Petrophysic cont

Petrophysic Cont’
Petrophysicist (Geologist)
For Practical Use and Refferences

Petrophysics Seismic Petrophysics
 Sonic and Density Logging Tools
 Elastic Properties of Rocks
 Seismic Petrophysics
Petrophysics Fractured Reservoir
 Dipmeter Logs
 Dipmeter and Image Log Calculations
 Fractured Reservoir
Structural & Stratigraphic Analysis
 Structural Analysis
 Stratigraphic Analysis
Petrophysics Continue

 Sonic and Density Logging Tools
 Elastic Properties of Rocks
 Seismic Petrophysics
 Dipmeter Logs
 Dipmeter and Image Log Calculations
 Fractured Reservoir
 Structural Analysis
 Stratigraphic Analysis

 Energy Sources for Acoustic Logs
1. Monopole sources
2. Dipole sources
3. Quadrupole sources
 Dispersion
 Acoustic Transmission Modes from a Monopole Sources
1. Fast compressional waves
2. Slow compressional waves
3. Surface compressional waves
4. Shear body waves
5. Shear surface waves
Sonic and Density Logging Tools

6. Stoneley waves
7. Tube waves
8. Fluid compressional wave or mud wave
9. Direct tool arriva
Attenuation of Sound Waves
Types of Sonic Logging Tools
Recording Conventional Sonic Logs
Recording Full Wave Sonic Logs
Recording Dipole Shear Sonic Logs
Sonic and Density Logging Tools

Energy Sources for Acoustic Logs
Acoustic log source types fall into three categories: monopole, dipole, or quadrupole
1. Monopole sources emit sound energy in all directions radially from the tool axis. They are
sometimes called axisymmetric or radially symmetric sources.
Sound energy from the source that reaches the rock at the critical angle is refracted (bent) so
that it travels parallel to the borehole inside the rock. This energy is refracted back into the
borehole, and strikes the receivers. The difference in time between arrivals at the receivers is
used to estimate the travel time, or slowness, of sound in rock.
The monopole source also generates a shear wave on the borehole surface in fast formations,
called a pseudo-Rayleigh wave. The converted shear and the pseudo-Rayleigh arrive at the
monopole detector with nearly the same velocity and cannot usually be separated. Monopole
sources also generate the Stoneley wave in both fast and slow formations. The low frequency
component of the Stoneley is called the tube wave.

2. Dipole sources and receivers are a newer invention. They emit energy along a single direction
instead of radially. These have been called asymmetric or non-axisymmetric sources. They can
generate a compressional wave in the formation, not usually detected except in large boreholes
or very slow formations. They generate a strong shear wave in both slow and fast formations.
This wave is called a flexural or bender wave and travels on the borehole wall
(upper) shows a waveform from a monopole source in a slow
formation. There is a compressional wave (P) but no shear
arrival. The dipole waveform (lower) at the same depth
shows no compressional but good shear (S) arrivals. Notice
that the shear wave arrives after the fluid wave (the
definition of a slow formation).

3. Quadrupole sources generate asymmetric pressure waves, called screw waves, which
behave similarly to those of dipole sources. They can be used on open-hole tools, although no
such tool is commercially available. They are more suited to the logging-while-drilling
environment where recent developments have shown some success in measuring shear
velocity. The quadrupole source generates quadrupole waves, which travel in the collar and the
formation, the two being coupled through the annulus. At low frequencies the formation
quadrupole travels at the formation shear speed. The quadrupole LWD tool collar is designed to
be thick enough that the collar quadrupole mode is "cut off" (very highly attenuated) below
some frequency chosen to be well above the frequency used for quadrupole logging, thus
minimizing the interference with the formation quadrupole.

Dispersion
The velocity of sound varies with the frequency of the sound wave. This effect is called
dispersion. Most waves travel faster at low frequency (normal dispersion) but tube waves are
slightly reverse dispersive in fast formations and normally dispersive in slow formations.
Compressional waves have very little dispersion. The various wave modes used to measure
shear velocity are very dispersive, which may account for errors in shear velocity on older
logging tools, when high frequency sources were the norm. Today, tools are designed to work
below 5 KHz for shear measurements, instead of 20 to 30 KHz on older tools.
Shear velocity dispersion curves for fast (left) and slow (right) formations (from Zemanek et al, 1991)

Acoustic Transmission Modes
from a Monopole Sources
The monopole source generates several wave modes, some of which have been used more or
less successfully, to estimate shear velocity.
Monopole sources can develop both body and surface waves; dipole and quadrupole sources
create only surface waves. Body waves travel in the body of the rock. Surface waves travel on
the borehole wall or bounce from the wall to the tool and back to the wall. The surface waves
are also called guided waves or boundary waves.
1. Fast compressional waves, also called dilational, longitudinal, pressure, primary, or P-
waves, are recorded by all monopole sonic logs, beginning in the mid to late 1950's. They are
the fastest acoustic waves and arrive first on the sonic wavetrain.
The compressional wave is initiated by a monopole energy source and is transmitted through
the drilling mud in all directions. Sound traveling at the critical angle will be refracted into the
formation, which in turn radiates sound energy back into the mud, again by refraction. The
sound waves refracted back into the borehole are called head waves. The compressional head
wave is detected by acoustic receivers on the logging tool.

2. Slow compressional waves are transmitted, as well as the fast waves described above. It
is called a dilational wave of the second kind by Biot. It is also a body wave and travels in the
fluid in the pores at a velocity less than that of the fast compressional wave in the formation
fluid. Its amplitude decays rapidly with distance, turning into heat before it can be detected by
a typical sonic log. No pores, no fluid, no slow compressional wave.
3. Surface compressional waves, also
called leaky compressional, compressional
"normal mode", or PL waves, follow the fast
compressional wave. This is a surface wave
from a monopole source and travels on the
borehole wall. Amplitude varies with Poisson's
Ratio of the rock/fluid mixture. It is present in
both fast and slow formations.
The wave is dispersive, that is, low frequencies travel faster than high frequencies. It has
velocities that range between the fast compressional wave through the formation (Vp) and
the fluid wave in the borehole (Vf). The first arrival coincides with Vp and the balance of the
wave shows up as a "ringing" tail on the compressional segment of the wavetrain.

4. Shear body waves, also called transverse, rotational, distortional, secondary, or S-waves,
are generated by conversion of the compressional fluid wave when it refracts into the rock
from the wellbore. It converts back to a P wave when it refracts through the borehole to reach
the sonic log detector. This wave is also a body wave. The refracted wave returning to the
logging tool is called the shear head wave. Shear waves vibrate at right angles to the ray path.
5. Shear surface waves, also called pseudo-Rayleigh, multiple-reflected conical, reflected
conical, or shear "normal mode" waves, follow the shear body wave. They are a surface wave
generated by a monopole source. They are also classified as a guided-wave. Monopole sonic
logs cannot generate a surface shear wave in slow formations for the same reason that they
cannot generate a body shear wave. Dipole sonic logs can generate a different form of shear
surface wave, the flexural wave, but cannot create the shear body wave.
6. Stoneley waves are guided waves generated by a monopole source that arrive just after
the shear wave or the fluid compressional wave, whichever is slower. The wave guide is the
annulus between the logging tool and the borehole wall. They are also called tube waves or
Stoneley tube waves

7. Tube waves, also called Lamb waves or "water hammer", are the low frequency
component of the Stoneley wave (in theory, the zero frequency component).
8. Fluid compressional wave or mud wave is the compressional body wave from a
monopole source that travels through the mud in the borehole directly to the sonic log
receivers. It travels at a constant velocity with relatively high energy. When it occurs after the
shear arrival (Vs > Vf), shear detection is relatively easy with modern digital sonic logs.
9. Direct tool arrival is sound that travels along the logging tool body. The wireline tool
housing is slotted to make the travel path, and hence the arrival time, too long to interfere with
other arrivals.

Attenuation of sound waves
All waves continue to propagate until they are completely attenuated. Attenuation is caused
by several factors.
1. Some energy is reflected back into the wellbore due to the change in acoustic impedance
between the mud and the rock. The impedance of any material is equal to the product of its
density and velocity. The greater the change in acoustic impedance, the larger the amount of
reflected energy. Thus, not all energy is transmitted into the formation. In large or rough
holes, the energy may be so low as to cause difficulty with the sonic log readings.
2. Some energy is lost due to internal reflection inside the formation when the sound wave
strikes a fracture plane or a bedding plane.
3. Spherical divergence, which reduces energy by the square of the distance from the source,
takes place only on body waves.
4. Absorption occurs on all waves, which converts the mechanical energy into heat.
5. Phase interference of one wave mode with another due to varying frequency components
can attenuate portions of the wavetrain in a variable fashion.
6. Multiple ray paths through rough borehole or altered rock usually reduces sonic amplitude,
but more rarely may cause additive interference.
7. Poorly maintained logging sondes, especially earlier generations of tools, can attenuate the
transmitted or received signal, by causing poor acoustic coupling with the borehole fluid.
8. Gas entrained in the mud column, and gas in the formation, can also attenuate the sonic
signal, sometimes causing poor logs (cycle skipping on older logs, missing or interpolated lo
curves on newer tools.

Types of Sonic Logging Tools
Modern sonic logs, often called dipole shear sonic logs, usually carry monopole
and dipole sources, and generate the measured values for compressional, shear,
and Stoneley slowness in different ways depending on the formation
characteristics. Such a tool can give us all three measurements in both slow and
fast formations.

The sonic logging tool consists of a
mandrel with one or more sound
transmitters and one or more sound
receivers. The tool is lowered into the
borehole on the end of an electrical
cable which provides power and signal
lines to the tool. The transmitters and
receivers are piezoelectric ceramic
bobbins wound with a coil.
Recording Conventional
Sonic Logs

The spacing of a sonic log refers to the distance
between transmitter and the center of the receiver
array. The span is the distance covered by the
receiver array, equal to the distance between the
receivers on a double receiver tool.
The sound frequency and spacing between the
transmitter and detectors determine the depth of
penetration of the sound energy into the rock.
Long spaced logs are usually run in large holes or in
unconsolidated formations.
Sonic Logs

 Lithology from shear and
compressional travel time
 Some sonic logs show a velocity
scale, often non-linear. Another log
presentation portrays the sonic
data as its equivalent porosity,
translated with a particular
lithology assumption. The scales are
usually called Sandstone or
Limestone scales to reflect the
assumption that was made to
create them. Dolomite scales also
exist on a few logs
Sonic Logs

Identifying and picking shear travel
time on full wave sonic
Recording Full Wave Sonic Logs

Array sonic tool and
waveforms
Recording Full
Wave Sonic Logs

Array sonic log with
compressional, shear, and
Stoneley traveltimes.

Array processor coherence
maps to find compressional,
shear,Stoneley travel time
and spotty shear log
In a fast formation, where shear is faster than mud velocity, the array tool obtains direct
measurements for shear, compressional, and Stoneley wave values. In a slow formation, it
obtains measurements of compressional, Stoneley, and mud wave velocities. Shear wave values
are then derived from these velocities.

 On the dipole sonic, shear travel time is
always obtained, even in slow formations, due
to the different way that acoustic waves
propagate from the dipole source
 Dipole shear sonic tool and specifications
Recording the Dipole Shear
Sonic Log

Waveform presentation
Sonic Log

Dipole shear image log - a crossed
dipole log will have two compressional
and two shear images, as well as two
travel time curves for both.
Sonic Log

 Elastic Constants Theory
 Calculating Mechanical Properties Of Rocks
 Correcting High Frequency Sonic (Lab) Data
 Correcting Density and Sonic Data for Gas
 Shear From Stoneley Travel Time
 Shear Modulus N
 Poisson's Ratio PR
 Bulk Modulus Kb
 Bulk Compressibility Cb
 Biot’s Constant Alpha
 Young's Modulus Y
 Modulus of Compressibility Kc
 Pore Compressibility Kp or Kf
 Calibrating Dynamic to Static Constants
ELASTIC PROPERTIES OF ROCKS

 Examples of Mechanical Properties Logs
 Calculating Overburden Pressure Gradient
 Calculating Normal Pore Pressure Gradient
 Calculating Abnormal Pressure Gradient
 Calculating Fracture Pressure Gradient
 Calibrating Fracture Pressure Gradient
 Calculating Fracture Extent
 Gamma Ray Logging to Confirm Fracture Placement
 Fracture Orientation from Caliper and Dipmeter Logs
 Tables of Rock Properties

Elastic constants are needed by five distinct disciplines in the petroleum industry:
1. geophysicists interested in using logs to improve synthetic seismograms, seismic models,
and interpretation of seismic attributes, seismic inversion, and processed seismic sections.
2. production or completion engineers who want to determine if sanding or fines migration
might be possible, requiring special completion operations, such as gravel packs
3. hydraulic fracture design engineers, who need to know rock strength and pressure
environments to optimize fracture treatments
4. geologists and engineers interested in in-situ stress regimes in naturally fractured
reservoirs
5. drilling engineers who wish to prevent accidentally fracturing a reservoir with too high a
mud weight, or who wish to predict overpressured formations to reduce the risk of a blowout.
The elastic properties or elastic constants of rocks are used to determine the
mechanical properties of rocks.

Elastic Constants Theory
The velocity of sound in a rock is related to the elastic properties of the rock/fluid mixture
and its density. The pore space bulk modulus (Kp) can be derived from the porosity, fluid, and
matrix rock properties, using the Biot-Gassmann equation:
The Gassmann equations define compressional velocity (Vp) and shear velocity (Vs):
WHERE:
ALPHA = Biot's elastic parameter (fractional)
DENS = rock density (Kg/m3 or g/cc)
DENSW = density of fluid in the pores (Kg/m3 or g/cc)
Kb = compressional bulk modulus of empty rock frame
Kc = compressional bulk modulus of porous rock
Kf = compressional bulk modulus of fluid in the pores
Km = compressional bulk modulus of rock grains
Kp = compressional bulk modulus of pore space
N = shear modulus of empty rock frame
PHIt = total porosity of the rock (fractional)
Vp = compressional wave velocity (m/sec or ft/sec)
Vs = shear wave velocity (m/sec or ft/sec)
Vp = Stoneley wave velocity (m/sec or ft/sec)
KS4 = 68.4 for English units
KS4 = 1.00 for Metric units
Kc = Kp + Kb + 4/3 * N
Vp = KS4 * (Kc / DENS) ^ 0.5
Vs = KS4 * (N / DENS) ^ 0.5
Vst = KS4 * (DENSW * (1/N + 1/Kf)) ^ 0.5
ALPHA = 1 - Kb / Km
Kp = ALPHA^2 / ((ALPHA - PHIt) / PHIt / Kf )

Calculating Mechanical
Properties Of Rocks
Correcting High Frequency Sonic (Lab) Data to Low Frequency Equivalent (Logging Tool
Frequency)
DTScor = (DTShi - KS1) *1.25 +KS1
DTCcor = (DTChi - KC1) *1.02 + KC1
WHERE:
DTCcor = compressional sonic corrected for high frequency effect (usec/ft or usec/m)
DTChi = lab measured compressional sonic reading (usec/ft or usec/m)
DTScor = shear sonic corrected for high frequency effect (usec/ft or usec/m)
DTShi = lab measured shear sonic reading (usec/ft or usec/m)

Properties Of Rocks
Frequency and fluid effects on Sonic travel time (Anderson, 1984)

Properties Of Rocks
Correcting Density and Sonic Data for Gas
The following equations will also provide better data than the raw log data in gas zones:
WHERE:
DENScor = density corrected for gas effect (gm/cc or Kg/m3)
DENS = density log reading (gm/cc or Kg/m3)
PHIe = effective porosity (fractional)
Sgxo = gas saturation near the well bore (fractional)
default = 0.80 for sonic, 0.70 for density log
DENSMA = matrix density (gm/cc or Kg/m3)
DENSW = water density (gm/cc or Kg/m3)
DTCcor = compressional sonic corrected for gas effect (usec/ft or usec/m)
DTC = compressional sonic log reading (usec/ft or usec/m)
DTMA_C = compressional sonic travel time in matrix rock (usec/ft or usec/m)
DTScor = shear sonic corrected for gas effect (usec/ft or usec/m)
DTS = shear sonic log reading (usec/ft or usec/m)
DELTW = sonic travel time in water (usec/ft or usec/m)
DENScor = DENS + 0.5 * PHIe * Sgxo * (DENSMA – DENSW)
DTCcor = DTC + 0.5 * PHIe * Sgxo * (DTMA_C – DELTW)
DTScor = DTS

Properties Of Rocks
Shear Travel Time From Stoneley Travel Time
In very slow formations, where shear travel time was impossible to measure on older sonic
logs, this formula is used to calculate shear travel time (DTS) from Stoneley travel time:
The dipole shear sonic log has reduced the need for this calculation, as it sees shear waves
better than older array sonic logs. This new value of DTS should be substituted for the
original log data in the following sub-sections.
When lithology is known from sample descriptions or from detailed log analysis, the shear
travel time or velocity can be predicted from the porosity, lithology, and elastic constants
DTS = (DENS / DENSW * (DELTst ^ 2 - DELTW ^ 2)) ^ 0.5
WHERE:
DENS = density log reading (gm/cc or Kg/m3)
DENSW = water density (gm/cc or Kg/m3)
DTS = shear sonic log reading (usec/ft or usec/m)
DELTW = sonic travel time in water (usec/ft or usec/m)

Chart to calculate N
from DENS and DTS
Properties Of Rocks
Shear Modulus N, also abbreviated G or S or u (mu)

Properties Of Rocks
Poisson's ratio PR, also abbreviated with Greek letter NU (v) or SIGMA
Chart to calculate P from DTC and DTS Poisson’s ratio versus lithology

Properties Of Rocks
Bulk modulus Kb (also abbreviated B or L)
Chart for calculating Kb from P and N

Properties Of Rocks
Bulk compressibility Cb
Bulk Compressibility is the inverse of Bulk Modulus.
For rock with porosity:
For rock with no porosity:
This term is called rock compressibility and abbreviated Cr in some literature.
If the rock is anisotropic, both Cb and Cm can be calculated for the minimum and maximum
stress directions by using DTSmin and DTSmax from a crossed dipole shear sonic log.
N and Cb predict sanding (sand production) in unconsolidated formations. When log analysis
shows sanding may be a problem, sand control methods (injection of plastic or resin or gravel
packing) can be initiated. Sanding is not a problem when N > 0.6*10^6 psi. in oil or gas zones.
High water cuts increase the likelihood of sanding. This threshold corresponds to Cb of
0.75*10^-6 psi^-1. N/Cb > 0.8*10^12 psi^2 is a more sensitive cutoff than either N or Cb cutoffs.
High N/Cb ratios indicate low chance for sanding. A good cement job is also needed to reduce
sanding.
Cb = 1 / Kb
Cm = 1 / Km

Biot's Constant is the ratio of the
volume change of the fluid filled
porosity to the volume change of the
rock when the fluid is free to move
out of the rock
Properties Of Rocks
Biot’s Constant

Chart to calculate Y from P and N
Properties Of Rocks
Young's modulus Y (also abbreviated E)

Properties Of Rocks
Modulus of compressibility Kc
Pore Compressibility Kp (also abbreviated as Kf)
For rock with porosity, Kc = Kp + Kb + 4/3 * N.
For rock with no porosity, Kp = 0 and Kb = Km, so:
Kc = Km + 4/3 * N
By setting Kb = Km - 0.9 * N (empirical relation for sandstone only) and solving for Kp:
Kp = Kc - Km + 0.9 * N - 4/3 * N
The relationships for Kb and N have not yet been published for carbonates, and may not lead
to such a simple result.
Interpretation is based on the following:
IF Kp <= 1.5 THEN Zone is gas bearing
IF 1.5 < Kp < 3.5 THEN Zone is oil bearing
IF Kp >= 3.5 THEN Zone is water bearing
Kp is sometimes shown as Kf in the literature.
If conventional and shear seismic data are of sufficient quality to be inverted, then these
same equations can be used to detect fluid type in porous sandstones.

Calibrating Dynamic to Static
Constants
The mechanical properties of rocks derived from
log data, or from high frequency sonic
measurements in the lab are called dynamic
constants. Those derived in the laboratory from
stress strain tests or destructive tests are called
static constants.
Comparison of Poisson's Ratio
Since the tiny core plugs used for lab work have
been de-stressed and re-stressed a number of
times, there is some doubt that this cycle is truly
reversible, so lab measurements may not
represent in-situ conditions. The difference
between static and dynamic values are larger for
higher porosity, which suggests that some grain
bonds are easily broken by coring and subsequent
testing. It might be a wise move to calibrate
fracture design software to dynamic data, since
this data is more readily available, and may
actually have fewer inherent measurement
problems.

Static to dynamic transforms for
Young's Modulus
Calibrating Dynamic
to Static Constants

Mechanical properties log
Examples of Mechanical
Properties Logs

Calculating Overburden Pressure
Gradients
Overburden pressure is caused by the weight of the rocks above the formation pressing down
on the rocks below. This is sometimes called overburden stress - stress and pressure have the
same units of measurement.
Integrating the density log versus depth or estimating the average rock density profile and
integrating will calculate this pressure:
WHERE:
Po = overburden pressure (KPa or psi)
DENSi = density log reading at the i-th data point (Kg/m3 or gm/cc)
INCR = digital data increment (meters or feet)
KS9 = 0.01 for metric units
KS9 = 0.0605 for English units
Overburden pressure gradient is:
Po = KS9 * SUM (DENSi * INCR)
(Po/D) = Po / DEPTH

Calculating Normal Pore Pressure
Gradient
Normal pore pressures occur in many parts of the world. Normal pressure gradients depend
only on the density of the fluid in the pores, integrated from surface to the depth of interest.
Fresh water with zero salinity will generate a pressure gradient of 0.433 psi/foot or 9.81
KPa/meter. Saturated salt water generates a gradient of 0.460 psi/ft or 10.4 KPa/meter.
Formation pore pressure gradient is:
WHERE:
DEPTH = formation depth (ft or meters)
Pp = formation pressure (psi or KPa)
(Pp/D) = formation pressure gradient (psi/ft or KPa/meter)
Ps = surface pressure (psi or KPa)
KP1 = 0.433 to 0.460 psi/foot for English units
KP1 = 9.81 to 10.4 KPa/meter for Metric units
KP2 = 14.7 psi for English units
KP2 = 101 KPa for Metric units
Pp = KP1 * DEPTH
Ps = KP2
(Pp/D) = Pp / DEPTH
Pore pressure plot versus depth

Calculating Abnormal Pore
Pressure Gradient
In some formations, pore pressure is higher than normal. These are called overpressured or
abnormal pressured zones. The best source of pore pressure is still the extrapolated
formation pressures derived from DST or RFT data.
Some gas sands are naturally underpressured due to burial at depth with subsequent
formation expansion after surface erosion. There is also some suspicion that glaciation may
have pressured then relaxed these zones. Measured pressures are the only source of pressure
data for such zones.
Where overpressure data is sparse, a log analysis technique is sometimes helpful. It relies on
fitting lines to semi-log plots of sonic travel time in shale versus depth.
Calculate pore pressure gradient:
This equation is very sensitive to the choice of the normal trend line. The exponent 3 in the
equation may also need adjustment.
(Pp/D) = (Po/D) - ((Po/D) - 1) * (MIN (1,DTnorm/DELT))^3
Pp = (Pp/D) * DEPTH

Calculating Fracture Pressure
Gradient
A major use of mechanical properties from log analysis is in the design of hydraulic fracture
treatments to improve oil or gas well performance. Hydraulic fracturing is a process in which
pressure is applied to a reservoir rock in order to break or crack it. These cracks are called
fractures. Most hydraulic and natural fractures are near vertical and increase well productivity
significantly.
Hydraulic fracturing may use sand to prop the fracture open, so it cannot re-seal itself due to
the enormous pressure exerted by the overlying rock. Some reservoirs have natural fractures;
others need to have fractures added by us. Some wells flow oil and gas at rates that make
fracturing unnecessary.
Fracture optimization involves designing a fracturing operation that is strong enough to
penetrate the reservoir rock and yet weak enough not to break into zones where it is not
wanted. In addition, a cost effective design that minimizes time and materials is needed.
The fracture pressure is the pressure needed to create a hydraulic fracture in a rock. It is
determined by the overburden pressure (a function of depth and rock density), pore pressure,
Poisson's Ratio, porosity, tectonic stresses, and anisotropy. Breakdown pressure is the sum of
the fracture pressure and the friction effects of the frac fluid being delivered to the formation.
Breakdown pressure can be considerably higher than fracture pressure.

Calculating Fracture Pressure
Gradient
Stress regime – no tectonic stress tectonic stress

Calculating Fracture
Pressure Gradient
Fracture pressure gradient log

 A common correction method is to compare log analysis
stress profiles with individual results from single or
multiple mini-fracs. The correction may be a linear shift of
the log derived curve
 Mini-fracs or leak-off tests should be run to verify that the
computed fracture pressure is close to the leak-off
pressure.
Calibrating Fracture Pressure
Gradient
Leak-off pressure test versus time

Calculating Fracture Extent
FracHite log Fracture optimization model

 The fracture height determined from
observation of the gamma ray log is used in
type-curve-fit or simulation software, with the
treatment placement pressure curve, to
calculate fracture length (depth of penetration).
The fluid plus proppant volume is used in the
simulation to calculate fracture width
(aperture).
 Some fracturing companies use a spectral
gamma ray logging tool to locate different
radioactive tracer elements that have been
applied to different sized propping materials.
The finer sized proppants will show the deepest
penetration, with coarser material being
deposited closer to the wellbore. The spectralog
gives a 3-D image of the fracture length, height,
and width (aperture). These tracers have very
short half-lives (hours or days) so no permanent
radioactive signature is created
Gamma Ray Logging to Confirm
Fracture Placement

Determining Fracture
Orientation
Borehole diameter indicates stress direction - this example is from
India where the minimum stress direction is NE - SW.
Natural fractures take the same directions as hydraulic fractures,
indicated again by the borehole shape. In addition, the high angle
dips seen on an open hole dipmeter, will also indicate this
preferential direction. Since most hydraulic fracture jobs are run in
casing, it is not possible to run a dipmeter or caliper survey to find
the orientation of a hydraulic fracture. The preferential direction
can be predicted from previous open hole data. Dipmeter and
caliper data can be displayed on rose diagrams to illustrate
preferential directions

Dipole shear image log shows
directional stress - the Fast
Direction is centered on 90
degrees (east - west) which is
also the maximum stress
direction.
Determining Fracture
Orientation

Part 1 - Editing and Modeling Logs
Part 2 - Editing/Modeling Logs Case Histories
Part 3 - Synthetic Seismograms
Part 4 - Seismic Inversion / Synthetic Sonics
Part 5 - VSP, AVO, and Porosity/Lithology
SEISMIC PETROPHYSICS

 Seismic Petrophysics and Seismic Modeling
 Seismic Petrophysics and Well Log Modeling
 Logs Used for Seismic Petrophysics
 Log Editing Concepts
 Seismic Check Shots
 Editing Sonic Logs With SRS and VSP Data
 Modeling Sonic and Density Logs With Trend Data
 Modeling Sonic and Density Logs From Resistivity Data
 Modeling Sonic and Density Logs From Neutron Data
 Modeling Sonic and Density Logs With Regression
 Modeling Sonic and Density From Log Response Equation
 Modeling the Sonic Log in Vuggy Porosity
 Modeling the Sonic Log Response From Gassmann Equation
 Integrating the Sonic Log
 Acoustic Impedance and Reflection Coefficients
 Quicklook Log Analysis Calculations for Geophysicists
Part 1 - Editing and Modeling Logs

Seismic Petrophysics and
Seismic Modeling
Seismic petrophysics is a term used to describe the conversion of seismic data into meaningful
petrophysical or reservoir description information, such as porosity, lithology, or fluid content
of the reservoir. Until recently, this work was qualitative in nature, but as seismic acquisition
and processing have advanced, the results are becoming more quantitative.

Seismic Petrophysics and
Well Log Modeling
Log modeling or editing is required because logs don’t see the same rock and fluid mixtures
that the seismic signal sees. Drilling fluid invasion removes gas or oil near the wellbore,
replacing it with water and altering the sonic and density log response from the reservoir's
undisturbed values. Compensating for invasion is called "fluid replacement". Fluid
replacement calculations are also used in "what-if" scenarios to see what a gas filled reservoir
might look like on seismic
The log should be edited only where it needs it using common sense rules grounded in local
and regional trends. Few practitioners have hip pockets full of sonic and density trend data
applicable to their current projects.

 The two logs most used by geophysicists are the sonic (also
called acoustic) log) and the density log, because these two
rock properties determine the acoustic impedance and hence
the reflection coefficients of the rock layers. A synthetic
seismogram can be calculated from these data.
 Most other log curves are useful to the geophysicist. For
example, the neutron, density, photoelectric effect, and
spectral gamma ray (both natural and induced) can be used to
determine lithology quite accurately. This knowledge assists
seismic modeling and inversion or attribute interpretation.
Logs Used to Aid Seismic Petrophysics

Log Editing Concepts
If logs were perfect, editing would not be required.
However, logs can suffer from a number of problems,
such as:
1. misidentification of curves or scales
2. miscalibration
3. electronic failure
4. human failure
5. noise
6. depth discrepancies
7. poor borehole conditions
8. improper tool choice for the hole conditions
9. environmental effects such as temperature, mud
salinity, mud type, mud weight
10. bed boundary and bed thickness effects
11. deviated boreholes
Sonic log before and after edit

 On density logs, the worst cases are
caused by large or rough borehole, which
often occurs in shale sections, in stress
relieved carbonates, and in gas bearing
formations. An example of a
reconstructed density log, corrected for
bad hole and rock alteration
 If regional trends for sonic and density
data are known for each major lithology
(shale, sand, carbonates), these can be
used to draw a more reasonable log.
Log Editing Concepts
Sonic and density editing based on lithology and trend analysis

 The seismic reference survey (SRS), often
called a seismic check shot survey, is
designed as a calibration mechanism for
reflection seismic data. In such a survey,
seismic velocities are measured in the
borehole by recording the time required
for a seismic pulse generated by a surface
energy source to reach a geophone
anchored at various levels in the borehole
 The recorded travel times are used to
calibrate the sonic log, which then
becomes the basic seismic calibration
reference. A time versus depth plot is
produced from these data
Seismic Check Shots

The calibrated sonic and the density logs
(Figures) are used to construct a
synthetic seismogram, which allows
identification of reflecting horizons by
reference to the seismic response at the
wellbore.
Seismic Check Shots

Editing Sonic Logs With SRS or
VSP Data
Seismic times obtained through the integration of a sonic log usually differ from those obtained by means
of a seismic pulse (surface surveys or check shots) for many reasons. These range from basic discrepancies
between the two approaches to disturbances in sonic readings caused by cycle skipping, detection of mud
arrivals in large holes, formation alteration, and invasion.
Plot of sonic log drift correction from checkshot survey
Seismic checkshot times are used as a reference to calibrate the
sonic log through a process called drift curve correction. The
drift curve is a log of the difference between integrated sonic
log time and check shot seismic time. When integrated sonic
log times are higher than seismic times (the usual case), drift is
negative.
Drift is made equal to zero at an arbitrary depth, the tie point,
often the top of the sonic log when, as it should be, a checkshot
is available at that depth. Drifts are plotted at each shot depth.
Then a curve is drawn, as segments of straight lines fitting the
drift points as well as possible. The junction of two such
segments is called a "knee". A knee should not be necessarily
located at a checkshot point, but where there is a change of
lithology or of sonic character

Editing the Sonic and
Density Logs With Trend Data
Editing sonic with trend analysis
Editing density with trend analysis

Modeling the Sonic and
Density Logs From Resistivity
1. Faust Method
This method is very old, but is useful in shallow rock sequences, especially clastics. You
may need to determine new parameters for each major geologic horizon.
Where:
Vc = compressional velocity (ft/sec or m/sec)
KR1 = Faust constant (2000 to 3400 for depths in feet)
RESS = resistivity from shallow investigation log (ohm-m}
DEPTH = depth of layer (ft or m)
KR2 and KR3 = 6.0 or as determined by regression analysis
The Faust transform can be used when the sonic log is missing, and can be calibrated with
offset well data, check shots, or vertical seismic profiles. The method does not account for
gas effect.
Vc = KR1 * RESS ^ (1/KR2) * DEPTH ^ (1/KR3)

Modeling the Sonic and Density
Logs From Resistivity
2. Smith Method
This method uses a simple correlation between resistivity and sonic traveltime:
Where:
DELTc = compressional travel time (usec/ft or usec/m)
KR4 = Smith constant (90 to 100 for depths in feet)
RESS = resistivity from shallow investigation log (ohm-m}
KR5 = -0.15 or as determined by regression analysis
The method does not account for gas effect. You may need to determine new parameters
for each major geologic horizon.
DELTc = KR4 * (RESS ^ KR5)
3. Fischer - Good Method
This method assumes a fairly sophisticated log analysis can be run on the well in question
or on a nearby well. This is needed to obtain a list of water resistivity (RWA) versus depth.
Since most sonic log problems are in shales due to bad hole or rock alteration, this
calculation is usually possible and should be done continuously or at least zone by zone.

Logs From Neutron Data
One log that is relatively unaffected by noise and bad hole effects is the neutron log. It is a good
source of total porosity (PHIt) and can be used in the time average equation to generate a sonic
log:
This can be rewritten in its more usual form as:
Neutron logs can be run through casing and many are available in well files where no sonic or a
poor sonic is present. Because neutron and sonic logs respond similarly to shale, no special shale
compensation is needed with this method.
The density log is not as strongly affected by shale, so it requires more attention to detail:
PHIN is too low in gas zones, giving DELTmod too low and DENSmod too high
DELTmod = DELTMA + (DELTW - DELTMA) * PHIN
DELTmod = DELTMA * (1 - PHIN) + DELTW * PHIN
Vshg = (GR - GR0) / (GR100 - GR0)
Vshs = (SP - SP0) / (SP100 - SP0)
Vsh = Min (Vshg, Vshs)
PHIe = PHIN - (Vsh * PHINSH)
DENSmod = (1 - Vsh - PHIe) * DENSMA + DENSW *
PHIe + Vsh * DENSSH

Response From Regression
Jay Patchett proposed a sonic editing technique in 1975 for shales, based on the following:
Where:
CEC = cation exchange capacity of the shale
ES = effective stress (psi)
Since CEC is not readily available in most wells, this approach was not terribly practical.
However, by recognizing other work that related CEC to gamma ray log response, the equation
becomes:
For shale zones:
A similar equation for density is:
For sandstones:
Where:
PHIrs = porosity from the shallow resistivity log
These models are decidedly not simple and a great deal of calibration is required to make them
work. Practitioners should refer to the original paper for details of the method. In addition, a
sophisticated multiple linear regression program is required.
log (COND) = A0 + A1 * log (DELT - 42) + A2 * log (CEC) + A3 * log (ES)
log (DELTmod - 40) = KW0 + KW1 * log (RSH) + KW2 * log (GR) + KW3 * log (ES)
DENSmod = KX0 + KX1 * GR + KX2 * DEPTH + KX3 * log (RSH)
DELTmod = KY0 + KY1 * GR + KY2 * log(ES) + KY3 * PHIrs
DENSmod = KZ0 + KZ1 * GR + KZ2 * DEPTH + KZ3 * PHIrs

Modeling Sonic and Density From
Log Response Equation
1. Density Log Response
The response of a density log can be described rigorously by a volume weighted summation
of the densities of the individual components in the rock.

Modeling Sonic and Density From
Log Response Equation
2. Sonic Log Response
An equation similar to that for density can be generated for sound velocity of mixtures.
However, it is a summation of travel time weighted by volume and not a summation of velocity
components

Modeling the Sonic Log in Vuggy
Porosity
An additional factor must be included to determine the travel time, (and hence seismic velocity)
in a vugular rock. The acoustic travel time measured by a sonic log is the shortest time path. Thus
the travel time will be lower than a path which includes segments through large vugs. This is
different than the seismic signal which is affected by the vuggy porosity, because the seismic
frequency is very low compared to a sonic log signal.
We can define the porosity term to include a vuggy porosity fraction:
The porosity formed by vugs, and not "seen" by the sonic log can be found by log analysis if a full
suite of logs is available. For log analysis purposes this porosity is defined as:
The sonic log will read too low a travel time (too high a velocity) in most vuggy rocks, which
accounts for short integrated times in many reef carbonates. Therefore the log must be edited,
or modeled, over this interval before a synthetic seismogram is made, even in a water or oil
zones, where modeling would not normally be needed. Use the modeling equations defined in
the previous section along with a true porosity from density neutron log analysis, from core
porosity, or from estimates of the vuggy fraction in the zone.
CAUTION: Synthetics and integrated times will not tie seismic unless you do this step in all vuggy
zones. Synthetics are often too short through vuggy reef sections because of this problem.
PHItrue = PHIsc + PHIvug
PHIvug = PHIxnd - PHIsc

Modeling the Sonic Log Response
From Gassmann Equation
An alternate and more rigorous approach is the Gassmann equation:
Gassmann's approach looks deceptively simple. However, the major drawback to this
approach is the difficulty in determining the bulk moduli, particularly those of the empty rock
frame (B1 and K1), which cannot be derived from log data. However, Kc can be calculated
directly from compressional and shear velocity or travel time if they are available, which
eliminates the need to calculate Kc from the Gassmann method.
Remember that this will be a liquid filled value due to mud filtrate invasion. Therefore,
equation 1 must be solved for K1 using a log derived Kc, Bo, and Bs, and listed values for Bf and
B1.
Kf = Sw / Cwtr + (1-Sw) / Coil
Kf = Sw / Cwtr + (1 - Sw) / Cgas
Kc = Km + ((1 - B1 / N) ^ 2) / (PHIe / Kf + (1 - PHIe) / Km - Kc / (N^2))
Vp = (Kc / DENS) ^ 0.5

Integrating the Sonic Log
Integration is a summation of the sonic log readings taken at equal depth
increments. This is often adjusted to a datum depth or time horizon, not
necessarily the surface. Because the sonic log depth is measured relative
to the surface but cannot often be recorded all the way to the surface, we
also have to estimate or tie the sonic integrated time to a known horizon
below the surface casing. The checkshot survey plays an important role in
tying the sonic to surface or some other datum.
The formula is:
Where:
Tsurf = Two way time from surface to start of sonic log (ms)
Tdatum = Two way time from surface to desired datum (ms)
DELTcor = Edited sonic log reading adjusted to SRS or VSP (us/m or us/ft)
INCR = Digitizing increment (meters or feet)
A computed log analysis on two-way time scale with VSP or synthetic
seismogram traces allows accurate horizon picks and correlation of
attributes to lithology or fluid content,
T2way = Tsurf - Tdatum + 2 * Sum (DELTcor * INCR)

 Sound is reflected back toward the source
of energy whenever an acoustic impedance
boundary occurs or Poisson's ratio
changes. Acoustic impedance is the product
of velocity and density. Energy is also lost
due to reflection and spherical divergence
 The reflection coefficient will vary with
incidence angle, equivalent to a variation
with offset distance. Attenuation is seldom
applied to reflection coefficient data, as
synthetics are often compared to gain
equalized data, in which attenuation has
been compensated.
Acoustic Impedance and
Reflection Coefficients

Quicklook Log Analysis Methods
for Geophysicists
To repair a log, or to compute what the log should have read in an undisturbed formation, or
to create a model of a hypothetical rock sequence, it is necessary to perform a quantitative
log analysis. The rock properties of most interest for geophysical modeling are:
1. shale volume
2. effective porosity and pore geometry
3. lithology
4. water saturation and hydrocarbon type - gas, oil
Other factors, such as permeability and productivity, are also computed for reservoir
evaluation, but they play only a minor role in seismic evaluation.
The rock model and its intrinsic response equation are described fully in Chapters Four
through Ten. The response equation determines the way a logging tool responds to a
mixture of rocks and fluids. By solving the response equations, either singly or as pairs and
triplets of simultaneous equations, we can calculate nearly anything we need to know about
a formation.

 Swan Hills reef section in the
Rosevear area of Alberta with
significant gas filled porosity. It
contains the log analysis results
and seismic results (acoustic
impedance and reflection
coefficients) on a highly
compressed depth scale. Formation
tops are shown and the modeled
interval is marked.
 Reflection coefficient, acoustic
impedance, and log analysis before
and after gas model - depth scale
 Seismic traces, acoustic impedance,
and log analysis before and after
gas model - time scale
Case Histories: Log Editing and
Modeling

 Case History - Layer
Replacement on a Reef
 The reef is thinned from its
maximum thickness down to
zero to see what the seismic
signature looks like for each
case.
Case Histories: Log Editing and
Modeling

Seismic Modeling Concepts
Seismic modeling is a loosely defined term. It has been taken to include any or all of the
following:
1. compute seismic response from a postulated rock sequence, using assumed velocity and
density values for successive layers
2. compute seismic response from unedited well logs (sonic or density or both)
3. compute seismic response from modeled and edited log data values to reflect real or
hypothetical fluid, porosity, shale, and matrix rock quantities or types
The latter form of modeling is by far the most successful, but it requires an extra step -
quantitative log analysis and log reconstruction. Synthetic seismograms will NOT be adequate
unless this extra work is done.
There are five major reasons why log editing or log modeling may be necessary:
1. large or rough boreholes that prevent accurate logs from being recorded (Eg: cycle skips
on sonic logs)
2. invasion of drilling fluid into gas or light hydrocarbon zones
3. vuggy or isolated porosity types
4. rock alteration by the drilling process
5. missing density or sonic information (not recorded or tool not working properly)

Step By Step Procedure for
Seismic Modeling
four basic definitions:
1. forward seismic modeling - making a synthetic
seismic trace from EDITED sonic and density log data.
2. inverse seismic modeling - making a synthetic
acoustic impedance log from a seismic trace.
3. seismic interpretation - making correlations,
picking horizons, and mapping seismic data, with
geological and well log data for control.
4. modeling a log - calculating what a log should
read in a given rock and fluid mixture, including the
creation of synthetic sonic and density logs from
other logs or geological/seismic data.

Step By Step Procedure for
Seismic Modeling
The steps in making a synthetic seismogram are:
1. edit the sonic and density log for borehole and recording problems, based on regional
trends, offset logs, and mathematical models of log response
2. model sonic and density logs in formations which have been affected by invasion or rock
alteration, based on a comprehensive quantitative log analysis
3. model effects in carbonates caused by porosity type or density contrast, based on log
analysis and geologic data
4. integrate the modeled and edited sonic log
5. interpolate equal time increment values for sonic and density (and other log) values from
depth data
6. calculate acoustic impedance and reflection coefficients from modeled and edited logs
7. generate an appropriate wavelet
8. convolve wavelet with reflection coefficients
9. plot synthetic seismogram on an appropriate time scale
10. check results against real seismic data
11. revise edits or log models over intervals that do not match real seismic, OR improve seismic
processing, OR change wavelet characteristics
12. make "What-if" models to test alternate interpretations and sensitivity to fluid, porosity, and
lithology assumptions, as well as wavelet shape and frequency
13. remodel zones which do not tie as to time, amplitude, or character, and check again

Synthetic seismograms with
multiple reflections
Step By Step
Procedure for
Seismic Modeling

 Sound is reflected back toward the source
of energy whenever an acoustic
impedance boundary occurs or Poisson's
ratio changes. Acoustic impedance is the
product of velocity and density.
 The reflection coefficient will vary with
incidence angle, equivalent to a variation
with offset distance. Attenuation is seldom
applied to reflection coefficient data, as
synthetics are often compared to gain
equalized data, in which attenuation has
been compensated.
 If density log data is missing or cannot be
used due to bad hole conditions, an
appropriate constant value or a value
derived from the empirical chart
Acoustic Impedance and
Reflection Coefficients
Acoustic impedance from velocity

If a wavelet can be extracted by
autocorrelation of a real seismic trace, it
should be used to make the synthetic. If this
cannot be done, wavelets are generated
from equations which describe the
frequency content of the wavelet. There are
two types - Ricker wavelets are generated
directly in the time domain and Klauder
wavelets are generated in the frequency
domain. Both are called zero phase wavelets
and are minimum delay, that is the
maximum energy is at the beginning of the
wavelet
Calculating Seismic Wavelets

 Filtered sonic logs
 Separating low and high
frequency components on a sonic
log
 Low frequency content of a sonic
log
Seismic Inversion and Synthetic
Sonic Logs

 Low frequency component of sonic log
 Comparison of filtered sonic log and seismic
inversion trace
Capturing Low Frequency
Components

 Inverted seismic section
 Seismic inversion section with interpreted
lithology based on velocity contours
Displaying Seismic Inversion
Traces

Case Histories: Seismic Inversion

 Vertical Seismic Profiles On Wireline
 Vertical Seismic Profiles While Drilling
 Case Histories: Vertical Seismic Profiles
 Amplitude Versus Offset (AVO)
 Amplitude Versus Offset Case Histories
 Porosity/Lithology From Shear Seismic
VSP, AVO, and Porosity/Lithology

Vertical Seismic Profiles On
Wireline
The processing sequence is as follows:
1. shot selection to eliminate dead or noisy
traces
2. trace editing to mute early arrivals
3. consistency check of surface geophone
signal
4. stacking of shots taken at the same level
5. bandpass filter to reduce noise and
aliasing
6. f-k filter to eliminate tube waves
7. amplitude recovery
VSP geometry and schematic of up- and down-
going reflections

Wireline
8. down going signal alignment
9. velocity filtering to separate down going
from up going components
10. predictive deconvolution to remove multiple
reflections
11. autocorrelation to check multiple removal
12. automatic gain control
13. time variant filtering to match conventional
seismic section
14. corridor stacking to sum all the up going
waves
VSP, synthetic seismogram, inverted VSP, and
original sonic log

Open and cased hole VSP
comparison
Wireline

Vertical Seismic Profiles While
Drilling
VSP while drilling
VSP while drilling - geometry and recorded traces
after deconvolution

Case Histories: Vertical Seismic
Profiles
Dipmeter with fault
VSP, sonic, and inversion with fault

 SP used to predict top of overpressure zone
 Example shows seismic section and VSP
overlay. Overpressure indications on VSP
inversion trace predict required mud
weights and potential drilling difficulty.
Sonic and density trace from logs in final
hole confirm the presence of overpressure
at the same depth as the VSP prediction.
Case Histories: Vertical Seismic
Profiles

Amplitude Versus Offset (AVO)
A technique used to differentiate seismic reflection events caused by lithology changes from
those caused by fluid changes is called amplitude versus offset, or AVO, processing. The
effect is caused by the fact that the reflected energy depends not only on the acoustic
impedance but also on the angle of incidence of the reflecting energy.
The contribution of this second effect is often ascribed to the difference between Poisson's
ratio of the layers. However, the equations clearly show the cause to be the difference in
compressional velocities:
Vrat = V1 / V2
Drat = DENS1 / DENS2
C = (Vrat^2 + (1 - Vrat^2) / (Cos (ANGLE))^2) ^ 0.5
Refl = (1 - Vrat * Drat * C) / (1 + Vrat * Drat * C)

 AVO models (oil, gas, shale) and real
data
 a Cretaceous Glauconitic channel sand.
Amplitude Versus Offset Case
History

Porosity/Lithology From Shear
Seismic
Shear amplitude and velocity

Porosity/Lithology Case History
Compressional wave inverted velocity section Shear wave inverted velocity section

Porosity/Lithology Case History
Poisson's ratio seismic section
Lithology from shear and compressional velocity

Sonic and Density Logging Tools
Elastic Properties of Rocks
Seismic Petrophysics
Dipmeter Logs
Dipmeter and Image Log Calculations
Fractured Reservoir
Structural Analysis
Stratigraphic Analysis

 Evolution of the Dipmeter Concept
 Modern Dipmeters
 Basic Continuous Dipmeter Calculations
 Handling Correlation Planarity Error
 Determining Dip By Clustering and Pooling
 Pattern Recognition Dip Calculations
 Stratigraphic High Resolution Dipmeter
DIPMETER LOGS

∗ Photoclinometer for
recording dipmeter data
Evolution of the Dipmeter Concept
Computed microlog dipmeter results circa mid-1950's
Photoclinometer for recording dipmeter data

Modern Dipmeters
Arrangement of tool components for 4-pad
dipmeter High resolution dips compared to core

Basic Continuous Dipmeter
Calculations
Dipmeter computation definitions Regional and stratigraphic dipmeter computation
using different correlation interval

Coding non-planar dips
helps interpret
sedimentary bedding
Handling Correlation Planarity
Error

Dip plot of clustered and pooled data
(left), dip fan or range plot (right)
Determining Dip By Clustering
and Pooling

Pattern Recognition For Dip
Calculations
Dip curve pattern recognition definitions
The method of correlation by pattern
recognition is composed of two main
phases:
- feature extraction (detection of curve
elements)
- correlation between similar features
In phase one, each curve is analyzed
individually with reference to a catalog
of standard patterns or types of curve
elements, such as peaks, troughs,
spikes, and steps, and is decomposed
into a sequence of such elements. At
the end of the feature extraction
phase, the curves are replaced by their
description in terms of elements.

Core comparison to pattern recognition dip
program GEODIP
Pattern Recognition For Dip
Calculations

1. MSD Dips (Mean Squares)
2. CSB Dips (Continous Side-by-Side)
3. LOC Dips (Local Derivative)
Stratigraphic High Resolution Dip
Calculations

 Formation Imaging From Dipmeters
 Resistivity Microscanner Imaging
 Dipmeter Advisor - An Expert System
 Auxiliary Dipmeter Presentations
 Synthetic Dipmeter Curves
 Dipmeter Calculations
 Dip Subtraction and Rotation
 True Stratigraphic and True Vertical Thickness
 True Vertical Depth
DIPMETER AND IMAGE LOG
CALCULATIONS

Formation Imaging From
Dipmeters
The program produces a 360 degree image of the borehole wall by interpolating between the eight resistivity
measurements from the eight electrodes on the SHDT pads

Resistivity Microscanner Image
Logs
Formation microscanner images in various
environments

Dipmeter Advisor - An Expert
System

 The cross section plot or stick
diagram, is a two dimensional cross
section representing the dipping
bedding planes at a pre-selected
azimuth
 It shows the apparent dip of each
bedding plane as it would cross the
borehole at the specified cross
section azimuth. A common use is to
establish the dip expected between a
well with computed dipmeter
information and a projected well
close to the original well, or between
two wells.
Auxiliary Dipmeter Presentations

 The cylindrical plot is a two-dimensional
presentation that has the appearance of
the borehole split along the south axis.
When placed in a transparent cylinder
 The cylindrical plot is especially useful for
locating the position of faults or major
unconformities where these are reflected
by a change in dip direction or magnitude

The modified Schmidt diagram is used
to determine structural dip when it is
hard to find from the arrow plot. The
paper is polar with North at the top. Dip
magnitudes are represented by
concentric circles. The plot is divided
into cells at 1 degree magnitude and 10
degree azimuth; the dots are plotted
for all dips computed. In some cells
there may be no dots; in others, one
dot; in still others, two or more dots.
The plot can be generated by hand or
by computer

Azimuth frequency plots, often called
rose diagrams, are plotted on polar
coordinate paper with north at the
top and 10 degree azimuth
increments. The length of each 10
degree segment is proportional to the
number of dips in the interval having
that azimuth range, with zero
frequency at the center. The result
will be little fans originating at the
center which may be composed of
structural dip and current patterns,
often at right angles to each other.

Regional dip removal changes the dip
patterns, making sedimentary interpretation
easier

Synthetic Dipmeter Curves was
developed to quantify and display
synthetic curves calculated from the
dipmeter resistivity and computed
dip data. This program calculates up
to seventeen variables, some of
which are displayed to present a
geologic description of the
formations in terms of bedding and
relative grain size information.
Synthetic Dipmeter Curves

The method is based on hand measurements of curve offsets from the raw dipmeter
curves and readings from the hole direction data. These equations are for the four arm
dipmeter and ignore closure and planarity errors
Dipmeter Calculations

Dip Subtraction and Rotation
Dip subtraction is used to translate actual dip to dip with regional dip removed. The result is
used to assess the actual angles of crossbedding or fault planes relative to horizontal strata. If
you do not have a dip removed arrow plot, you may have to perform this calculation on a few
dips to find depositional dip patterns. The equations are:
NEWDIP = Arccos(Cos SD * Cos DIP + Sin SD * Sin DIP * Cos(AZM - SDAZ))
ANGLS = Arccos((Cos DIP - Cos SD * Cos NEWDIP) / (Sin SD - Sin NEWDIP))
IF Sin (AZM - SDAZ) >= 0
THEN NEWAZM = SDAZ + 180 - ANGLS
Otherwise NEWAZM = SDAZ - 180 + ANGLS
NEWAZM = 360 * Frac((NEWAZM + 360) / 360)
Where:
ANGLS = intermediate term
AZM = true dip azimuth before structural dip removal
DIP = true dip angle before structural dip removal
NEWDIP = dip after structural dip removal
NEWAZM = azimuth after structural dip removal
PROJDIP = Arctan (Tan DIP * Cos (PROJAZM - AZM))
SD = structral (regional) dip to remove
SDAZ = azimuth of structural dip
PROJDIP = projected dip
PROJAZM = projected azimuth

True stratigraphic and true vertical thickness are
important in dipping beds and in deviated holes,
since reservoir volume depends on these properties
and not the measured thickness.
True Stratigraphic and True
Vertical Thickness
TST = MT * (Cos WD * Cos DIP - Sin WD * Sin DIP * Cos (HAZ - AZM))
TVT = TST / Cos DIP
Where:
AZM = true dip azimuth
DIP = true dip angle
HAZ = azimuth of hole direction relative to true north
MT = measured thickness (feet or meters)
TST = true stratigraphic thickness (feet or meters)
TVT = true vertical thickness (feet or meters)
WD = well deviation angle

True Vertical Depth
1. Tangential Method
The tangential method uses only the inclination and direction angles measured at the lower end
of the survey course length. The well bore path is assumed to be a straight line throughout the
courseThe formula are:
TVD = SUM ((MD2 - MD1) * Cos WD2)
2. Average Tangential Method
The angle averaging method uses the angles measured at both the top and bottom of the course
length in such a fashion that the simple average of the two sets of measured angles is assumed to
be the inclination and the direction.
TVD = SUM ((MD2 - MD1) * Cos ((WD2 + WD1) / 2))
3. Balanced Tangential Method
The balanced tangential method uses the inclination and direction angles at the top and bottom
of the course length to tangentially balance the two sets of measured angles. This method
combines the trigonometric functions to provide the average inclination and direction angles
which are used in standard computational procedures.
TVD = SUM ((MD2 - MD1) * (Cos WD2 + Cos WD1) / 2)

True Vertical Depth
4. Mercury Method
The mercury method is a combination of the tangential and the balanced tangential method that treats that
portion of the measured course defined by the length of the measuring tool in a straight line (tangentially) and
the remainder of the measured course in a balanced tangential manner.
TVD = SUM (((MD2 - MD1 - STL) * (Cos WD2 + Cos WD1) / 2) + STL * Cos HAZ2)
Where:
STL is the length of the survey tool
5. Radius of Curvature Method
The radius of curvature method uses sets of angles measured at the top and bottom of the course length to
generate a space curve (representing the wellbore path) that has the shape of a spherical arc passing through
the measured angles at both the upper and lower ends of the measured course.
TVD = SUM (MD2 - MD1) * (Sin WD2 - Sin WD1) / (WD2 - WD1)
6. Minimum Curvature Method
The minimum curvature method, like the radius of curvature method, takes the space vectors defined by
inclination and direction measurements and smooths these onto the wellbore curve by the use of a ratio factor
which is defined by the curvature (dog-leg) of the wellbore section.
TVD = SUM (((MD2 - MD1) * (Cos WD2 * Cos WD1) / 2) * CF)
Where:
DL = dog leg severity (degrees)
CF = curvature factor

FRACTURED RESERVOIRS
Part 1 – Fracture Identification
Definition of Fractures
General Methods For Identification Of Fractures
Fracture Identification From Core Analysis
Fracture Identification From Spontaneous Potential Logs
Fracture Identification From Caliper Logs
Fracture Identification From Micro Resistivity Logs
Fracture Identification From Dipmeter Logs
Fracture Identification From Density, Neutron, and PE Logs
Fracture Identification From Gamma Ray Logs
Fracture Identification From Resistivity Logs
Fracture Identification From Temperature Logs
Fracture Identification From Sonic Logs
Fracture Identification From Sonic Waveform Logs
Fracture Identification From Formation Microscanner Logs
Fracture Identification From Borehole Televiewer Logs

Part 2 – Quantitative Models
Log Overlays and Crossplots to Quantify Fractures
Calculating Permeability From Stoneley Attenuation
Calculating Formation Strength
Calculating Fracture Intensity (Crain’s Method)
Calculating Fracture Intensity and Initial Flow Rate (Schafer’s Method)
Calculating Fracture Porosity and Fracture Permeability from Fracture Aperture
Part 3- Dual Porosity Model
Basic Resistivity Concepts in Fractured Reservoirs
The Double Porosity Model in Fractured Reservoirs
Water Saturation in the Double Porosity Model
Case Histories: Fracture Analysis

 A fracture is a surface along which a
loss of cohesion in the rock texture
has taken place. A fracture is
sometimes called a joint and, at the
surface, are expressed as cracks or
fissures in the rocks.
 The orientation of the fracture can
be anywhere from horizontal to
vertical. The rough surface
separates the two faces, giving rise
to fracture porosity. The surfaces
touch at points called asperities.
Altered rock surrounds each surface
and infilling minerals may cover
part or all of each surface. Minerals
may fill the entire fracture,
converting an open fracture to a
healed or sealed fracture.
Definition of Fractures

 Fractures are caused by stress in the formation, which in turn usually derives from tectonic
forces such as folds and faults. These are termed natural fractures, as opposed to induced
fractures. Induced fractures are created by drilling stress or by purposely fracturing a
reservoir by hydraulic pressure from surface equipment
 Natural fractures are more common in carbonate rocks than in sandstones. Some of the best
fractured reservoirs are in granite – often referred to as unconventional reservoirs.
Fractures occur in preferential directions, determined by the direction of regional stress.
This is usually parallel to the direction of nearby faults or folds, but in the case of overthrust
faults, they may be perpendicular to the fault or there may be two orthogonal directions.
Induced fractures usually have a preferential direction, often perpendicular to the natural
fractures.

 Most well logs respond in some way to the presence of fractures. Not all logs detect
fractures in all situations, and very few see all fractures present in the logged interval.
Bear in mind that other borehole and formation responses will be superimposed on each
log. Moreover, it is not normal to analyze a single log in isolation, but to review all log
curves together to synthesize the best, most coherent, result.
 Logs used to detect fractures; Core Analysis, Spontaneous Potential Logs, Caliper Logs,
Micro Resistivity Logs, Dipmeter Logs, Density, Neutron, and PE Logs, Gamma Ray Logs,
Resistivity Logs, Temperature Logs, Sonic Logs , Sonic Waveform Logs , Formation
Microscanner Logs , Borehole Televiewer Logs
General Methods For
Identification Of Fractures

The possibility and confirmation of fractures from :
1.Drilling characteristics: occurrence of lost circulation or mud loss, abrupt drilling breaks, bit
bouncing or torqueing, mud weight reduction, well kicks, oil on the mud pit surface, large
de-gasser volumes, oil or gas shows on mud logs, calcite in well cuttings coming from
fracture incrustations or veins may be indications of fractures. A review of the well history
file is an important source of knowledge for the log analyst.
2.Sample descriptions: observation of fractures, slickensides, calcite in healed fractures,
blocky or fissile texture may indicate fractures.
3.Inflatable packers: an impression of the borehole wall can be imprinted on the rubber
when the packer is set in place. If fractures are present, they will be seen, but there is no way
to tell if they were induced by drilling or were present before drilling.
4.Drill stem testing: analysis of pressure transient data from flow and buildup tests has been
used extensively to indicate the presence of fracturing.
General Methods For
Identification Of Fractures

Fracture Identification From Core
Analysis

 Minor SP development in fractured zone, may be
caused by a streaming potential due to mud
filtrate flow into the formation at these depths.
This is not certain.
 Many factors influence the SP and it is difficult to
identify fractures directly using this method
alone, but often it aids in confirming the
possibility of a fractured zone
Fracture Identification From
Spontaneous Potential Logs

The caliper recorded with the microlog is
designed to float on top of the mudcake. It
will respond and measure the thickness of
the mudcake, instead of measuring borehole
rugosity. The presence of mudcake should be
more conclusive of permeability and possible
fracturing than rugosity alone. Dipmeter
pads are pressured to cut through mudcake
and usually measure the rough hole if it is
present. Other dipmeter curves are also used
to identify fractures.
Caliper Logs
Above show significant hole elongation on the caliper. Fractures are inferred from this and
confirmed by the dipmeter curves. Fracture orientation is roughly NE - SW.

 Micro resistivity logs, such as microlog and micro
SFL, indicate fractures by showing low resistivity
spikes opposite open fractures, and high resistivity
spikes opposite healed fractures and tight or
highly cemented layers.
 The permeable zone contains three distinct
fractures with several more tiny conductive spikes
that could indicate fractures. Only one is seen by
the proximity log.
Micro Resistivity Logs

 High resolution dipmeters with 4, 6, or 8 micro-conductivity log curves, 2 or 3 opposed
calipers, plus directional and orientation data can indicate fractures by visual observation of
log curve characteristics and from individual dip magnitude and direction calculations. Hole
enlargement in a preferential direction caused by fractures, is easily displayed from the
multi-arm caliper data
 Semi-vertical fractures usually cause a relatively long conductive anomaly on two opposite
pads, or on one pad if the fracture is off axis enough to be missed by the opposite pad. A
typical vertical fracture
Dipmeter Logs

 If the density log shows
high porosity spikes that
are not seen by the
neutron log, usually
fractures, large vugs, or
caverns exist. Broken out
borehole also causes the
same effect, but fractures
are often present when
this occurs
 Large density correction
values in competent rock,
especially when weighted
muds are used, is a
fracture indicator.
 PE curve shows fractures
in barite weighted mud
Density, Neutron, and PE Logs

 The natural gamma ray spectral log provides a
quantitative measurement of the three primary
sources of natural radioactivity observed in
reservoir rocks: potassium, uranium, and
thorium.
 If the gamma ray derived shale volume is higher
than the others, uranium in fractures may be
suspected.
 CAUTION: In some areas, fractures are never
radioactive, so this method is not always
suitable.
Gamma Ray Logs

 Shallow resistivity cross over shows fractures
 The shallow resistivity log may read the
resistivity of drilling mud in washed out
borehole sections caused by the presence of
fracturing. Check the log heading and compare
the mud resistivity, corrected for the
temperature of the borehole, with the actual
log reading.
Resistivity Logs

 Temperature log may locate fractures
 Mud fluid invasion into a fractured zone can
lower its temperature. If logged before it can
return to the geothermal temperature, the
presence of fractures or, at least, invasion can
be confirmed. It is possible that the invasion is
merely a function of porosity, but usually the
effect is smaller than for fractures.
Temperature Logs

 Sonic log cycle skips may indicate fractures
 Cycle skipping is an excellent fracture
indication in hard formations.
 Shallow resistivity crossover might help
confirm fractures in a typical well with only an
induction and sonic log.
Sonic Logs

 Sonic ampliude log may indicate fractures
 The sonic amplitude log is a curve representing the
first arrival energy, measured in millivolts. Energy
varies with many factors, so absolute values mean
little, but low amplitude often means fractures. All
the things that cause cycle skipping, described
above, cause low amplitude, so fractures are only
one possibility.
 Shear attenuation may locate fractures or vuggy
porosity These attenuations result primarily from
the large contrast in acoustic impedance between
the rock matrix and the fluid in the fractures and in
porosity. As compressional and shear waves
traverse a fracture their energies are significantly
attenuated with the greatest attenuation occurring
to the shear wave.
Sonic Waveform Logs

 The formation micro-scanner (FMS) or the
newer formation micro-imager (FMI) is an
array of electrodes on pads used to produce
an electrical image of the formations seen on
the borehole wall.
 FMI log in fractured granite reservoir
showing computed dip angle and direction
Formation Micro-scanner Logs

 The borehole televiewer image is similar in
appearance to a formation micro-scanner, but
uses an ultrasonic derived, directionally
oriented, 360 degree view of the borehole wall.
Such an image, created by a conventional
televiewer, has sufficient resolution to see
major fracture systems in good hole conditions
 The televiewer log of the wellbore is a
representation of the amount of acoustic
energy received at the transducers, which is
dependent upon rock impedance, wall
roughness, wellbore fluid attenuation, and hole
geometry.
Borehole Televiewer Logs

Quantitative fracture methods include fracture
intensity calculations that help to discriminate
between lightly fractured and heavily fractured
intervals. Fracture porosity and fracture
permeability are covered as well as secondary
porosity index and Pickett plots for finding the
cementation exponent, M.
Quantitative Models

 Sonic/density or sonic/neutron porosity overlay
presentations help find vugs and caverns in
carbonates. Fractures are often associated with these
porosity types. Sonic derived porosity is generally
considered to be intergranular or intercrystalline
(primary) porosity, whereas density or neutron
derived porosity measures primary (intergranular or
intercrystalline) plus secondary (vuggy, solution, or
fracture) porosity.
 The cross hatched area on the log defines zones where
density porosity is greater than sonic porosity. In this
case, it looks like the difference is due to rough or
large hole, and not entirely to fracture porosity.
However, the presence of fractures is almost certain.
Log Overlays and Crossplots to
Quantify Fractures

Log Overlays and Crossplots to
Quantify Fractures
Porosity – resistivity crossplot (Pickett plot) identifies fractures

While propagating along the borehole wall, the
Stoneley wave is able to exchange energy with
the formation fluid in a process called acoustic
flow. This communication between the borehole
and formation is proportional to the mobility of
the fluids, which in turn is proportional to
permeability and fluid viscosity. Increases in
communication decrease Stoneley amplitude,
because energy is used up when acoustic flow is
initiated. This is equivalent to increased Stoneley
attenuation, which therefore can be calibrated to
predict formation permeability.
Calculating Permeability From
Stoneley Attenuation

 There are two other ways the computer can help present a synthesis
of fracture indicating logs. One is to calculate formation strength and
elastic properties.
 The other is to reduce the indicators to a single curve representing
fractures intensity or fracture probability.
Calculating Formation Strength

Calculating Fracture Intensity
(Crain’s Method)
CFI = ((RESS<RESD) + (PHID>PHIN+0.05) + (DELT>200) + (GR>150) + (PE>5.5) + (CAL>250) + (DCOR>250) + DELTA_CAL>50)) / NTEST
WHERE:
CFI = calculated fracture index (fractional)
RESS = shallow resistivity
RESD = deep resistivity
PHID = density porosity
PHIN = neutron porosity
DELT= sonic travel time
GR = gamma ray
PE = photo electric effect
CAL = caliper
DCOR = density correction
DELTA_CAL = differential caliper
NTEST = number of thresholds tested

Calculating Fracture Intensity and
Initial Flow Rate (Schafer’s Method)
SFI = KF1 * (2.5 * (A + B) + C) / (70 * D)
Qi = KF2 * (SFI ^ 0.5) * Bo
Where:
A = total opposite pad fracture length on FIL in perforated intervals (ft or m)
B = total length of borehole width elongation greater than 25% of hole diameter (ft or m)
C = total single pad fracture length on FIL in perforated intervals (ft or m)
D = maximum borehole ellipticity (short / long diameters)
SFI = fracture intensity index (unitless)
Qi = initial flow rate (bbl or m3)
Bo = oil formation volume factor (vol per vol)
KF1 = 1.00 for English units
KF1 = 0.3048 for Metric units
KF2 = 1.00 for English units
KF2 = 0.159 for Metric units

Quantitative analysis of fracture
aperture is possible by further
processing of formation micro-
imager conductivity data. The
algorithm is based on the concept
that higher conductivity means a
larger open fracture. The fracture
aperture and fracture frequency
can be combined to obtain
fracture porosity and fracture
permeabil
Calculating Fracture Porosity and Fracture
Permeability From Fracture Aperture

Part 2 – Quantitative Models
Log Overlays and Crossplots to Quantify Fractures
Calculating Permeability From Stoneley Attenuation
Calculating Formation Strength
Calculating Fracture Intensity (Crain’s Method)
Calculating Fracture Intensity and Initial Flow Rate (Schafer’s Method)
Calculating Fracture Porosity and Fracture Permeability from Fracture Aperture
Part 3- Dual Porosity Model
Basic Resistivity Concepts in Fractured Reservoirs
The Double Porosity Model in Fractured Reservoirs
Water Saturation in the Double Porosity Model

 A fracture is a surface along which
a loss of cohesion in the rock
texture has taken place. A fracture
is sometimes called a joint and, at
the surface, are expressed as
cracks or fissures in the rocks.
 The orientation of the fracture can
be anywhere from horizontal to
vertical. The rough surface
separates the two faces, giving
rise to fracture porosity. The
surfaces touch at points called
asperities. Altered rock surrounds
each surface and infilling minerals
may cover part or all of each
surface. Minerals may fill the
entire fracture, converting an
open fracture to a healed or
sealed fracture.

Basic Resistivity Concepts in
Fractured Reservoirs
Effective porosity
PHIe = PHIm + PHIf
Total porosity
PHIt = PHIe + Vsh * BVWSH
WHERE:
PHIe = effective porosity of dual porosity system (fractional)
PHIm = effective matrix porosity in dual porosity system (fractional)
PHIf = effective fracture porosity of dual porosity system (fractional)
PHIt = total porosity of any rock (fractional)
Vsh = shale volume (fractional)
BVWSH = bound water in 100% shale (fractional)
Archie’s Laws
I = RESD / (F * RW@FT)
F = A / (PHIe ^ M)
Rearranged, these become the Pickett plot definition
RESD = F * RW@FT * I
RESD = (PHIe ^ (- M)) * (A * RW@FT) * I
log RESD = - M * log (PHIe) + log (A * RW@FT) + log (I)
A = tortuosity exponent (unitless)
F = formation factor (unitless)
I = resistivity index (unitless)
M = cementation exponent (unitless)
PHIe = effective porosity of dual porosity system (fractional)
RESD = true )deep) formation resistivity (ohm-m)
RW@FT = formation water resistivity (ohm-m)

Water Saturation in the Dual
Porosity Model
Partitioning water saturation
Swd = (Pwtr / Phyd) ^ (1/N)
Swf = (VISW * WOR) / (Bo * VISO + VISW * WOR)
Swe = (Swd - V * Swf) / (1 - V)
WHERE:
Bo = oil formation volume factor (vol/vol)
N = water saturation exponent (unitless)
Phyd = parameter P for each hydrocarbon zone (unitless)
Pwtr = mean value of P for water bearing intervals (unitless)
Swd = water saturation for the double porosity system (fractional)
Swe = water saturation for the matrix rock (fractional)
Swf = water saturation for the fracture (fractional)
VISW = water viscosity (cp)
VISO = oil viscosity (cp)
WOR = water/oil ratio, (vol/vol)

 Structural Analysis
 Part 1 - Conventional Dipmeter Methods
 Plate Tectonics - The Big Picture
 Diastrophism - The Regional Picture
 Subsidence and the Creation of Geosynclines
 Folds and Faults
 Petroleum Traps Formed By Structures
 Analysis of Dipmeter Data For Structural Features
 Choosing and Using Regional Dip
 Deciding What The Patterns Mean
 Classic Dipmeter Patterns On Arrow Plots
 Case Histories of Structural Analysis
 Part 2 - Unconventional Dipmeter Methods
 Statistical Curvature Analysis Techniques - SCAT Diagrams
 Analyzing Dipmeters with Tangent Diagrams
 Dipmeter Calculations With Stereonets
Structural & Stratigraphic Analysis

 Stratigraphic Analysis
 Part 1 - Depositional Environment
 Rock Facies - Origin and Depositional Environment
 Classification of Depositional Environments
 Sedimentary Structures
 Genetic Units
 Marine Transgressive Overlap - Fining Upward Sequence
 Marine Regressive Overlap - Coarsening Upward Sequence
 High Energy Marine Deposition - Cylindrical Sequence
 Curve Shape Patterns in Continental Sequences
 Stratigraphic Traps
 Grain Size and Depositional Environment
 Dip Spread and Depositional Environment
 Current Bedding and Depositional Environment
 Curve Shape Analysis and Depositional Environment

 Stratigraphic Analysis
 Part 2 - Dipmeter Patterns
 Dipmeter Patterns in Sedimentary Structures
 Analyzing Dipmeter Patterns
 Choosing Regional Dip
 Subtracting Regional Dip
 Sedimentary Models
 Glacial Deposits
 Alluvial Fan and Scree Slope Deposits
 Sand Dune Deposits
 Braided Stream Deposits
 Meandering Stream Point Bars
 Channel Cut and Fill
 Delta Distributary Channels
 Delta Front Distributary Mouth Bars
 Tidal Channel Deposits
 Beach and Shoestring Sands
 Basal Unconformity Sands
 Offshore Bars and Barrier Bars
 Marine Shelf Sands (Blanket Sands)
 Marine Shelf Carbonates
 Reefs and Carbonate Banks
 Turbidite Slumps
 Classic Dipmeter Patterns For
Stratigraphy

 Classic Dipmeter Patterns On Arrow Plots

Plate Tectonics - The Big Picture
Major continental plates, mid-oceanic ridges,
transform faults, and subduction zones
Subduction and buckling of plates

Diastrophism - The Regional
Picture
Diastrophism is "the process by which the earth's crust is reshaped". The word is seldom heard
today. More modern terms are "mountain building" and "tectonism". The word "orogeny" also
means the process of mountain building, but is often used to mean a mountain building period
of time in the earth's history.
The diastrophic processes of interest to petroleum geologists may be classified as follows:
1.subsidence - the relative depression of portions of the earth's surface with respect to
adjacent areas.
2.uplift - the elevation of portions of the earth's surface with respect to adjacent areas.
3.warping - tilting of the surface such that one side of a plate rises and the other subsides.
4.folding - the buckling of strata into corrugations by lateral compression.
5.faulting - the breaking and displacement of rock masses along fractures.

Subsidence and the Creation of
Geosynclines
A geosyncline is a long prism of rock laid down on a subsiding region of the earth's crust.
Geosynclines are fundamental geologic units. The geosyncline is formed of sedimentary rock
deposited under the sea parallel to the coastline, and continues to grow in thickness as long as
subsidence continues.
Geosynclinal prisms are deposited along the trailing edge of a plate. If the continental plate
changes its relative direction of motion, and the trailing edge becomes a leading edge, the
geosyncline is compressed and folded.

Petroleum Traps Formed By
Structures

Analysis of Dipmeter Data For
Structural Features

 Regional dip, often called structural dip, is chosen in zones where
dip angle and direction are consistent, with a minimum of scatter
 Due to the roughness of the borehole, and statistical variations in
the correlation measurements, even a zone with zero dip will show
some scatter. In particular, dip direction may appear to fluctuate
wildly when dip is near zero.
Regional dip may not be easy to find. In thick sandstones, there may
be too many stratigraphic features, and in thick carbonates there
may be no bedding or too many fractures. Therefore, shale sections
should be preferred for the selection of structural dip. If there is not
much shale, choose the minimum consistent dips in the sands.
Choosing and Using Regional Dip

 There are two basic ways to decide what red and blue
patterns mean from a structural point of view. The first is to
sketch a cross sectional view of the well bore with the
bedding planes positioned according to the dipmeter data.
These can be made by hand or with the stick diagram
 The second is to use a catalog of typical patterns to compare
your pattern with those already described. regional dip
removal can change a pattern, so the approach is not too
useful unless dip removal has been done. Also, the patterns
presume that dip directions shown on logs are always
parallel to your cross section direction. This is not always
true so it becomes necessary to rotate dips to get the "best"
patterns. Both transverse and longitudinal cross sections
should be visualized when analyzing dip patterns.
Deciding What The Patterns Mean
Stick diagram for a normal
fault with drag
Stick diagram for overthrust
fault

Deciding What The Patterns Mean
Normal faults growth faults

Classic Dipmeter Patterns On
Arrow Plots
Regional Dip and Symmetrical Anticline Asymmetrical Anticline and Recumbent Syncline

Arrow Plots - The Cook Book
Recumbent Anticline and Normal Fault -No Drag
Normal Fault with Drag

Arrow Plots - The Cook Book
Normal Fault With Rollover and Reverse Fault
With No Drag
Reverse Faults With Drag

Case Histories of Structural
Analysis
Unconformity Normal Fault with Rollover and Drag

Case Histories of Structural
Analysis
Normal Fault with Rollover and No Drag Normal Fault with No Rollover and No Drag

 Classic Dipmeter Patterns On Arrow Plots - The Cook Book

Statistical Curvature Analysis
Techniques - SCAT Diagrams
SCAT is based on four unfamiliar, but empirically well verified, geometric concepts:
1. structural curvature
2. transverse and longitudinal structural directions
3. special points on dip profiles
4. dip isogons or trend lines
The five plots used in SCAT are:
1. dip angle vs dip azimuth
2. dip azimuth vs depth
3. dip angle vs depth
4. transverse section dip angle vs depth
5. longitudinal section dip angle vs depth

Statistical Curvature Analysis
Techniques - SCAT Diagrams
SCAT plots for fault settingsSCAT plots for homocline and fold settings

Analyzing Dipmeters with
Tangent Diagrams

Dipmeter Calculations With
Stereonets

 A description of a rock by its detailed type, origin, and depositional environment is usually
called a facies description. It can be derived by observation of the rocks, or inferred from
analysis and interpretation of well log data. To determine facies from well logs requires
calibration to known rocks (cores, samples, or outcrops). Understanding the rock facies is
the only way to reconstruct the paleogeography of a rock sequence, which in turn provides
clues as to a potential reservoir's quality and lateral extent.
 Facies description based on well logs is often called electrofacies analysis, because electrical
logs are used
 The rock type can be derived from:
1. observation of samples
2. observation of cores
3. lithology analysis of an adequate log suite
 The origin of a rock can be inferred from its present depositional environment and a
reconstruction of paleogeography. Both of these can, at least sometimes, be inferred from
log data, especially from dipmeter data, which tells us about depositional energy and
direction of transport, in conjunction with other log curves, which suggest the grain size of
the rock. Log analysts usually concentrate on depositional environment and bedding
patterns, along with dip direction and angle
Rock Facies - Origin and
Depositional Environment

 The environmental classification is:
1. continental
2. coastal or transitional
3. marine
 Most detrital sediments are continental
or transitional, and most chemical
sediments are marine.
Classification of Depositional
Environments

Continental and transitional sediments:
1. glacial - formed by glacial action, eg. gravel bars, drumlins
2. eolian - formed by wind action, eg. sand dunes
3. alluvial - formed by flooding or when fast moving water dumps sediment into slow
moving water, eg. deltas, sand bars, beaches
4. fluvial - formed by a river, eg. point bars, channels
5. lacustrine - formed in a lake, eg. mudstones, marls, chert
6. paludal or carbonaceous - formed in a marsh or swamp, eg. peat, coal
The first four describe detrital sediments and the last two chemical sediments.
Marine sedimentary rocks:
1. shelf margin - formed at the edge of the continental shelf
2. inner shelf - formed near shore
3. outer shelf - formed farther from shore
4. atoll/pinnacle reefs - formed by biological skeletons in shallow water
5. lagoonal/back reef - formed in the quiet shallow water protected by a reef
6. basinal - formed in deep water
7. evaporitic - formed by evaporation of sea water
All but the last may be biological sediments and all can be chemical sediments. However, detrital
material can occur in nearly all of them, including evaporites.
Classification of Depositional
Environments

Sedimentary Structures
The term sedimentary structures refers to stratigraphic features in the subsurface, created by
erosion and deposition of sediments, as opposed to tectonic structures created by tension,
compression, uplift, and subsidence.
There are four basic kinds of stratigraphic traps: unconformities, porosity or permeability
pinchouts, reefs, and drape structures. River channels, beaches, bars, and deltas are
sedimentary structures, usually associated with porosity pinchout traps. Drape structures over
these may form additional traps.
Sedimentary structures can be subdivided into predepositional, syndepositional, and
postdepositional sedimentary features, which aid in describing the sequence of events which
created the structure.
Predepositional sedimentary structures are those observed on the underside of a bed. These
include erosional features, scour marks, flute marks, ripple marks, mud cracks, worm
burrowings, grooves, and channel cutting. Of these, only channel cutting may sometimes be
recognized on the dipmeter by the log analyst, although the smaller events may be seen on
Formation Microscanner images.
Syndepositional sedimentary structures are those occurring within the bed and take the form
of cross bedding or current bedding.
Postdepositional sedimentary structures are those observed on the top side of a bed. These
include load casts, quicksand structures, and movement by slump or creep.

Sequence Stratigraphy and
Genetic Units
Sequence stratigraphy is a phrase used to indicate
a method for describing the depositional
environment of a sequence of rocks.

Petrophysic cont

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (7)

Similar to Petrophysic cont

Similar to Petrophysic cont (20)

More from Andi Anriansyah

More from Andi Anriansyah (20)

Recently uploaded

Recently uploaded (20)

Petrophysic cont