drive. When pressure drops below the bubble point in the reservoir,

small, disconnected gas bubbles form in pores, also pushing the oil toward the wellbore. At

about 5–10% free gas in the reservoir, the bubbles coalesce and the gas moves toward the

wellbore as a separate flowing phase. When this happens, oil production drops and gas

production increases rapidly because of the increased relative permeability to gas.

Gas Cap Mechanism

In some instances, oil reservoirs are discovered with a segregated gas zone overlying an oil

column. The overlying gas zone is referred to as a primary gas cap. In addition to free gas, gas

caps usually contain connate water and residual oil. The underlying

oil column is sometimes referred to as an oil leg. In other instances,

as reservoir pressure declines with production, gas evolves in the

reservoir and migrates to the top of the structure to add to an

existing primary gas cap or to form a gas cap. If properly

harnessed, gas caps can enhance oil recovery considerably. The

degree with which they improve recovery depends mainly on their

size and on the vertical permeability and/or formation dip.

Producing wells usually are completed only in the oil leg to

minimize gas production.

Second Drive Mechanisms

Secondary recovery is the result of human intervention in the reservoir to improve recovery

when the natural drives have diminished to unreasonably low efficiencies.

Water flooding - This method involves the injection of water at the base of a reservoir to;

(I) Maintain the reservoir pressure, and

(II) Displace oil (usually with gas and water) towards production wells.

Gas Injection- This method is similar to water flooding in principal, and is used to maintain gas

cap pressure even if oil displacement is not required.

Sucker Rod Pump

Beam pumping, or the sucker-rod lift method, is the oldest and most

widely used type of artificial lift for most wells. A sucker-rod pumping

system is made up of several components, some of which operate

aboveground and other parts of which operate underground, down in the well. The surface-

pumping unit, which drives the underground pump, consists of a prime mover (usually an

electric motor) and, normally, a beam fixed to a pivotal post. The post is called a Sampson

post, and the beam is normally called a walking beam.

This system allows the beam to rock back and forth, moving the

downhole components up and down in the process. The entire surface

system is run by a prime mover, V-belt drives, and a gearbox with a

crank mechanism on it. When this type of system is used, it is usually

called a beam-pump installation. However, other types of surface-

pumping units can be used, including hydraulically actuated units (with

and without some type of counterbalancing system), or even tall-tower

systems that use a chain or belt to allow long strokes and slow pumping

speeds. The more-generic name of sucker-rod lift, or sucker-rod

pumping, should be used to refer to all types of reciprocating rod-lift

methods.

Submersible Pump & Motor

A submersible pump is a unit combining a pump and a motor to an

enclosed unit, suitable for submerged installation.

There are two types of submerged pumps:

A submerged pump type with a submersible motor.

A submerged pump with a dry motor, which is connected to the

pump by a long shaft.

These pumps are normally used for supply of fresh water for

drinking, irrigation, and various industrial applications.

Submersible pump versions

The pump comes in both a single-stage and a multi-stage

version (the multistage version being the most common one).

The submersible pump may be connected to a riser pipes with a

non-return valve, or it can also be installed connected with a

flexible hose or other arrangements.

The pumps are specially designed to be submerged in a liquid

and are often fitted with a submersible motor which is

hermetically sealed.

Motor and pump are connected with a coupling, from the pump

shaft to the motor shaft.

Power to the motor is fed through one or more flexible watertight cable.

Grundfos has the following types of submersible pumps:

Enhance Oil Recovery (EOR)

In a conventional reservoir drilled with conventional methods, the expected initial extraction

rate of available hydrocarbons maybe as much as 15% – leaving 85+% of hydrocarbons in

the reservoir. Pump jacks and initial gas injection or thermal recovery can increase that

capture to the 25-30% range. By applying EOR techniques you can extract another 10-15%

of the initially available hydrocarbons. EOR is sometimes referred to as “water-flooding” in a

nod to this technique, where large quantities of liquid (or gas) are pumped into the

formation in order to encourage the release and migration of hydrocarbons towards the

producing well.

As there are different kinds of oil fields in the world, there are different EOR methods used

to improve the long-term drilling results.

Essentially these can be determined in four basic methods:

1. Chemical Method

Polymer flooding Polymer flooding is one of the most widely used EOR methods to

retrieve oil left behind after conventional recovery processes. Polymer flooding is a tertiary

recovery method by adding high-molecular-weight polyacrylamide into injected water, so

as to increase the viscosity of fluid, improve volumetric sweep efficiency, and thereby

further increase the oil recovery factor. When oil is displaced by water, the oil/water

mobility ratio is so high that the injected water fingers through the reservoirs. By injecting

polymer solution into reservoirs, the oil/water mobility ratio can be much reduced, and the

displacement front advances evenly to sweep a larger volume. The viscoelasticity of

polymer solution can help displace oil remaining in micro pores that cannot be otherwise

displaced by water flooding.

Chemical Flooding In a chemical flood, chemicals are injected with the water flood to

improve the displacement efficiency. A chemical solvent is specially developed for

adaptation to the specific structural characteristics and physiochemical properties of a

reservoir.

2. Physical method

Thermal recovery Thermal methods raise the temperature of regions of the reservoir to

heat the crude oil in the formation and reduce its viscosity and/or vaporise part of the oil

and thereby decrease the mobility ratio. Thermal methods include the injection of hot

water, steam or other gas, or by conducting combustion in situ of oil or gas. The increase in

heat reduces the surface tension and increases the permeability of the oil and improves the

reservoir seepage conditions. The heated oil may also vaporise and then condense forming

improved oil.

Biological Method

Microbial injection These days there is also a new biological theory which involves

injecting bacteria into the oil reservoir to improve the recovery efficiency.

Microbial injection is part of microbial enhanced oil recovery and is rarely used because of

its higher cost and because the developments are not widely accepted.

Vindhyan Basin : A case Study

•Stratigraphy :

The Proterozoic Vindhyan Basin in the Central part of India is situated between the Delhi -

Aravalli orogenic belt to the north-west and Son-Narmada Geofracture to the south. The

Bundelkhand Massif, located in the north-central part of the basin, divides it into two sectors:

Chambal Valley to the west and Son Valley to the east. The basins fill in Son Valley constitutes a

considerable thickness (2-6Km) of unmetamorphosed, varyingly deformed sedimentary

succession, which is divisible into carbonate dominated Lower Vindhyan (Semri Group) and

clastic dominated Upper Vindhyan (Kaimur, Rewa and Bhander Groups) sequences, separated

by a large hiatus. Various stratigraphic classification schemes for the Vindhyan sediments have

been proposed by different workers.

The Lower Vindhyan sediments in Son Valley lie either on metamorphosed sediments

comprising Bijawar Group of rocks (late Palaeoproterozoic) or sometimes directly over the

Mahakoshal and/or Bundelkhand Granitic Complex (early Paleoproterozoic-Archaean). The

Karaundhi (Deoland) Formation immediately overlies the basement and comprises coarse gritty

arkosic sands and sometimes conglomerate. The overlying Arangi Formation is represented by

carbonaceous black shale deposited in the grabenal areas during syn-rift phase. The Kajrahat

Formation comprises of light to dark-grey, occasionally pinkish argillaceous limestone with

subordinate beds of light grey to dark grey, pyritic, feebly calcareous shale. The Jardepahar

(Deonar) Formation consists of dark grey shale, siltstone, porcellanite, chert and minor marl.

Charkaria Shale (Koldaha) Formation is dominated by dark grey to black shale with thin

alternations of grey, light grey, hard, compact and feebly calcareous siltstone. The overlying

Mohana Fawn Limestone (Salkhan Limestone) Formation consists of light grey and dirty white,

micritic, argillaceous limestone and dolomite interbedded with shale. Basuhari Glauconite

(Rampur Glauconite) Formation is essentially argillaceous with a few thin bands of chert

towards the top, glauconitic sandstone towards the middle and limestone at the bottom. The

overlying Rohtas (Rohtasgarh Limestone) Formation is represented by alternate limestone and

shale sequence. Rohtas Formation has been divided into three litho-units i.e. upper, middle and

lower Units. The Lower Rohtas Unit consists of argillaceous limestone with interbed of cherty /

silty-shale. The Middle Rohtas Unit is dominantly argillaceous in nature represented by

alternations of argillaceous limestone and calcareous shale/calcareous siltstone with occasional

very fine- grained sandstone layers. The Upper Rohtas Unit is dominantly represented by

argillaceous limestone with thin laminations of shale.

The Upper Vindhyan sequence beginning with the Kaimur Group occurs over a large hiatus

which is well observed with truncation of Rohtas sediments against Upper Vindhyan sediments.

The lesser thickness of Upper Vindhyans attributed to subsequent upliftment and erosion.

Kaimur Group includes grey to greenish grey sandstone and shale with minor siltstone. Rewa

and Bhander groups of upper Vindhyan overlie Kaimur Group unconformably. Rewa Group

consists of Panna Shale, Lower Rewa Sandstone, Jhiri Shale and upper Rewa Sandstone. The

overlying Bhander Group comprises four formations. The oldest Ganurgarh Shale Formation

contains chocolate coloured fine -grained calcareous sandstone. Overlying it is the Bhander

Limestone (Nagod Limestone), which is the only carbonate unit in the upper Vindhyan.

Overlying Sirbu Shale Formation is light yellow, grey to greyish green with interbedded

siltstone. Upper Bhander Sandstone (Maihar Sandstone Formation) is the youngest horizon

consisting of brown to red coloured sandstone and deep red coloured shales.

Techtonic Setting

The Vindhyan Basin is genetically associated with two mega tectonic elements: Great Boundary

Fault (GBF) to the northwest and Son-Narmada Lineament (SNL) to the south. The Vindhyan

strata of Son Valley define a broad ENE–WSW trending regional syncline in the central part. The

axis of the syncline is slightly curved (convex towards north) and plunges gently towards west.

Detailed account of tectonic framework including the fault systems, paleo-structures, structural

inversion and deformation history have been described by many workers from time to time.

Son Narmada Lineament is a major crustal feature formed along the Archean structural trends

and remained active throughout geologic history till the present day. It marks the tectonic

sedimentation limit of Vindhyan Basin in south and south-east. The greater thickness of

sediments in Son Valley area towards south implies an active southern margin along which

relatively continuous subsidence was responsible for greater thickness of sediments. The

northern and eastern margins of basin have gentle gradient.

Initial tectonic evolution of Vindhyan Basin is controlled by basement related rift tectonics,

which formed a number of horst and grabens. Two main fault trends are evident, faults parallel

to the SNL (E-W to ENE-WSW) as well as along NW-SE aligned oblique faults. The major half

grabens are located along the down thrown side of these rift related faults. Some of these

faults show syn-sedimentary vertical movements. In later phase of evolution, compressional

reactivation of pre-existing extensional faults under the influence of wrench related strike–slip

movement along SNL resulted in the formation of inversion structures like Damoh, Jabera and

Kharkhari. Major oblique faults divide Son Valley into a number of tectonic blocks notable

among them are the Udaipur-Tendukhera block, Jabera-Damoh block and Satna-Rewa-Kaimur.

Among these blocks, the Jabera-Damoh block is tectonically the most disturbed.

•Basin Evolution:

The Vindhyan Basin has evolved through multiphase geological history from 1400Ma (?) to

550Ma. In Son Valley, the well-developed sub-basins are the Bahuriband - Jabera - Damoh and

Udaipur-Tendukhera depressions. These depressions show half-graben morphology wherein

three phases of evolution are evident. Crustal extension began at ~ 1.65 Ga, and continued for

tens of millions of years. The basal Karaundi, Arangi Shale, Kajrahat and major part of

Jardepahar formations were deposited during this time. On lap surfaces and stratigraphic

growth at several levels provide evidence of crustal extension and tilting of fault blocks at the

base of lower Vindhyan. This tectonic evolution is supported by the sedimentological records of

having a transition from alluvial conglomerate/arkosic sandstone at bottom to shallow marine

carbonate and shale/siltstone at shallower level. The transition from syn rift to post-rift thermal

subsidence is marked in seismic records by the termination of local stratigraphic growth

associated with tilting of extensional fault blocks (at the upper part of Jardepahar level, ~1.63

Ga). Compressional deformation began subsequent to the deposition of the uppermost part of

the Lower Vindhyan. Basin inversion is thought to mark the end of the thermal subsidence

phase and Lower Vindhyan sedimentation at ~1599 Ma. Upper Vindhyan subsidence is

ascribed, tentatively, to continuing but likely episodic compression.

•Petroleum Systems:

The fractured limestone within Rohtas Formation and Basal Kaimur Sandstone are the principal

reservoirs where presence of gas has been established over a large part of the study area.

Additionally, Mahona Fawn Limestone, Siltstone within Charkaria Formation, Jardepahar coarser

clastics and Kajrahat Limestone are envisaged to be potential reservoirs as well. A number of

transgressive shales and intra formational shales act as effective seals. The syn-rift organic rich

Arangi shales in the lower part of Semri Group has exhibited good source rock potential (TOC:

0.5-10.14%) in well B located near the Jabera Low. Stratigraphically younger sequences like

Charkaria Shale (TOC: 0.42-1.84%) and Basuhari Shale (TOC: 1.14-1.78%), also constitute

adequate source rocks. The data from outcrop studies and drilled wells in the area indicated fair

to good organic richness in the thick shale section within Middle Rohtas Unit as well as shale

layers within the Upper and Lower Rohtas Limestone (TOC: 0.57-4.71%). This observation

strongly suggests that Rohtas Formation has a separate viable petroleum system having

adequate organic rich source which are envisaged to have charged the gas bearing fractured

reservoirs within different units of Rohtas and Kaimur formations through short distance

migration. Moreover, expulsion of hydrocarbon from the deeper Arangi and Kajrahat sources to

the shallow Rohtas and Kaimur reservoirs is not considered as a viable possibility, particularly in

view of presence of thick transgressive Charkaria shale sequence, with thickness as high as

600m, in between. The deeper syn-rift source might possibly have charged stratigraphically

deeper plays like Kajrahat, Jardepahar and Charkaria, which has not been fully established till

date baring flow of gas within Jardepahar Formation and hydrocarbon indications within

Charkaria Formation in well A. Hence, the following two petroleum systems are envisaged in

Son valley:

Rohtas-Rohtas and Rohtas-Basal Kaimur: major petroleum system responsible for the

accumulation of gas within Rohtas and Basal Kaimur units.

Arangi-Kajrahat-Jardepahar/Charkaria: secondary petroleum system, where the potential

source rocks within deeper Arangi/Kajrahat formations might have charged deeper

Kajrahat/Jardepahar/Charkaria reservoirs in suitable strati-structural prospects.

Interpretation and Quantitative Analysis:

Log curve

Depth

interval(m)

Observation Lithology

Interpretation

Water Saturation

Sw

(%)

Porosity

(%)

1460-1500

High variation in the

gamma ray curve.

Neutron porosity and

density curves indicates

high porosity where there

are sandstone beds

Alternate layers of

shale and sandstone

(lower Kaimur

sandstone)

interbedded with

siltstone

60-70 4-5

1500-1510 Very high values of

gamma Thick shale bed -- --

1514-1620

Gamma ray curves

deflects towards left and

resistivity curve shows

high value (1514-1520)

indicating the presence

of hydrocarbon. PE curve

shows transition from

sandstone to limestone.

Thick limestone bed

(Upper Rohtas

limestone)

80-90

(water bearing) 6-9

1620-1680

Low resistivity and high

gamma ray from 1620 -

1640m and high

resistivity from 1640 to

1680m

Shale beds followed by

thick limestone beds 60-75 1

1700-1730

Very high resistivity

values

(believed to be highly

fractured)

Thick limestone beds 50-65 1-2

1735-1800 High variation in

resistivity curve

Alternate layers of

limestone and shale 65-90 1

Fracture Interpretation

76%

15%

9%

PERCENTAGE FRACTURE IN THE GIVEN INTERVAL OF THE XRMI LOG

Partially Open Open Closed

Rose Diagram

• The average direction in set-1 of fractures i.e. maxima 1 is N37E-S37W.

• The average direction in set 2 of fractures i.e. maxima 2 is N44W-S44E.

• Their bisector i.e. the maximum stress direction ( 1) is N86E-S86W.

• The minimum stress direction ( 2) is N4W-S4E.

The project work related to summer training’ 16 has been successfully completed on the topic

“Study on the Geophysical techniques in petroleum exploration- a case study on Vindhyan

Basin” and the objective of understanding the concepts involved has been achieved.

•Seismic survey method is considered the most important technique in hydrocarbon

exploration as it gives a clearer and comparatively higher resolution image of the sub-surface

(compared to gravity/ magnetic/ magneto-telluric) thereby helps in more accurate

understanding of sub-surface prospective structures.

•Logging helps us in knowing the sub-surface petro-physical properties, depositional

environment and also the study of sequence stratigraphy of an area by means of composite

log. Geophysical methods of log also gives an insight of nature of fluid which is present within

pore spaces of formations and helps in quantitative as well as qualitative analysis of

hydrocarbon (oil and gas) in reservoir rocks. One of the well logs of Vindhyan basin (till mid

Rohtas formation) was studied and interpreted during our training.

•In conventional reservoirs, basic logs are used which include Calliper, GR, SP, neutron, density,

sonic and resistivity logs. Data recorded from these logs are used to determine lithology,

porosity and derive hydrocarbon saturation by various methods.

•In an unconventional reservoir setup with very low porosity and permeability values, the role of

fractures induced secondary porosity becomes very important. The fractured zone in a well may

be delineated using XRMI log which produces a high resolution image based on resistivity

contrast. The orientation of the fractured data gives an insight into the palaeo-stress regime

which prevailed in the area and resulted in generation of the fractures. The XRMI log of Lower

Vindhyan, Rohtas Formation has been studied in this report in our case study.

•In addition, the study also included reservoir pressure and the natural drive mechanisms which

take place in the reservoir and aid in the recovery of oil. By understanding the physics behind

them, it might help in developing further technologies which enhance the net extraction from

the reservoir.