Petrophysic cont

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

Transcript of Petrophysic cont

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Petrophysic Cont’

Petrophysicist (Geologist)

For Practical Use and Refferences

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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

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Petrophysics Continue

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

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Energy Sources for Acoustic Logs1. Monopole sources2. Dipole sources3. Quadrupole sources

Dispersion Acoustic Transmission Modes from a Monopole Sources

1. Fast compressional waves2. Slow compressional waves3. Surface compressional waves4. Shear body waves5. Shear surface waves

Sonic and Density Logging Tools

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6. Stoneley waves7. Tube waves8. Fluid compressional wave or mud wave9. Direct tool arriva

Attenuation of Sound WavesTypes of Sonic Logging Tools Recording Conventional Sonic LogsRecording Full Wave Sonic LogsRecording Dipole Shear Sonic Logs

Sonic and Density Logging Tools

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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.

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Energy Sources for Acoustic Logs

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).

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Energy Sources for Acoustic Logs

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.

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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)

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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.

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Acoustic Transmission Modes from a Monopole Sources

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.

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Acoustic Transmission Modes from a Monopole Sources

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

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Acoustic Transmission Modes from a Monopole Sources

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.

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Attenuation of sound wavesAll 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.

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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.

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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

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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.

Recording Conventional Sonic Logs

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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

Recording Conventional Sonic Logs

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Identifying and picking shear travel time on full wave sonic

Recording Full Wave Sonic Logs

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Array sonic tool and waveforms

Recording Full Wave Sonic Logs

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

Recording Full Wave Sonic Logs

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Array processor coherence maps to find compressional, shear,Stoneley travel time and spotty shear log

Recording Full Wave Sonic Logs

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.

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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

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Waveform presentation

Recording the Dipole Shear Sonic Log

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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.

Recording the Dipole Shear Sonic Log

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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

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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 PROPERTIES OF ROCKS

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ELASTIC PROPERTIES OF ROCKS

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.

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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 * NVp = KS4 * (Kc / DENS) ^ 0.5Vs = KS4 * (N / DENS) ^ 0.5Vst = KS4 * (DENSW * (1/N + 1/Kf)) ^ 0.5

ALPHA = 1 - Kb / KmKp = ALPHA^2 / ((ALPHA - PHIt) / PHIt / Kf )

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Calculating Mechanical Properties Of Rocks

Correcting High Frequency Sonic (Lab) Data to Low Frequency Equivalent (Logging Tool Frequency)

DTScor = (DTShi - KS1) *1.25 +KS1DTCcor = (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)

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Calculating Mechanical Properties Of Rocks

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

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Calculating Mechanical 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

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Calculating Mechanical 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)

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Chart to calculate N from DENS and DTS

Calculating Mechanical Properties Of Rocks

Shear Modulus N, also abbreviated G or S or u (mu)

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Calculating Mechanical 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

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Calculating Mechanical Properties Of RocksBulk modulus Kb (also abbreviated B or L)

Chart for calculating Kb from P and N

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Calculating Mechanical 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

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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

Calculating Mechanical Properties Of Rocks

Biot’s Constant

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Chart to calculate Y from P and N

Calculating Mechanical Properties Of Rocks

Young's modulus Y (also abbreviated E)

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Calculating Mechanical 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 * NThe 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 bearingIF 1.5 < Kp < 3.5 THEN Zone is oil bearingIF Kp >= 3.5 THEN Zone is water bearingKp 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.

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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.

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Static to dynamic transforms for Young's Modulus

Calibrating Dynamic to Static Constants

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Mechanical properties log

Examples of Mechanical Properties Logs

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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 unitsKS9 = 0.0605 for English units

Overburden pressure gradient is:

Po = KS9 * SUM (DENSi * INCR)

(Po/D) = Po / DEPTH

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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 * DEPTHPs = KP2

(Pp/D) = Pp / DEPTH

Pore pressure plot versus depth

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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))^3Pp = (Pp/D) * DEPTH

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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.

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Calculating Fracture Pressure Gradient

Stress regime – no tectonic stress tectonic stress

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Calculating Fracture Pressure Gradient

Fracture pressure gradient log

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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

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Calculating Fracture Extent

FracHite log Fracture optimization model

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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

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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

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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

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Part 1 - Editing and Modeling LogsPart 2 - Editing/Modeling Logs Case HistoriesPart 3 - Synthetic SeismogramsPart 4 - Seismic Inversion / Synthetic SonicsPart 5 - VSP, AVO, and Porosity/Lithology

SEISMIC PETROPHYSICS

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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

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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.

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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.

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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

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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

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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

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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

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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

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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

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Editing the Sonic and Density Logs With Trend Data

Editing sonic with trend analysis

Editing density with trend analysis

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Modeling the Sonic and Density Logs From Resistivity

1. Faust MethodThis 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)

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Modeling the Sonic and Density Logs From Resistivity

2. Smith MethodThis 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 MethodThis 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.

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Modeling the Sonic and Density 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

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Modeling the Sonic and Density 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 logThese 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 * PHIrsDENSmod = KZ0 + KZ1 * GR + KZ2 * DEPTH + KZ3 * PHIrs

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Modeling Sonic and Density From Log Response Equation

1. Density Log ResponseThe response of a density log can be described rigorously by a volume weighted summation of the densities of the individual components in the rock.

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Modeling Sonic and Density From Log Response Equation

2. Sonic Log ResponseAn 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

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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

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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) / CoilKf = Sw / Cwtr + (1 - Sw) / CgasKc = Km + ((1 - B1 / N) ^ 2) / (PHIe / Kf + (1 - PHIe) / Km - Kc / (N^2))Vp = (Kc / DENS) ^ 0.5

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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)

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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

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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, oilOther 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.

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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

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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

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Synthetic Seismograms

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Time to Depth Conversions

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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)

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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.

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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

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Synthetic seismograms with multiple reflections

Step By Step Procedure for

Seismic Modeling

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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

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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

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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

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Low frequency component of sonic log Comparison of filtered sonic log and seismic

inversion trace

Capturing Low Frequency Components

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Inverted seismic section Seismic inversion section with interpreted

lithology based on velocity contours

Displaying Seismic Inversion Traces

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Case Histories: Seismic Inversion

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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

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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

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Vertical Seismic Profiles On 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

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Open and cased hole VSP comparison

Vertical Seismic Profiles On Wireline

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Vertical Seismic Profiles While Drilling

VSP while drilling

VSP while drilling - geometry and recorded traces after deconvolution

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Case Histories: Vertical Seismic Profiles

Dipmeter with fault

VSP, sonic, and inversion with fault

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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

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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 / V2Drat = DENS1 / DENS2C = (Vrat^2 + (1 - Vrat^2) / (Cos (ANGLE))^2) ^ 0.5 Refl = (1 - Vrat * Drat * C) / (1 + Vrat * Drat * C)

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AVO models (oil, gas, shale) and real data

a Cretaceous Glauconitic channel sand.

Amplitude Versus Offset Case History

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Porosity/Lithology From Shear Seismic

Shear amplitude and velocity

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Porosity/Lithology Case History

Compressional wave inverted velocity section Shear wave inverted velocity section

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Porosity/Lithology Case History

Poisson's ratio seismic section

Lithology from shear and compressional velocity

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Petrophysics Seismic PetrophysicsSonic and Density Logging ToolsElastic Properties of RocksSeismic Petrophysics

Petrophysics Fractured ReservoirDipmeter LogsDipmeter and Image Log CalculationsFractured Reservoir

Structural & Stratigraphic AnalysisStructural AnalysisStratigraphic Analysis

Petrophysics Continue

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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

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∗ Photoclinometer for recording dipmeter data

Evolution of the Dipmeter Concept

Computed microlog dipmeter results circa mid-1950'sPhotoclinometer for recording dipmeter data

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Modern Dipmeters

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

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Basic Continuous Dipmeter Calculations

Dipmeter computation definitions Regional and stratigraphic dipmeter computation using different correlation interval

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Coding non-planar dips helps interpret sedimentary bedding

Handling Correlation Planarity Error

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

Determining Dip By Clustering and Pooling

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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.

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Core comparison to pattern recognition dip program GEODIP

Pattern Recognition For Dip Calculations

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1. MSD Dips (Mean Squares)2. CSB Dips (Continous Side-by-Side)3. LOC Dips (Local Derivative)

Stratigraphic High Resolution Dip Calculations

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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

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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

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Resistivity Microscanner Image Logs

Formation microscanner images in various environments

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Dipmeter Advisor - An Expert System

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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

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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

Auxiliary Dipmeter Presentations

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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

Auxiliary Dipmeter Presentations

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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.

Auxiliary Dipmeter Presentations

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

Auxiliary Dipmeter Presentations

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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

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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

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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) >= 0THEN NEWAZM = SDAZ + 180 - ANGLSOtherwise NEWAZM = SDAZ - 180 + ANGLSNEWAZM = 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

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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

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True Vertical Depth

1. Tangential MethodThe 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 MethodThe 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 MethodThe 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)

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True Vertical Depth4. Mercury MethodThe 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 tool5. Radius of Curvature MethodThe 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 MethodThe 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

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FRACTURED RESERVOIRS

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

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FRACTURED RESERVOIRS

Part 2 – Quantitative ModelsLog Overlays and Crossplots to Quantify Fractures Calculating Permeability From Stoneley AttenuationCalculating Formation StrengthCalculating 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 ModelDefinition of FracturesBasic Resistivity Concepts in Fractured ReservoirsThe Double Porosity Model in Fractured ReservoirsWater Saturation in the Double Porosity ModelCase Histories: Fracture Analysis

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FRACTURED RESERVOIRS

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

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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

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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.

Definition of Fractures

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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

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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

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Fracture Identification From Core Analysis

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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

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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.

Fracture Identification From 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.

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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.

Fracture Identification From Micro Resistivity Logs

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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

Fracture Identification From Dipmeter Logs

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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

Fracture Identification From Density, Neutron, and PE Logs

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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.

Fracture Identification From Gamma Ray Logs

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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.

Fracture Identification From Resistivity Logs

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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.

Fracture Identification From Temperature Logs

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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.

Fracture Identification From Sonic Logs

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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.

Fracture Identification From Sonic Waveform Logs

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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

Fracture Identification From Formation Micro-scanner Logs

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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.

Fracture Identification From Borehole Televiewer Logs

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FRACTURED RESERVOIRS

Part 2 – Quantitative ModelsLog Overlays and Crossplots to Quantify Fractures Calculating Permeability From Stoneley AttenuationCalculating Formation StrengthCalculating 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 ModelDefinition of FracturesBasic Resistivity Concepts in Fractured ReservoirsThe Double Porosity Model in Fractured ReservoirsWater Saturation in the Double Porosity ModelCase Histories: Fracture Analysis

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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.

FRACTURED RESERVOIRS Quantitative Models

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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

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Log Overlays and Crossplots to Quantify Fractures

Porosity – resistivity crossplot (Pickett plot) identifies fractures

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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

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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

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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

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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

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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

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FRACTURED RESERVOIRS

Part 2 – Quantitative ModelsLog Overlays and Crossplots to Quantify Fractures Calculating Permeability From Stoneley AttenuationCalculating Formation StrengthCalculating 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 ModelDefinition of FracturesBasic Resistivity Concepts in Fractured ReservoirsThe Double Porosity Model in Fractured ReservoirsWater Saturation in the Double Porosity Model

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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

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Basic Resistivity Concepts in Fractured Reservoirs

Effective porosity PHIe = PHIm + PHIfTotal 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 LawsI = RESD / (F * RW@FT)F = A / (PHIe ^ M) Rearranged, these become the Pickett plot definitionRESD = F * RW@FT * IRESD = (PHIe ^ (- M)) * (A * RW@FT) * Ilog 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)

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Water Saturation in the Dual Porosity Model

Partitioning water saturationSwd = (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)

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Petrophysics Seismic PetrophysicsSonic and Density Logging ToolsElastic Properties of RocksSeismic Petrophysics

Petrophysics Fractured ReservoirDipmeter LogsDipmeter and Image Log CalculationsFractured Reservoir

Structural & Stratigraphic AnalysisStructural AnalysisStratigraphic Analysis

Petrophysics Continue

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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

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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

Structural & Stratigraphic Analysis

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Structural & Stratigraphic Analysis Stratigraphic Analysis Part 2 - Dipmeter Patterns

Dipmeter Patterns in Sedimentary Structures Analyzing Dipmeter Patterns Choosing Regional Dip Subtracting Regional Dip Deciding What The Patterns Mean 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

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Structural & Stratigraphic Analysis 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

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Plate Tectonics - The Big Picture

Major continental plates, mid-oceanic ridges, transform faults, and subduction zones

Subduction and buckling of plates

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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.

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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.

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Folds and Faults

Folds Faults

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Petroleum Traps Formed By Structures

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Analysis of Dipmeter Data For Structural Features

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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

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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

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Deciding What The Patterns Mean

Normal faults growth faults

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Classic Dipmeter Patterns On Arrow Plots

Regional Dip and Symmetrical Anticline Asymmetrical Anticline and Recumbent Syncline

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Classic Dipmeter Patterns On Arrow Plots - The Cook Book

Recumbent Anticline and Normal Fault -No Drag Normal Fault with Drag

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Classic Dipmeter Patterns On Arrow Plots - The Cook Book

Normal Fault With Rollover and Reverse Fault With No Drag

Reverse Faults With Drag

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Case Histories of Structural Analysis

Unconformity Normal Fault with Rollover and Drag

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Case Histories of Structural Analysis

Normal Fault with Rollover and No Drag Normal Fault with No Rollover and No Drag

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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 - The Cook Book 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

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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

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Statistical Curvature Analysis Techniques - SCAT Diagrams

SCAT plots for fault settingsSCAT plots for homocline and fold settings

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Analyzing Dipmeters with Tangent Diagrams

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Dipmeter Calculations With Stereonets

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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

Structural & Stratigraphic Analysis

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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

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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

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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, coalThe 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 waterAll 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

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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.

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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.

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Marine Transgressive Overlap - Fining Upward Sequence

A sedimentary structure is generally initiated by the accumulation of sediment on an old erosion surface. Deposition does not occur everywhere at once. Sediment will be deposited gradually at a location close to the source of sediments and will be spread outward from the source. This process is called overlap since the new sediments gradually overlap onto the older sediments.

Two kinds of overlap are recognized. Transgressive overlap occurs when the sea is advancing, or transgressing, upon a low, relatively flat land mass. In this case the land mass is subsiding relative to sea level. At the shore line, sand and gravel accumulate. Away from the land, beyond the beach sands, mud is laid down, and beyond that there may be organic oozes deposited on the sea floor.

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Marine Transgressive Overlap - Fining Upward Sequence

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Regressive overlap is produced when the sea recedes from the land, as when the land mass is uplifted or the sea bed subsides. By this process, the beach zone migrates out over earlier offshore muds

At the seaward end, mud beds overlap the older ooze. A vertical section shows coarser material overlying finer material, or shallow water sediments overlying deep water sediments. These sands are described as "coarsening upward" and have a gamma ray or SP curve shape

These are called funnel shaped curves and would be indicative of barrier bars, or the edge of delta fronts. These curve shapes may also be serrated or saw tooth shaped.

Sea level dropping relative to the land is not necessary for marine regressive overlap. The same regressive sequence is produced if the sea level is stationary and there is sufficient supply of sediments, or even if the sea level is rising, provided the rate of supply exceeds the rate of rise of the ocean.Different types of overlap often combine in the same stratigraphic section. Thus the sea may advance on the land and then recede, so that regressive overlap is found above transgression. This alternation may be repeated many times.

Marine Regressive Overlap - Coarsening Upward Sequence

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Distributary channels in delta sequences represent high energy deposition. At flood stage, these deposits will fill old channels while new ones are formed. The sand bodies will be quite uniform, with large grain size and little visible bedding. If flooding is erratic, the curve shape may be serrated.

Similar curve shapes can be formed in deeper water as sand slides, or fans, formed at the end of submerged canyons. Turbidite deposits, formed in deep water by slumping of unconsolidated slopes or by rapid movement of heavy, silt laden water, form serrated cylindrical curve shapes, often covering hundreds or thousands of feet of vertical section.

High Energy Marine Deposition - Cylindrical Sequence

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Bell shaped curves are found in alluvial point bar sands, in meandering streams, and in drape inside a channel fill. Funnel shaped curves occur in foreset and crossbeds in channels. Cylindrical patterns are restricted to sand dunes and scree slopes, the latter being often serrated.

There are obvious ambiguities between marine and continental curve shapes, so curve shape alone will not suffice to uniquely determine environment. With all four sources of environmental data, namely curve shape, dip angle and spread, bedding type, and shale volume, it is usually possible to assess the environment and hence the sedimentary structure quite precisely. If one source is missing, especially the dip data, life becomes more difficult, but regional knowledge will usually fill in the gaps.

Curve Shape Patterns in Continental Sequences

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Petroleum Traps Formed By Stratigraphy

1. UnconformitiesAn unconformity is a hiatus in the normal geological sequence caused by a break in the process of deposition, by erosion, or by structural deformation. It results in a missing amount of sediments corresponding to a missing geological time as compared to the normal sequence.there are four main types of unconformities: nonconformity, paraunconformity, disconformity, angular unconformity.

Typical unconformity trap

Unconformities and disconformity

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Petroleum Traps Formed By Stratigraphy

2. Porosity Permeability Pinchouts

Sand pinchout (top) and Sand channel (bottom)

Permeability pinchout trap (shaly sand shown, similar traps are also formed in carbonates)

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Petroleum Traps Formed By Stratigraphy

3. Reef Traps

Reefs are productive in many parts of the world. Many types exist, such as atolls, table reefs, pinnacle reefs, barrier reefs, fringing reefs, biostromes, and bioherms. They occur as small dome like features that may be reflected in the overlying sediments by drape. Drape is described in the next section of this Chapter. Some reef trends extend for hundreds of miles, such as the Leduc reef trend in Alberta. The size of a reef ranges from a few acres to several square miles. Seismic exploration is the best way to find reefs.

The reef core grows upward and usually outward as the sea level rises. Detrital reef material falls on the ocean side, forming the fore reef.

If sea level rises too fast, the reef may drown and die. If water level drops it may begin to grow again, forming very complex structures.

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Petroleum Traps Formed By Stratigraphy

4. Drape TrapsDifferential compaction causes drape over reefs and sand bodies and this can form traps. A sandstone or carbonate layer above the bar or reef can be bent in such a way as to have closure, that is, the ability to contain and trap hydrocarbons. The bending is caused by the fact that the reef or sand body does not compress to the same degree as the shales to either side of it. Therefore a topographic high can be propagated upward through the section for quite some distance.They were not formed by tectonic activity, but rather by the sedimentary process itself. Dips underneath the reef or bar will be regional, in contrast to the anticline.

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There are four primary ways to estimate depositional environment from well logs: 1. shale volume/grain size analysis 2. dip spread/water depth analysis 3. bedding angle/bedding type analysis 4. curve shape/depositional sequence analysisDepositional energy level correlates well to grain size, which in turn is usually proportional to shale volume. Thus the gamma ray or SP curve can augment environment estimates from dipmeter analysis. Low values of gamma ray (or high SP) indicate high energy, low shale content zones. These are inner shelf or upper continental slope in a marine environment, or alluvial or fluvial regimes on the continent.Higher shale volume indicates lower energy deposition; that is, deeper water outer shelf, lower continental slope, continental lacrustine, or paludal environments.

Grain Size and Depositional Environment

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Dip Spread and Depositional Environment

Depositional environment, water depth, and dip scatter

Dip scatter and water depth

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The geometry of a sandstone unit is related to its internal structures, which are functions of its depositional environment. The internal structure is influenced mostly by current bedding. The direction of paleocurrents is indicated by the orientation of the current bedding, which can be measured by using dipmeter data after removal of structural dip.

Crossbedding, although the term suggests otherwise, is also parallel to the direction of current flow. However, crossbeds do not often occur in river channels but usually on the front of deltas or shallow marine sand bars. Crossbeds dip considerably more steeply, but in the same direction, as the dips of the delta or sand bar surface.Planar or tabular bedding, as the words suggest, involve flat layers of rock (maybe lying at an angle) laid down in streams, lakes, or in deltas. Festoon bedding creates layers which are convex top and bottom, and are usually laid down in braided streams. Wedge shaped or nonparallel bedding is planar bedding with concurrent erosion which has removed a portion of the bed, such as on the curve of a meandering river.

Current Bedding and Depositional Environment

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Curve Shape Analysis and Depositional Environment

Grain size and bedding both influence the overall curve shape of a log versus depth. There are four basic curve shapes:

1. straight line, indicating constant shale, evaporite, clean sand, or carbonate, caused by continuous deep water deposition

2. bell shaped, indicating a fining upward sequence, ie., lower energy at the end of a cycle

3. funnel shaped, indicating a coarsening upward sequence, ie higher energy at the end of a cycle

4. cylindrical shaped, indicating constant energy throughout the cycle

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Structural & Stratigraphic Analysis Stratigraphic Analysis Part 2 - Dipmeter Patterns

Dipmeter Patterns in Sedimentary Structures Analyzing Dipmeter Patterns Choosing Regional Dip Subtracting Regional Dip Deciding What The Patterns Mean 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

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Small scale stratigraphic dips from SHDT DUALDIP program

Dipmeter Patterns in Sedimentary Structures

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Analyzing Dipmeter Patterns

Stratigraphic analysis begins with a review of the well history, sample descriptions, log curve shapes, open hole logs (shale volume and lithology), and the dipmeter arrow plot.Dip patterns fit one of five general classifications:GREEN Patterns: nearly constant dip and direction, representing regional dip, sometimes called structural dip.RED Patterns: increasing dip with depth, representing drape, down dip thickening, or differential compaction.BLUE Patterns: decreasing dip with depth, representing current bedding.BLACK Patterns: abrupt changes or breaks in dip and/or direction, representing unconformities, or erosional boundaries between stratigraphic units.YELLOW (RANDOM) Patterns: caused by poor hole condition or random stratigraphic events, such as pre-depositional burrows and cracks.

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Choosing Regional DipRegional dip is chosen in zones where dip angle and direction are consistent, with a minimum of scatter, as in the example in Figure 34.04. This usually occurs in shale zones.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. However, shale sections do not always exhibit a regular dip. The mode of deposition as well as post-depositional slumping or fracturing may induce erratic dips. A statistical approach may then be needed to determine structural dip, and local experience is the best guide. Here is a case for using the modified Schmidt plot or the frequency azimuth plot.

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Subtracting Regional Dip

It is essential to subtract the structural dip (by means of dip vector rotation), preferably by having a regional dip removed arrow plot created in the computer. Indeed, a blue pattern may become a red one and vice versa after subtraction of the general trend, or patterns may not be visible at all, especially stratigraphic patterns.

A dipmeter log should always be correlated with the rest of the open hole logs when the patterns are being drawn.

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Deciding What The Patterns Mean

There are two basic ways to decide what red and blue patterns mean from a stratigraphic point of view. The first is to sketch a cross sectional view of the wellbore with the bedding planes positioned according to the dipmeter data. Details of the sketch are then compared to the sedimentary models, and the best choice picked from the set of possible solutions.

The second is to use a catalog of typical patterns to compare your pattern with those already described. As mentioned earlier, regional dip removal can change a pattern, so the approach is not too useful unless dip removal has been done. Both methods require the use of gamma ray or SP curve shapes and energy level estimates, to distinguish between various models which may have similar patterns.

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Sedimentary Models

Sedimentary Structure Analysis - Step-By Step Approach1. lithology (shale, shaly sand, clean sand, carbonate, evaporite)2. shale content (laminated, dispersed, amount, distribution)3. dip spread (energy level, water depth inferences)4. bedding angle (steep, shallow, energy level inferences)5. bedding type (planar, festoon, nonparallel, environmental inferences)6. bedding frequency (thin, thick, massive, cyclic, seasonal)7. overall curve shape (fining, coarsening, cylindrical, smooth, serrated,

combinations)8. internal structure (minor curve shapes within larger ones)9. dip patterns (regional dip removal, absolute red and blue patterns, internal

dip patterns or cycles)10. deductive interpretation (what do the environment and dip patterns mean)

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Glacial Deposits

Stratigraphic model and dipmeter in glacial environment

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Alluvial fans are composed of rock fragments, gravel, sand, and mud washed down from a steep slope onto a flatter surface. Boulders and coarse materials settle to the top to form a generally coarsening upward sequence. Transportation is by both water and gravity. Debris falls dominate on steep slopes. Water channels alternately erode and deposit downstream, making a very erratic depositional sequence over short intervals.

Alluvial fans are long in the down slope direction and very narrow. Thickness varies from a few hundred to several thousand meters. Dip angle is high and scattered. Dip direction is not a good indicator of body geometry. The lower reaches of the fan may grade into a braided stream environment.

Alluvial Fan and Scree Slope Deposits

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There are three major types of dunes: transverse, barchan, and seif dunes. Each has a distinctive cross section or cross-bedding pattern. Parabolic dunes are similar to a single lobe of a barchan dune.

Wind blown dune deposits are often difficult to distinguish from those laid down by water. The mechanics of both processes are quite similar. Although we normally think of dunes as occurring in a desert environment, they often form on beaches and barrier bars, as well as on continental deposits exposed to the air

Sand Dunes

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Braided stream deposits are the result of an interlaced network of sinuous channels exhibiting flood stage scouring and subsequent channel filling. A channel is no sooner cut than it chokes on its own detritus. This is dumped in the form of bars in the center of the channel around which two new channels are diverted.

Braided Stream Channels

Dipmeter in braided stream environment

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Point bars are formed in the inside of bends in rivers and streams, where the current slows down and drops out some of its sediment load

These bars are small, and difficult to find due to the meandering nature of the original river. They are attractive exploration targets because their reservoir characteristics are usually good.

Meandering Stream Point Bars

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Channel Cut and Fill

Meandering streams or delta distributary channels fill with a sequence of cross-bedded sands, with the thickest cross-beds, and the steepest dip angles, near the basal scour surface. There is an upward decrease in the thickness and angle of cross-bedding. Channel fill is also called vertical accretion.

Drape over the top of these sand bodies is not usually present. The channel fill itself, however, may drape or sag towards the axis of the valley.

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The meandering streams of the plains areas grade into delta distributary channels in the exposed delta areas. These channels are relatively straight and are cut into young, soft sediments. Natural levees formed of clays and silts contain the channel in a fixed position.

The infilling of a distributary channel is a rapid process and there is no further reworking of the infilling sediments. Current bedding therefore reflects stream energy and direction at the time of deposition. Current bedding near the base is usually of the festoon type. Measured dips are erratic near the base, sometimes grading upward into more consistent dips near the top. The direction of the channel and thus the direction of sand elongation, is given by the average of the current bedding directions.

Delta Distributary Channels

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There are three main types of deltas: 1. bird's foot or elongate, laid down with little reworking of sands by ocean current. These are termed constructional deltas. 2. estuarine or lobate, laid down with some reworking by ocean currents and wave action. 3. arcuate or cuspate, laid down with considerable reworking by ocean currents and wave action. These are termed destructional deltas.

Distributary mouth bar sands are relatively fine grained and moderately sorted. However, curve shapes reflect a general coarsening upward in a highly serrated funnel type configuration. The serrations arise from thin shale layers laid down in times of low water flow.

Delta Front Distributary Mouth Bars

Dipmeter in distributary mouth bar environment

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Certain delta areas are strongly dominated by tidal forces. In this case, rather than the distributaries building outward, the effect of tidal currents is to form indentations at the location of each distributary mouth. The modern Mahakam delta is an example. The outer reaches of the distributary channels are subject to tides and there is significant mixing of river and sea water.

Narrow estuaries develop elongate sand bodies with characteristics similar to those of distributary channel fills except that cross-bedding may be bimodal, that is, cross-beds dip both toward and away from the sea in alternating layers.On the other hand, very wide estuaries create tidal flats which contain some sand, but are often predominately mud. Deposits formed in wide tidal estuaries tend to be a grouping of roughly parallel elongate sand bars amid silts and muds

Tidal Channel Deposits

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When a sea invades an area, several beach sands may be laid down. In the subsurface, these become preserved as long narrow sand bodies, sometimes called shoestring sands, although this term may also be used to describe channel fill sands. Typically, beach sands are upward coarsening, regressive type sequences. These give rise to smooth funnel shaped curves on logs. Beach sands, in their upper sections are normally very well sorted and may form cylindrical curve shapes over a fairly thick section.

Current bedding reflects the wave action showing gentle, tabular, unimodal cross-bedding, with lower angle dips at the base and steeper at the top of the sand. The direction of cross-bedding is seaward, normal to the direction of elongation of the sand body. Beaches cannot be distinguished easily from distributary mouth bars by dipmeter data. Stacking of several beaches is common and both regressive (funnel shaped), transgressive (bell shaped), and cylindrical curve shapes are possible.

Beaches and Shoestring Sands

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This type of deposition originates on erosional surfaces which are fairly rugged in profile and have undergone a rapid transgression. Low lying areas will tend to collect unsorted detrital material. Sands develop on the flanks of the erosional highs where wave energy has been sufficient to clean up the sediments. Thus sands tend to follow the outlines of the erosional surface, often developing on both sides of old erosional channels.

Basal unconformity sands have stronger cross-bedding angles, proportional to the topographic relief. In addition, there is usually draping dip due to differential compaction in the overlying beds. Draping dips point away from the local high on the erosional surface. Granite wash sands typically exhibit this behavior. These sands are composed of granite fragments, feldspar, quartz, and silt.

Basal Unconformity Sands

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Offshore bars develop in the area where waves break near the shore. The incoming water rapidly loses energy thus dropping its sediment load. Bars grow parallel to the shoreline. On the seaward slope, bars very closely resemble a beach deposit in that they are upward coarsening and cross-bedding is gentle and tabular. The direction of cross-bedding is normal to sand body elongation.

The barrier bar is formed by regression of the shoreline, and contains three fundamental units:- upper cross-bedded sandstone unit- intermediate shale, silt and fine sandstone unit- a basal shale and silty shale unit

Offshore Bars and Barrier Bars

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Blanket sands originate on large, shallow shelf areas, such as the present Bering Sea. A plentiful supply of sediments and a persistent energy condition, such as a slow steady current, is required. In addition, most of these sands are the result of repetitive regressive-transgressive sequences. In many cases, shelf blanket sands end up with a regressive sequence and develop bar deposits at the top.

Marine Shelf Sands (Blanket Sands)

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The character of log curve and dip plots on shelf carbonates is very dependent upon the degree of shaliness. Massive limestones give rise to cylindrical or straight line gamma ray curves; interbedded shale creates a serrated effect. Dips measured in massive limestones are likely to present an incoherent pattern, being mainly the result of vugs and fractures. To be able to measure meaningful dips, it is necessary to have recognizable bedding planes which are mainly due to variations in shaliness.

Bell and cylindrical curve shapes usually correlate to red patterns, and bell shaped to blue patterns. However the shapes are not taken from the usual gamma ray and SP logs.

Marine Shelf Carbonates

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Reefs are carbonate buildups of skeletal organisms which had a rigid framework forming a topographic high on the sea floor. Banks are carbonate buildups such as oolite shoals, coquina beds, or crinoid debris, also forming topographic highs.

Reefs and Carbonate Banks

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Turbidite Slumps

Sedimentary model in deep water turbidite sand environment

Sedimentary model in deep water turbidite sand environment

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Classic Dipmeter Patterns For Stratigraphy

Arrow Plot - Angular Unconformity and Drape Over Salt Dome

Arrow Plot - Disconformity and Angular Unconformity

Arrow Plot - Festoon or Lenticular Cross-bedding and Tabular or Planar Cross-bedding

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Classic Dipmeter Patterns For Stratigraphy

Arrow Plot - Drape Over Reef and Deep Water Turbidite

Arrow Plot - Sand Bar and Drape Inside Channel Sand

Arrow Plot - Nonparallel Cross-bedding and Foreset Cross-bedding

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Classic Dipmeter Patterns For Stratigraphy

Pattern Azimuth Frequency Plot - Barrier Bar or Delta Front and Barrier Bar or Tidal Channel

Pattern Azimuth Frequency Plot - Stream Channel Off Center and Centered

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From many Sources

Reference