Guide2PphInterp.2004

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Guide toPetrophysical Interpretation Daniel A. Krygowski

Austin Texas USA

This Guide contains references to, and specifically lists, trademarks and service marksof the following companies, their subsidiaries, and/or their parent companies: BakerHughes, Baker Atlas, Baker Hughes INTEQ, Gearhart, Halliburton, PathFinder,Precision Drilling, Precision Wireline Services (formerly Computalog), Reeves Wireline(formerly BPB Wireline), Schlumberger Limited, Sperry-Sun Drilling Services, Welex.


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1995, 2000, 2003 Daniel A. Krygowski All rights reserved. No part of this Guide shall be reproduced or transmitted in any formor by any means, electronic or mechanical, including photocopying, recording, or by anyinformation or retrieval system (except for the conditions stated in the paragraph below)without written permission from the Author.

The file which contains this document is protected from printing but is not protected fromcopying. Users may copy this file from the original compact disk to the hard drive of thecomputers on which they are the primary users. Making copies for purposes beyondthose of personal reference is not permitted.

Guide to Petrophysical Interpretation 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA


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About This Document

This document was developed, updated, and refined over about two decades in

response to the feedback of participants in a number of different petrophysical shortcourses, especially the basic well logging course taught by Dr. George Asquith andmyself under the sponsorship of the AAPG. It is meant to be a quick guide or a memoryaid to those needing to interpret well log data (wireline or MWD), and a starting point formore detailed study when needed.

The document is a summary of each common openhole petrophysical measurement; theinterpretation goals and details, a brief explanation of the physics and operatingconstraints, and some of the nomenclature related to each measurement. Themeasurements are listed below, and are those that have been traditionally used todetermine formation lithology, porosity, and fluid saturation.

The measurements are arranged by interpretation goal, rather than by tool physics, sothat the user can more readily compare the interpretation methodologies ofmeasurements that are focused on a common goal, such as the determination ofporosity. In addition, there is a section on openhole log interpretation that is again meantas a general guide, not as an exhaustive study of all interpretation techniques.

The measurements/topics covered here are:Correlation/Lithology

Spontaneous Potential (SP)Gamma RayCaliper

Porosity

Sonic/AcousticDensityNeutronPorosity Measurement Combinations

ResistivityInduction LogsLaterologsMicroresistivity (Rxo) Logs

Openhole Log Interpretation

An Annotated Bibliography is included to guide the user to more complete referencematerial.



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Correlation/Lithology

Correlation/Lithology

This section contains information about three measurements: Spontaneous Potential(SP) , Gamma Ray , and Caliper .

The measurements are those which are usually displayed to the left of the depth track inan API standard (three data tracks) display. While the Gamma Ray and SpontaneousPotential (SP) are often used for correlation, they are also useful for the determinationof gross formation lithology (reservoir vs. non-reservoir). In addition, both can be used todetermine the shaly sand calculation parameter Shale Volume (V shale ), and the SP canbe used to determine formation water resistivity, R w. The Caliper measurementdetermines hole size, which can be an indicator of the quality of other loggingmeasurements, and which is used in some of the corrections made to thosemeasurements to account for changes in the borehole environment.



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SP 1Correlation/Lithology

Spontaneous Potential

Interpretation GoalsCorrelation of formations from well to well.Gross lithology (reservoir vs. non-reservoir).

Estimate of formation water resistivity, R w.Estimate of shale (clay) content.Qualitative indication of permeability.Identification of depositional environments.



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Tool Diagram

Halliburton array induction (HRAI)showing the SP electrode (SP

band).

2000 Halliburton

Physics of the MeasurementThe SP is a passive measurement of very smallelectrical voltages resulting from electrical currentsin the borehole caused by the differences in thesalinities (resistivities) of the formation connatewater (R w) and the drilling mud filtrate (R mf ), and bythe presence of ion selective shale beds. Thevoltage changes are measured by a downholeelectrode relative to a surface ground. Unlike otherlogging tools which are displayed on a specificscale with a specified reference value, the SP hasno specified origin and values used for computationare referenced to deflection from the nearby shalebaseline established by the interpreter.

The SP is one of the oldest logging measurements(very old logs may show the curve as "permeability"or "porosity"). It continues to be one of the leastunderstood measurements, in terms of basicphysical principles of operation.

Volume of InvestigationVertical

Resolution(feet)

Radius ofInvestigation

Precision(+-)

SP 1/porosity shallow 1mV

Operational ConstraintsThe tool can be run:

open hole centered

cased hole eccentered

In a borehole fluid of:

gas or air

water or water-based mud

oil or oil-based mudLogging speed: The logging speed is constrained byother measurements in the toolstring.Comments: Usually run with induction logs and oldelectric logs, the SP can also be run with laterologs,sonics, micrologs, dipmeters, and sidewall cores. Thereusually is no separate "SP tool".



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Measurement NamesMeasurement names preceded by an asterisk (*) are not listed in current acquisition companyliterature, and may no longer be available, or are obsolete.WIRELINE Mnemonic

Baker AtlasSpontaneous Potential SP

ComputalogSpontaneous Potential SP

HalliburtonSpontaneous Potential SP

GearhartSpontaneous Potential, SP

WelexSpontaneous Potential, SP

Reeves WirelineSpontaneous Potential SP

SchlumbergerSpontaneous Potential SP

Tucker WirelineSpontaneous Potential SP

MWD/LWD MnemonicThere are no MWD/LWD SP measurements

Curves Displayed(Curves are listed by generic name, common mnemonics (if any) and measurement units.)Curve Name Mnemonics Units of MeasurementSpontaneous Potential SP mV



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Log Example



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Interpretation DetailsCORRELATION OF FORMATIONS

Curves are scanned for similarities in shape and magnitude.

GROSS LITHOLOGYReservoirs are shown as deflections (either positive or negative) from a relatively stable (andarbitrary) shale baseline. The direction of the deflection is determined by the relative salinities(resistivities) of the formation water (R w) and the mud filtrate (R mf ), and is not directly related toformation porosity or permeability.

As a rule of thumb the following relationships are true:

If Rmf > R w, then the SP deflection is negative.

If Rmf = R w, then the SP deflection is zero.

If Rmf < R w, then the SP deflection is positive.

ESTIMATE OF FORMATION WATER RESISTIVITY (R w)SP response equation:

=

we

mfe

R

R K SP log

SP = Spontaneous Potential (from the log)

K = temperature-dependent factor (K=61+ 0.133*T; T in F).

R mfe = equivalent mud filtrate resistivity.

R we = equivalent formation water resistivity.

The magnitude of the SP is measured from the shale baseline near the zone of interest. Thebaseline is usually assumed to have a value of zero. "Equivalent" resistivities are required tocorrect for the non-linear relationship between resistivity and ionic activity which exists at highNaCl concentrations, and when significant amounts of divalent (non-NaCl) ions are present.

A good estimate of Rw (at formation temperature) can be obtained from the following equation:( )( ) K SP R K

wmf R

/log10

+=

where R mf is corrected to formation temperature.

See pages SP 9 or SP 10 for detailed flow charts to determine R w from the SP.



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Spontaneous PotentialESTIMATE OF SHALE (CLAY) CONTENT

Shale/clay volume equation:

==

shaleclean

clean shaleclay SP SP

SP SP V V

log

Vclay = V shale = Shale or clay volume.

SP log = SP in the zone of interest (read from the log).

SP clean = maximum SP deflection from a nearby clean wet zone in the same well.

SP shale = SP value at the shale baseline (often considered to be zero).

This method assumes a constant R w for all zones considered. It also assumes that the responseof the SP to shaliness is linear.

The terms shale and clay are used almost interchangeably in log analysis techniques, eventhough the understanding of the difference between shale and clay have matured since thedevelopment of the techniques.

QUALITATIVE INDICATION OF PERMEABILITYThe presence of an SP (positive or negative) opposite a bed indicates permeability. Only aminimal amount of permeability is required to develop an SP and therefore there is no techniqueto determine the magnitude of the permeability from the SP. The permeability may in fact beonly ionic and not hydraulic.

IDENTIFICATION OF DEPOSITIONAL ENVIRONMENTSDepositional environments can be inferred from the shape of the SP. The method is ambiguous,and should therefore be used only in support of other data in an area of interest. Depositionalenvironment interpretation will work best if data from several wells are used to create a three-dimensional subsurface picture, rather than the use of data from only one well.Environmental effects which may decrease the magnitude of the SP, such as differences invalues of R mf from well to well or the presence of hydrocarbons, can produce the same effects onthe SP as shaliness. The presence of these effects should be considered in the interpretation,either in a qualitative way, or thorough more rigorous normalization procedures which account forRmf differences.

COMPARISON OF SP BETWEEN WELLSWhen comparing the SP curves in a variety of wells, remember that:

The location of the shale baseline on the log grid is set by the logging engineer, and hasno interpretive meaning.

Differences in SP magnitude between wells could be due to:o A change in the shaliness of the formation,o A change in mud filtrate resistivity, R mf , in different wells.o The presence of hydrocarbons in one of the wells,o A change in the formation water resistivity, R w.



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Secondary EffectsENVIRONMENTAL EFFECTS

Shale: The presence of shale in the formation will cause a smaller deflection (either positive ornegative) from the shale baseline than in an equivalent clean formation. The response isassumed to be linear.

Hydrocarbons: Oil or gas in the formation will cause a smaller deflection from the shale baselinethan in an equivalent wet formation. There is no equation to quantify this decrease.

Other effects:

Those with corrections: borehole size, bed thickness, depth of invasion.

Those without corrections: poor ground, stray rig currents, magnetized logging cable, electricalstorms, nearby power lines on pumping wells, logging cable rubbing against rig floor,...

Streaming potential: an increase in the magnitude of the SP due to fluid flow between theformation and the borehole. This phenomenon will appear as excessive SP values beyond thatanticipated from the R mf /R w contrast. This is a rare phenomenon.

Baseline drift: The gradual change in SP baseline (that is, the value of the SP in shales), eitherpositive or negative, with depth. Many possible environmental and equipment factors cancontribute to this phenomenon which must be recognized during the interpretation. The causesof baseline drift are poorly understood (if at all) and have no meaning in interpretation.

Most logging software packages have routines to remove the drift, so that long sections of log canbe easily processed using a constant value for the baseline.

Note: The location of the SP baseline on the log is controlled by the logging engineer, and not byany physical phenomena. Positioning of the baseline is done for aesthetic reasons (and ease ofreading the curve) rather than as part of calibration to a universal standard.

INTERPRETATION EFFECTSHydrocarbons and/or shale (clay) in the formation will cause the calculated R w to be higher thanthe actual formation water resistivity; this will cause the water saturation, S w, calculated from

Archie's Equation to also be higher than the actual formation water saturation.



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Environmental CorrectionsThis table indicates the corrections for the borehole and formation conditions that can be madefor each logging measurement. The corrections that are applicable to the measurement areshown in bold .

CORRECTION COMMENTSboreholemud weightbed thicknessinvasionmud cakeborehole salinityformation salinitystandoffpressuretemperature

excavationpropagation timeattenuationlithology

Not all acquisition companies may have the correction indicatedon this chart, or make corrections for all generations of the tool.

For newer logs, corrections may have been made at the time ofdata acquisition. Check the log header for information.

Algorithms which are equivalent to (or often better than) thechartbooks may be available from the acquisition company, or in

some formation evaluation software packages.

Quality ControlThe SP should be recorded as noise-free as possible.

SP baseline shifts made by the logging engineer (done for display purposes) should be abrupt,made in the shale sections (not reservoirs), and noted on the log.

Check repeatability; curves should have the same values and character as those from previousruns or repeat sections. SP should repeat very well except under unusual conditions (e.g.,streaming potential).

Cross-check the curve character with other curves from the same logging run.



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Spontaneous PotentialPROCEDURE FOR DETERMINATION OF R w FROM THE SP

Taken from the procedure outlined in Schlumberger chartbooks. Use the Log Example in thissection.

1: Identify a zone on the logs which is clean, wet, and permeable.2: Read the SP value at the depth of maximum deflection.

SP = _______ mV at __________ feet.

3: Calculate formation temperature (FT) at the depth of the SP value. (Use Schlumberger chartGen-6 with total depth and maximum temperature from the log heading.)

Total depth (TD) = ______ feet

Formation depth (FD) = ______ feet

Bottom hole temperature (BHT) = ______ F

Formation temperature (FT) = ______ F

Annual Mean Surface Temperature (AMST) = ______F

The following equation can also be used:

AMST FDTD

AMST BHT FT +

=

4: Convert R mf from surface temperature to formation temperature (use Schlumberger chart Gen-9 with R mf at measured temperature from the log heading).

R mf = _______ohm-m @ ________F (measured temperature)

R mf = _______ohm-m @ ________F (formation temperature).

The following equation (Arps equation) can also be used:

( )( )77.6

77.6++

= FM

Tk FM T

Tk R R

R FM = fluid resistivity at formation temperature T FM (in F).

R Tk = known resistivity at a known temperature, Tk.

Tk = known temperature (in F).

5: Convert R mf at formation temperature to R mfeq using one of the following:

a: If R mf @ 75 F > 0.1 ohm-m, use R mfeq = 0.85R mf .

b: If R mf @ 75 F < 0.1 ohm-m, use Schlumberger chart SP-2.

(a and b are included on Chart SP-1 of the Schlumberger chartbook).

R mfeq = ______ohm-m @ ________F (formation temperature).

6: Using SP, formation temperature, and R mfeq , enter Schlumberger chart SP-1 to find R weq .

R weq = _______ohm-m @ _________F (formation temperature).

The following equation can also be used:( )( ) K SP R K

weqmfsq R

/log10

+=

7: Convert R weq to R w using Schlumberger chart SP-2.

Rw = _______ohm-m @ ________F (formation temperature).



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Spontaneous PotentialPROCEDURE FOR DETERMINATION OF R w FROM THE SP:

Taken from the procedure outlined in Western Atlas chartbooks. Use the Log Example in thissection.

1: Identify a zone on the logs which is clean, wet, and permeable.2: Read the SP value at the depth of maximum deflection.

SP = _______ mV at __________ feet.

3: Calculate formation temperature at depth of SP value. (Use Atlas chart 1-1 with total depthand maximum temperature from the log heading.)

Total depth (TD) = ______ feet

Formation depth (FD) = ______ feet

Bottom hole temperature (BHT) = ______ F

Formation temperature (FT) = ______ F

Annual Mean Surface Temperature (AMST) = ______F

The following equation can also be used:

AMST FDTD

AMST BHT FT +

=

4: Convert R mf from surface temperature to formation temperature (use Atlas chart 1-5 with R mf atmeasured temperature from the log heading).

R mf = _______ohm-m @ ________F (measured temperature)

R mf = _______ohm-m @ ________F (formation temperature).

The following equation (Arps equation) can also be used:

( )( )77.6

77.6++

= FM

Tk FM T

Tk R R




5: Using SP, formation temperature, and R mf , use Atlas chart 2-2 to find R weq .

R weq = _______ohm-m @ _________F (formation temperature).

The following equation can also be used:( ) BHT SP

mfeqweq R R += 133.061/10

6: Convert R weq to R w using Atlas chart 2-3.

R w = _______ohm-m @ ________F (formation temperature).

The following equation can also be used:( )[ ]

( )[ ]8.50/log0426.0

0.29.19/log/1

105.0

10131.0 BHT

weq

BHT weq

w R

R R

+

+=



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Spontaneous PotentialPROCEDURE FOR DETERMINATION OF R w FROM THE SP: ANSWER

Taken from the procedure outlined in Schlumberger chartbooks. Use the Log Example in thissection.

1: Identify a zone on the logs which is clean, wet, and permeable.Large SP, low GR, low resistivity

Possibilities: 10,317 or 10,340

Go with 10,317: closer to pay, lower GR, thicker zone.

2: Read the SP value at the depth of maximum deflection.

SP = __-87 __ mV at ___ 10,317 __ feet.

SPshale = +5, SPclean = -82; SP = -87

or, SP baseline = 0 (by definition); SP = -87

3: Calculate formation temperature (FT) at the depth of the SP value using the equation below.

Total depth (TD) = _ 11,192 _ feetFormation depth (FD) = _ 10,317 _ feet

Bottom hole temperature (BHT) = _ 175 __ F

Formation temperature (FT) = __ 168 __ F

Annual Mean Surface Temperature (AMST) = __ 80 __F

16880196,11

80175 =+

=+

= AMST FDTD

AMST BHT FT

(Schlumberger chart Gen-6, with total depth and maximum temperature from the log heading, canbe used in place of the above equation.) 4: Convert R mf from surface temperature to formation temperature using the Arps equation

below.R mf = __ 0.58 __ohm-m @ ___ 70 ___F (measured temperature)

R mf = __ 0.26 __ohm-m @ __ 168 ___F (formation temperature).

( )( )

( )( ) 26.077.6168

77.67058.077.6

77.6 =+

+=++

= FM

Tk FM T

Tk R R




(Schlumberger chart Gen-9, with R mf at measured temperature from the log heading, can be usedin place of the above equation.)

5: Calculate the SP factor, K:

3.83168133.061133.061 =+=+= FT K 6: Using SP, formation temperature, and R mf , calculate R w from the equation below.

R w = __ 0.023 __ohm-m @ ___ 168 ___F (formation temperature).( )( ) ( )( ) 023.01010 3.83/)87(26.0log3.83/log === +

+ K SP R K w

mf R

(Schlumberger chart SP-1 can be used in place of the above equation to find R w .)



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GR 3Correlation/Lithology

Gamma Ray


Baker AtlasGamma Ray GRSpectralog SL

ComputalogGamma Ray GRSpectral Gamma Ray SGR

HalliburtonGamma Ray GRCompensated Spectral Natural Gamma Ray CSNGNatural Gamma Ray Tool NGRT

Gearhart*Gamma Ray, GR; *Natural Gamma Ray Spectral Log, SGR

Welex*Gamma Ray, GR; *Compensated Spectral Natural Gamma Ray, CSNG

Reeves WirelineCompact Gamma Ray MCG, MGSSpectral Gamma Sonde

SchlumbergerIntegrated Porosity Lithology IPLPlatform Express*Gamma Ray, GR; *Natural Gamma Ray Spectrometry Log, NGS, NGT

Tucker WirelineGamma Ray Tool GRT

MWD/LWD MnemonicBaker Hughes INTEQ

Directional-Gamma DGResistivity-Gamma-Directional RGD

Exlog

*Gamma Ray, DLWD componentTeleco

*Gamma Ray, DG, DDG, RGD, ReGD componentPathfinder

Directional Gamma Ray HDS1Resistivity Gamma Ray CWRD

Schlumberger LWD (Anadrill)Vision 475*Gamma Ray; *Resistivity at Bit, RAB (focused gamma ray)

Sperry SunDGR Sensors DGRMWD Triple Combo*Dual Gamma Ray, DGR; *Natural Gamma Probe, NGP

Curves Displayed(Curves are listed by generic name, common mnemonics (if any) and measurement units.)Curve Name Mnemonics Units of MeasurementGamma Ray, Total Gamma Ray GR API UnitsUranium-Free Gamma Ray GRS, SGR, KTH API UnitsPotassium POTA, K PercentUranium URAN, U ppmThorium THOR, TH ppm

Guide to Petrophysical InterpretationDaniel A. Krygowski, Austin Texas USA


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Gamma Ray

Log Example



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Gamma Ray

Interpretation DetailsCORRELATION OF FORMATIONS

Curves are scanned for similarities in shape and magnitude.

GROSS LITHOLOGYIn general, reservoirs are less radioactive than shales. However, some sandstones anddolomites can be radioactive.

ESTIMATE OF SHALE (CLAY) CONTENTThe magnitude of the gamma ray in the formation of interest (relative to that of nearby clean andshale zones) is related to the shale content of the formation. The relationship between gammaray magnitude and shale content may be linear or non-linear. The relationships are all empirical.

Gamma Ray Index, I GR :

clean shale

clean

GRGRGR

GRGR I

=

log

IGR describes a linear response to shaliness or clay content.

GR log = log reading at the depth of interest

GR clean = Gamma Ray value in a nearby clean zone

GR shale = Gamma Ray value in a nearby shale

Linear Gamma Ray - clay volume relationship:

Vshale = I GR

Non-linear Gamma Ray - clay volume relationships:

Steiber:

GR

GR shale

I

I V

=

0.20.3

Clavier:

( )[ ] 5.027.038.37.1 += GR shale I V

Larionov (Tertiary rocks):

( )12083.0 7.3 = GR I shaleV

Larionov (older rocks):

( ) 0.1233.0 2 = GR I shaleV



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Gamma Ray

All the above relationships are empirical. The choice of which to use is up to the user, anddepends on other information that may be available. If no other information is known, the linearrelationship is probably the best choice, although it is the most pessimistic (that is, it predicts themost clay volume for a given Gamma Ray response. All the non-linear relationships predict less

clay volume than the linear response, in varying amounts depending on the Gamma Ray readingand the clean and shale values.

The terms shale and clay are used almost interchangeably in log analysis techniques, eventhough the understanding of the difference between shale and clay have matured since thedevelopment of the techniques.

* CLAY TYPINGThe method involves plotting the potassium responses against those of thorium which will givesome indication of the type of clay present in the formation. This technique assumes thepresence of pure clays, which rarely exist in reservoirs. Because of its limitations, this techniqueis no longer widely used.

The uranium-free curve is often a better shaliness indicator than the total gamma ray curve,because it can distinguish between the gamma rays counted from potassium and thorium in claysand the gamma rays resulting from uranium which are not necessarily associated with clays.

* FRACTURE IDENTIFICATIONSpikes to higher values of uranium may indicate fractures due to the deposition of solubleuranium compounds in the fractures during reservoir fluid movement. The technique isambiguous, and even when working, will not distinguish closed from open fractures.

* SOURCE ROCK IDENTIFICATIONConsistently high uranium readings in shales may indicate high source rock potential due to the

uranium compounds associated with the organic material.

* These interpretations are usually based on spectral gamma ray logs only.



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Gamma RaySecondary Effects

ENVIRONMENTAL EFFECTSHole size: increasing hole size decreases count rates.

Mud weight: increasing mud weight decreases count rates.

Centering: centering the tool decreases count rates.

Mud type: KCl muds increase potassium count rates in spectral tools; barite-weighted mudsaffect all count rates.

Logging Speed: In older logs, the logging speed may cause some variation in the response, withlogs acquired at a faster speed having somewhat less definition and activity than those acquiredat slower speeds.

INTERPRETATION EFFECTSSandstones and dolomites may occasionally be radioactive and respond as shales. A Density-Sonic crossplot may help to distinguish radioactive ("hot") reservoirs from shales.



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Gamma Ray








Quality ControlThe gamma ray should agree with other shale indicators except in radioactive beds.

The uranium-free curve should always be less than or equal to the total gamma ray curve.

The uranium curve should never be negative.

Shale values should be similar to those in nearby wells.

Check repeatability; curves should have the same values and character as those from previousruns or repeat sections.




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CAL 1Correlation/Lithology

Caliper

Interpretation GoalsIndication of hole diameter and volume.

Input for environmental corrections for other measurements.

Qualitative indication of permeability.Correlation.Log quality control.



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Caliper

Tool DiagramHalliburton 4-arm caliper tool (FACT).

1999 Halliburton

Physics of the MeasurementFor wireline tools, the physical movement of armson the tool is converted to a diameter measurementthrough electrical circuitry. The arms are intendedto either keep the tool centered in the borehole, orto push the tool against the borehole wall.

Some MWD tools generate a caliper curve basedon the differences in the response of the detectorsas the tool rotates. Other tools use ultrasonicsensors to generate a caliper by measuring thetime taken for an acoustic pulse to travel from thesensor to the formation wall and back.


Resolution Depth of

Investigation Precision

Caliper Notdefined NoneNot

defined


open hole centered 1

cased hole eccentered 1


gas or air


oil or oil-based mud

Logging speed: The logging speed is constrained byother measurements in the toolstring.Comments:The measurement is usually auxiliary to othermeasurements being made.1Centering depends on the requirements of the othertools in the toolstring.



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Caliper


Baker AtlasCaliper CAL*4-Arm Dual Caliper, *4CAL; *Multi Finger Caliper, MFC

ComputalogCaliperDual Axis Calipers DACMulti Sensor Caliper MSC

HalliburtonCaliper CL*Four Arm Caliper Tool, FACT; *Four Independent Arm Caliper, FIAC

Gearhart*Caliper, CL; *X-Y Caliper

Welex*Caliper, CL

Reeves WirelineTwo Arm Caliper TACCompact Two Arm Caliper MCT*Caliper, CAL; *Four Arm Caliper, FAC

SchlumbergerEnvironmental Measurement Sonde EMS*Caliper, CAL; *Borehole Geometry Tool, BGT

Tucker WirelineCentralizer Caliper Tool CCTXY Caliper Tool XYT


Caliper Corrected Neutron CCNExlog

(none)Teleco

(none)Pathfinder

Density Neutron Caliper DNSCDensity Neutron Standoff Caliper Tool DSNCM

Schlumberger LWD (Anadrill)*Compensated Density Neutron, CDN (Downhole Sonic Caliper)

Sperry Sun Acousticaliper MWD tool

Curves Displayed(Curves are listed by generic name, common mnemonics (if any) and measurement units.)Curve Name Mnemonics Units of MeasurementCaliper CAL, CALI Inches, cm



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Caliper

Log Example



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Caliper

Interpretation DetailsINDICATION OF HOLE DIAMETER AND VOLUME

Hole diameter is read directly from the log. One- or two-arm calipers (like with the Density,

Dipmeter, or Rxo tools) will tend to read the long diameter of the hole if the hole is elongated,while three-arm calipers (like with the Sonic) will read an average, somewhere between thelength of the long and short axis. One arm or two arm calipers will tend to be more sensitive thanthree-arm calipers. Calipers which show diameter in two orthogonal directions will show holeswhich have become elongated.

Hole volume is computed by integrating the hole volume calculated at each depth sample. Thehole is assumed to be circular for a single diameter measurement, and assumed elliptical for atwo dimensional measurement.

INPUT FOR ENVIRONMENTAL CORRECTIONS FOR OTHER TOOLSThe hole diameter is used in various charts for Density, Neutron, Laterolog, and Induction, and toindicate the thickness of mud cake for Rxo tool corrections.

QUALITATIVE INDICATION OF PERMEABILITYThe existence of mudcake (when the borehole diameter is less than the bit size) is an indicationof the infiltration of mud into the formation. Because of differences in mud type, density, andother parameters, the magnitude of permeability cannot be determined. Mudcake is usuallynoted as a comparison to bit size. When the hole is washed out, the presence of mudcake can bemasked by the washout.

CORRELATIONCurves can be scanned for general shape and changes in indicated hole size. Some formationscan consistently wash out in a particular geographic area (regardless of mud program), giving ageneral indication of the location of the well in the subsurface.

LOG QUALITY CONTROLIndications from the Caliper that the hole is rough is a warning that measurements which are fromtools pressed against the borehole wall, such as Density, Neutron, and the microresistivitycurves, may not be reliable.



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Caliper


In highly deviated holes, the caliper mechanism may not be strong enough to support the weight

of the logging tool, and may not indicate the actual diameter of the hole.

INTERPRETATION EFFECTSOccasionally, mud cake indications can be masked by a washed out borehole.



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Caliper








Quality ControlCheck the caliper value in casing against the casing diameter.






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Porosity

Porosity

This section contains information about the three common porosity measurements;Sonic/Acoustic , Density , and Neutron . Although called porosity measurements, noneof the logging tools actually measure porosity directly. It is this indirectness that leads, inpart, to the interpretation of the measurements in pairs or in triads. The PorosityCombination part of this section details the interpretations that produce better estimatesof porosity, and as a by-product, estimates of formation lithology.



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SON 1Porosity

Sonic/Acoustic

Interpretation GoalsPorosity (from interval transit time, DT)).

Lithology identification (with the Density and/or Neutron).

Synthetic seismograms (with the Density).Formation mechanical properties (with the Density).Detection of abnormal formation pressures.

Permeability identification (from waveforms).Cement bond quality.

Borehole size (from an attached caliper).



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SON 2Porosity

Sonic/Acoustic

Tool DiagramHalliburton Full Wave Sonic tool(FWST) in its long-spaced

2000 Hallibu

configuration.

rton

Physics of the Measurement A high frequency (10s of KHz) acoustic pulse froma transmitter is detected at two or more receivers.The time of the first detection of the transmitted

pulse at each receiver is processed to produce aninterval transit time called delta t ( ! t orDT). Thedelta t is the transit time of the wave front over onefoot of formation. If the entire acoustic waveform iscaptured, arrival times and attenuations (energydecrease) of several portions of the waveform canbe measured including: compressional (thestandard delta t), shear, and Stoneley.

Compensated tools use multiple transmitter-receiver pairs to minimize the effects of boreholesize changes.

Array or similarly named tools usually have 4 ormore receivers, and the data from all receivers isprocessed to determine arrival times.

Some tools are designed specifically for shearwave measurements.


Resolution90%

Radius ofInvestigation-

50%

Precision(+-)

DT 12 in.* ~6 in. 1 usec/ft

*depends on receiver spacing


open hole centered 1

cased hole eccentered 1

In a borehole f lu id of :

gas or air



Logg ing sp eed : 60 feet/minute.Array or full wave tools may require slower loggingspeeds.Comments :1To minimize signal attenuation, the tool should be runcentered in holes smaller than 16 inches, andeccentered in holes larger than 16 inches. The toolshould always have some standoff in order to reduceroad noise.



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SON 3Porosity

Sonic/Acoustic


Baker Atlas Acoustic Properties Explorert APXCross-Multipole Array Acoustic XMACBorehole Compensated Acoustilog DAL, AC*Long Spaced BHC Acoustic, ACL; *Multiple Array Acoustilog, MAC; *Digital Array Acoustilog,DAC

ComputalogBorehole Compensated Sonic BCSDigital Acoustic Array DARHigh resolution sonic logs (BCS variants)Long Spaced Sonic, LSS; Sonic Signature Log, SSL

HalliburtonFull Wave Sonic FWSMultipole Acoustic Logging Service XACT

*Borehole Compensated Sonic, BCS; *Long Spaced Sonic, LSS; *Low Frequency Dipole Tool,LFDT

Gearhart*Borehole Compensated Sonic, BCS; *Long Spaced Sonic, LSS

Welex*Compensated Acoustic Velocity, CAV; *Full Wave Sonic, FWS; *Acoustic Velocity Log

Reeves WirelineCompensated Sonic Sonde CSSLong Spaced Compensated Sonic Sonde LCSCompact Sonic Sonde MSSUltrasonic Gase Detector UGD*Sonic Waveform, SW

SchlumbergerDipole Shear Sonic Imager DSI

*Borehole Compensated Sonic Log, BHC; *Long Spaced Sonic, LSS; *Array-SonicTucker WirelineCompensated Sonic Tool CSTLong Spaced Sonic Tool LST


No information available.Exlog

*(none)Teleco

*(none)Pathfinder

Density Neutron Caliper DNSCSchlumberger LWD (Anadrill)

IDEAL Sonic-While-Drilling Tool ISONICSperry SunBi-Modal Acoustic Tool BAT

Curves Displayed(Curves are listed by generic name, common mnemonics (if any) and measurement units.)Curve Name Mnemonics Uni ts of MeasurementInterval transit time, travel time(for compressional, shear, and/or Stoneley waves) DT, ! t usec/ft, usec/m



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SON 4Porosity

Sonic/Acoustic

SON 4Porosity

Sonic/Acoustic


Log Example



36/147

SON 5Porosity

Sonic/AcousticWaveform display



37/147

SON 6Porosity

Sonic/AcousticVariable density display



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SON 7Porosity

Sonic/Acoustic

Interpretation DetailsCHARACTERISTIC VALUES:

Matrix Value(Wyllie)DTMa

Matrix Value(Raymer-Hunt-Gardner))

DTMa

Fluid Value

DTFl

Sandstone 51.3 to 55.6 168 to 182 56 184Limestone 43.5 to 47.6 143 to 156 49 161Dolomite 38.5 to 43.5 126 to 143 44 144Anhydrite 50 164 50 164Halite 67 220 67 220Coal >100 >328 >100 >328Steel 57 187 57 187

Gas 920 3018Oil 230 755

Water 179 to 208(189)587 to 682

(620)Units usec/ft usec/m usec/ft usec/m usec/ft usec/m

POROSITYWyllie Time-Average Equation:

cpma fl

ma

cpS Bt t

t t

B DTMa DTFl DTMa DT

SPHI 11

"!#!

!#!$"

##

$$ %

SPHI = %S= sonic (acoustic) porosity

DT = ! t = sonic travel time (from the log)

DTMa = ! tma = matrix travel time

DTFl = ! tfl = fluid travel timeBcp = compaction correction, where

0.1100

&$ DTShale

Bcp

The Bcp factor was added to the equation when it was found that the equation gave highlyoptimistic porosity values in unconsolidated sands. DTShale is picked from a shale near the zoneof interest. The correction factor is never less than 1.0.

Raymer-Hunt-Gardner Equation (Schlumberger Empirical Relation):

t

t t

DT

DTMa DT SPHI maS

!

!#!"$

#"$$

8

5

8

5%

SPHI = %S= sonic (acoustic) porosity

DT = ! t = sonic travel time (from the log)

DTMa = ! tma = matrix travel time

The above equation is an approximation of Schlumberger chart Por-3.



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SON 8Porosity

Sonic/AcousticLike the Wyllie equation, Raymer-Hunt-Gardner is based on empirical data. It is non-linear inform, resulting in lower porosities than Wyllie for high DT, as in uncompacted sands. Nocompaction correction is needed.

The choice of which equation to use depends on the interpreter. If other porosity information isavailable, as from cores, choose the equation which best fits the supporting data.

The formation matrix traveltime, DTMa, is the acoustic traveltime of the formation at zero porosity.Its value depends on the lithology of the formation (see the Characteristic Values, above). Sincethe Sonic log "sees" the formation close to the borehole, the fluid is assumed to be the drillingmud filtrate. The formation fluid traveltime, DTFl, varies somewhat with the salinity of theformation, but is usually assumed to be 189 usec/ft.

LITHOLOGY IDENTIFICATIONLithology is determined by comparison of delta t with Neutron and Density data in crossplots, inMatrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tooltype, Sonic response equation type, and by service company.

The ratio of shear to compressional DT may also be an indicator of gross lithology.

SYNTHETIC SEISMOGRAMSSonic compressional and Density data are used to determine acoustic impedance of theformations along the borehole, and reflection coefficients at bed boundaries. The syntheticseismic trace that is derived from that information can be displayed in depth or time to becompared to the seismic data.

The logs can also be modeled with varying fluid properties (and sometimes also with varyingporosity), and synthetics calculated from the modeled curves, to help determine the response ofthe seismic data to the subsurface.

FORMATION MECHANICAL PROPERTIESCompressional and shear sonic data are used with density data to calculate formation propertiessuch as Poisson's ratio and Young's Modulus, and formation strength.

Formation strength calculations can be used to determine the mud weight range to be used whiledrilling to ensure borehole stability. Information on relative formation strengths supports thedesign of hydraulic fracturing so that fractures remain in the target formations instead ofextending to adjacent formations. Formation strength can also support predictions of drawdownpressures so that sand-free production can be maintained when a well is completed andproduced.

DETECTION OF ABNORMAL FORMATION PRESSURESSonic traveltime values in shales are plotted against depth. Sharp deviations from a general trend

of decreasing DT with depth indicate the presence of geopressured (overpressured) zones.

PERMEABILITY IDENTIFICATION Attenuation of some of the later arrivals in the acoustic wavetrain (shear and Stoneley waves)gives some indication of permeability. The attenuation is, however, affected by other parameters,such as lithology. This technique is not well defined.



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SON 10Porosity

Sonic/Acoustic


Enlarged borehole, formation fractures, gas in the borehole or formation, or improper

centralization can produce signal attenuation resulting in "cycle skipping", or DT spikes to highervalues.

Improper centralization, the lack of standoff, or excessive logging speed can result in "roadnoise", or DT spikes to either higher or lower values.

INTERPRETATION EFFECTSLithology effects are manifested in the necessity to chose a matrix traveltime (DTMa) value inorder to calculate porosity.

Porosity calculations in uncompacted formations will yield porosity values higher than actualporosity when using the Wyllie equation. This can be accounted for through the use of thecompaction factor, Bcp, in the Wyllie equation, or by use of the Raymer-Hunt-Gardner equation.

Porosity calculated in gas bearing zones will be slightly higher than actual porosity because thetraveltime in gas is higher than in water.



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SON 11Porosity

Sonic/Acoustic








Quality ControlThere should be no spikes or interruptions in DT.

Check DT values in anhydrite (50 usec/ft), salt (67 usec/ft), or zones of known zero porosity.

DT = 57 usec/ft in casing.

For waveforms, the arriving signal of interest should not be saturated (truncated at its highest

values) and should be apparent on the display.Shale values should be similar to those in nearby wells.





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DEN 1Porosity

Density

Interpretation GoalsPorosity (from bulk density, RHOB).

Lithology identification (from the PEF curve and/or with the Neutron and/or Sonic).

Gas indication (with the Neutron).Synthetic seismograms (with the Sonic).Formation mechanical properties (with the Sonic).

Clay content (shaliness) (with the Neutron).Borehole size (from an attached caliper).



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DEN 2Porosity

Density

Tool DiagramHalliburton spectral density tool (SDL).

2000 Halliburton

Physics of the MeasurementHigh energy gamma rays are emitted from achemical source (usually Cesium 137) and interactwith the electrons of the elements in the formation.Two detectors in the tool count the number ofreturning gamma rays which are related toformation electron density. For most earthmaterials of interest, the electron density is relatedto formation bulk density through a constant.

In newer spectral tools, the number of returninggamma rays at two different energy ranges aremeasured. The higher energy gamma rays (fromCompton Scattering) determine bulk density, andtherefore porosity, while the lower energy gammarays (due to photoelectric effect) are used todetermine formation lithology. The lower energygamma rays are related to the lithology of theformation and show little dependence on porosityor fluid type.


Resolution90%

Depth ofInvestigation-

50%

Precision(+-)

Bulk density 33 in.5.5 in.* 1.5 in.0.01

g/cm3

PE 33 in.2 in.* 0.5 in. 5%

*with enhanced resolution processing


open hole centered

cased hole 1 eccentered


gas or air



Logging speed: 60 feet/minute. May require slowerspeeds for enhanced resolution processing.Comments:1Can be run in cased holes in special conditions.



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DEN 3Porosity

Density

Measurement NamesMeasurement names preceded by an asterisk (*) are not listed in current acquisition companyliterature, and may no longer be available, or are obsolete. WIRELINE Mnemonic

Baker Atlas Advantage Porosity Logging Service APLSCompensated Z-Density ZDLCompensated Densilog CDL

ComputalogSpectral Pe Density SPeD*Spectral Litho Density, SLD; *Compensated Density, CDL

HalliburtonSpectral Density Log SDL

Gearhart*Spectral Litho-Density, SDL; *Compensated Density Log, CDL

Welex*Spectral Density, SDL; *Compensated Density Log, DEN

Reeves Wireline

Photo Density Sonde PDSCompact PhotoDensity MPD*Compensated Density, CDS

SchlumbergerIntegrated Porosity Lithology IPL*LithoDensity Log, LDT; *Compensated Formation Density Log, FDC

Tucker WirelineCompensated Density Tool CDTLithology Density Tool LDT

MWD/LWDBaker Hughes INTEQ

Optimized Rotational Density ORDModular Density/Lithology MDL

Exlog

*(none)Teleco

*Modular Density Porosity, MDPPathfinder

Density Neutron Standoff Caliper Tool DNSCMDensity Neutron Caliper DNSC

Schlumberger LWD (Anadrill)Vision475

Sperry Sun Azimuthal Stabilized Litho Density ASLDMWD Triple Combo*Simultaneous Formation Density, SFD

Curves Displayed(Curves are listed by generic name, common mnemonics (if any) and measurement units.)Curve Name Mnemonics Units of MeasurementBulk density RHOB, DEN, ZDEN g/cm3, kg/m3Density porosity (referenced to a specific lithology) DPHI, PHID, DPOR %, v/v decimalDensity correction DRHO g/cm3, kg/m3Photoelectric effect (lithology indicator) PE, Pe, PEF b/eCaliper (hole diameter) CALI, CAL Inches, cm



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DEN 4Porosity

Density

DEN 4Porosity

Density


Log Example



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DEN 5Porosity

Density

Interpretation DetailsCHARACTERISTIC VALUES

Matrix ValueRhoMa

Fluid ValueRhoFl

LithologyPEF

Sandstone 2.65 2650 1.81Limestone 2.71 2710 5.08Dolomite 2.87 2870 3.14Anhydrite 2.98 2980 5.05Halite 2.04 2040 4.65Coal ~1.2 ~1200 0.2Barite 4.09 4090 267.

Gas .2 200 0.95Oil ~0.85 ~850 0.12Water 1.0 to 1.2 1000 to 1200 0.36 to 1.1

Units g/cm3 Kg/m3 g/cm3 Kg/m3 b/e

POROSITY

fl ma

bma D RhoFl RhoMa

RHOB RhoMa DPHI

=

==

DPHI = D = density porosity

RHOB = b = bulk density (from the log)

RhoMa = ma = matrix density

RhoFl = fl = fluid density (often assumed to be mud filtrate density)

LITHOLOGY IDENTIFICATION

Lithology is determined by comparison of bulk density with Sonic and Neutron data in crossplots,in Matrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tooltype, Sonic response equation type, and by service company.

The photoelectric effect (PEF) curve can be used alone to determine a single lithology, or incombination with bulk density, or bulk density and Neutron curves to determine mixed lithologies.

GAS INDICATION

Gas is indicated when the Density and Neutron "crossover"; that is, when the neutron porosity isless than the density porosity in a porous and permeable zone. Both curves must be corrected tothe lithology of the zone of interest. Similar crossover may occur as part of a lithology effect, aswhen both the Density and Neutron tools are recorded on limestone matrix, and the lithology isactually a sandstone.

SYNTHETIC SEISMOGRAMS

Sonic compressional and Density data are used to determine acoustic impedance of theformations along the borehole, and reflection coefficients at bed boundaries. The syntheticseismic trace that is derived from that information can be displayed in depth or time to becompared to the seismic data.



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DEN 6Porosity

DensityFORMATION MECHANICAL PROPERTIES

Compressional and shear sonic data are used with density data to calculate formation propertiessuch as Poisson's ratio and Young's Modulus, and formation strength.

Formation strength calculations can be used to determine the mud weight range to be used whiledrilling to ensure borehole stability. Information on relative formation strengths supports thedesign of hydraulic fracturing so that fractures remain in the target formations instead ofextending to adjacent formations. Formation strength can also support predictions of drawdownpressures so that sand-free production can be maintained when a well is completed andproduced.

CLAY CONTENT (SHALINESS)

Density and Neutron data are crossplotted, and a shale point identified on the plot (generally fromassociated Gamma Ray data). The distance between the shale point and a clean formation lineis a measure of the clay content of an individual zone, with the shaliness relationship assumed tobe a linear function of that distance.

BOREHOLE SIZE A mechanical arm opposite the sensors and source hold the density tool against the boreholewall. Movement of the arm is calibrated to indicate hole diameter. Because of tool design, thetool will tend to measure the longest diameter of the hole when the hole is elongated.



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DEN 7Porosity

Density


Enlarged borehole (>9 inches): RHOB < formation bulk density (DPHI > PHI actual ).

Rough hole: RHOB < formation bulk density (DPHI > PHI actual ). This is due to the sensor padlosing contact with the borehole wall. Other indications of a rough hole will be a highly variableCaliper curve, and a high-valued density correction (DRHO) curve. There are no environmentalcorrections than can be applied to correct for loss of pad contact.

Barite muds: RHOB > formation bulk density (DPHI < PHI actual ), and PEF > PEF actual .

INTERPRETATION EFFECTS

Lithology: The porosity calculated from bulk density will be affected by the choice of matrixdensity, RhoMa, which varies with lithology. In dense formations, such as anhydrite, the densityporosity will be negative because the assumed matrix density is less than the actual formationmatrix density.

Fluid content: The porosity calculated from bulk density will be affected by the choice of fluiddensity, RhoFl, which varies with fluid type and salinity. In routine calculations the zoneinvestigated by the density tool is assumed to be completely saturated with mud filtrate.

Hydrocarbons: The presence of gas or "light" hydrocarbons in the pore space investigated by theDensity tool causes the calculated value of density porosity to be more than the actual porosity.This is most noticeable in the presence of gas, causing "crossover" of the Neutron porosity andDensity porosity curves, where the Neutron log values are lower than the Density log values.

In all the cases above, the bulk density value, RHOB, derived from the tool is correct, but thecalculated Density porosity is erroneous because of differences between the assumed matrixand/or fluid density values and the actual densities in the formation.



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DEN 8Porosity

Density








Quality ControlDensity porosity should equal Neutron porosity in clean, wet formations, when both are properlycorrected for lithology.

The correction curve, DRHO, should be near zero in smooth holes.

DRHO values deviating by more than 0.05 may be questionable due to loss of padcontact.

DRHO values deviating by more than 0.10 indicate the density value is notquantitatively reliable.

The DRHO value will be negative in heavy muds (e.g. barite muds).

Continuously large DRHO values in a smooth borehole may indicate excessive padwear (density readings could be questionable), or other problems.

Large DRHO values opposite an apparently smooth borehole wall may indicatefractures (or other small irregularities at the wall surface).

PE will not be reliable in heavy muds, and will show values well over 5.






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NEU 1Porosity

Neutron

Interpretation GoalsPorosity (displayed directly on the log).

Lithology identification (with the Sonic and/or Density).

Gas indication (with the Density).Clay content (shaliness) (with the Density).Correlation; especially in cased holes.



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NEU 2Porosity

Neutron

Tool DiagramHalliburton neutron tool (DSN-II).

1999 Halliburton

Physics of the Measurement A chemical source (Americium-Beryllium) emitshigh energy neutrons which are slowed byformation nuclei. Two detectors in the tool countthe number of returning capture gamma rays orneutrons (depending on the type of tool). Thedetector count rates are inversely proportional tothe amount of hydrogen in the formation ("hydrogenindex"). By assuming that all the hydrogen residesin the pore space of the formation (as water orhydrocarbons), the hydrogen index can be relatedto the formation porosity. "Gamma ray-neutron"tools detect gamma rays and thermal neutrons;"sidewall" tools detect epithermal neutrons;"compensated" tools detect thermal neutrons.

Schlumberger offers a neutron tool which uses anaccelerator to generate neutrons, eliminating theneed for a chemical source. This minimizes safetyissues on the rig floor and in the event the tool islost in the hole.


Resolution90%

Radius ofInvestigation-

50%

Precision(+-)

thermal 36 in.20 in.* 6 in. 0.4 p.u.

epithermal 30-44 in. 6 in. 1 p.u.

Gamma-

neutron20 in. 8 in. NA

*with enhanced resolution processing


open hole centered

cased hole eccentered


gas or air


oil or oil-based mudLogging speed: 60 feet/minute. May require slowerspeeds for enhanced resolution processing.

Comments:



53/147

NEU 3Porosity

Neutron


Baker AtlasCompensated Neutron Log CN*Sidewall Epithermal Neutron Log, SWN; Neutron Log, NEU

ComputalogCompensated Neutron Service CNS*Sidewall Neutron Log, SNL

HalliburtonDual-Spaced Neutron II DSN IIDual-Spaced Epithermal Neutron DSEN

Gearhart*Compensated Neutron Log, CNS; *Sidewall Neutron Log, SNL; *Neutron Log, NL

WelexDual Spaced Neutron II, DSN II; Dual Spaced Neutron, DSN; *Sidewall Neutron, SWN;*Neutron, NEU

Reeves WirelineCompensated Neutron Sonde CNSCompact Dual Neutron MDN

SchlumbergerIntegrated Porosity Lithology IPLPlatform Express*Compensated Neutron Log, CNL; *Sidewall Neutron Log, SNP; *Gamma Ray-Neutron Tool,GNT

Tucker WirelineCompensated Neutron Tool CNT


Caliper Corrected Neutron CCNModular Neutron Porosity MNP

Exlog*(none)Teleco

Modular Nuclear Porosity, MNPPathfinder

Density Neutron Caliper DNSCSchlumberger LWD (Anadrill)

Vision475*Compensated Neutron Density, CDN

Sperry SunCompensated Thermal Neutron CTNMWD Triple ComboCompensated Neutron Porosity CN

Curves Displayed(Curves are listed by generic name, common mnemonics (if any) and measurement units.)Curve Name Mnemonics Units of MeasurementNeutron porosity (referenced to a specific lithology) NPHI, PHIN, NPOR %, v/v decimal

For older (GNT) tools, Counts Counts/second, APINeutron units



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NEU 4Porosity

Neutron

NEU 4Porosity

Neutron


Log Example



55/147


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NEU 6Porosity

Neutron

CLAY CONTENT (SHALINESS)Density and Neutron data are plotted, and a shale point identified on the plot (generally fromassociated Gamma Ray data). The distance between the shale point and a clean formation lineis a measure of the clay content of an individual zone, with the shaliness relationship assumed tobe a linear function of that distance.

CORRELATION Any of the neutron logs can be used in open or cased holes for correlation.



57/147

NEU 7Porosity

Neutron


Enlarged borehole: NPHI > PHI actual

Mudcake: NPHI < PHI actual Borehole salinity: NPHI < PHI actual

Formation salinity: NPHI > PHI actual

Mud weight: NPHI < PHI actual

Pressure: NPHI > PHI actual

Temperature: NPHI < PHI actual

Temperature and pressure have the greatest effects on the the Neutron log.

The Neutron is not as severely affected by rough borehole as the Density log.

INTERPRETATION EFFECTSShaliness: NPHI > PHI actual in shaly zones. Thermal neutron tools are more affected (read higherin shales) than are epithermal neutron tools.

Gas: NPHI < PHI actual in gassy zones. See also the section on "Gas Indication" on the previouspage.

Lithology: In general, for logs recorded in limestone units, if the actual lithology is sandstone, thelog porosity is less than the true porosity, and if the actual lithology is dolomite, the log porosity isgreater than the actual porosity. See the Neutron porosity equivalence curves in the chartbooks.



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NEU 8Porosity

Neutron

Neutron environmental corrections

1988 Schlumberger



59/147

NEU 9Porosity

Neutron








Quality ControlNeutron porosity should equal Density porosity in clean, wet formations, when properly correctedfor lithology.






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Combo 1Porosity

Porosity Combinations

Porosity measurement combinationsRemember that porosity tools dont measure porosity directly:

Acoustic logs measure acoustic wave travel time;

Density logs measure formation bulk density;Neutron logs measure formation hydrogen content.

When using a single porosity measurement,

Lithology must be specified (through the choice of a matrix value) for the correct porosityto be calculated.

When using two or more porosity measurements,

Lithology can be predicted (along with porosity) [with some ambiguity].

The greater the number of measurements, the greater the complexity of the formation that can beassumed.

Measurement preferences (in order of choice)Two measurements:

Neutron and Density

Neutron and Sonic

Spectral Density (bulk density and Pe)

Density and Sonic

Three measurements:

Neutron and Spectral Density

Neutron, Density, and Sonic

MID (Matrix Identification) plots

M-N plots

Interpretive techniquesQuicklook

Graphical techniques, usually comparing measurements in a log plot format (usually for

Neutron and Density).Crossplots

Graphical x-y plots which predict porosity and lithology on the basis of the location of datapoints with respect to pure lithology reference data. The plots may also contain data inthe z-axis.

Algorithmic calculation techniques are derived from these plots.



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Combo 2Porosity


Neutron-Density Quicklook method

shale

limestone

limestone

dolomite

shale

sandstone

sandstone

anhydrite

coal

salt

limy dolomite

sandy limestone

dolomitic sand

shale

shale

shale

shale

shale

limestone

limestone

dolomite

shale

sandstone

sandstone

anhydrite

coal

salt

limy dolomite

sandy limestone

dolomitic sand

shale

shale

shale

shale



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Combo 3Porosity


Neutron-Density Quicklook method Approach:

Compare the positions of the curves with respect to each other, as well as with respect tothe track.

Assumptions:

The Neutron and Density porosities are calculated with respect to limestone.

The Neutron porosity is recorded on a limestone matrix.

The Density porosity is calculated with a matrix density of 2.71 g/cm 3, or scaledto approximate the Neutron porosity scale.

The formation fluid is either water or oil, but NOT gas.

ResponsesLithology Porosity Neutron-Density response Pe response

Shale -- Neutron greater than Density by some variable amountdepending on the shale composition and depth.

Variable, butabout 3.

Limestone 0.05 Neutron and Density values overlay. About 5.

Limestone 0.15 Neutron and Density values overlay. About 5.

Dolomite 0.10 Neutron values greater than Density by 12 to 14porosity units (0.12 to 0.14).

About 3.

Shale -- As described in the Shale section above. As above.

Sandstone 0.26 Neutron values less than Density (crossover) by 6 to 8porosity units.

2 or slightlyless.

Sandstone 0.05 Neutron values less than Density (crossover) by 6 to 8porosity units.

2 or slightlyless.

Anhydrite -- Neutron porosity greater than Density by 14 porosityunits or more. Neutron porosity near zero. About 5.


Salt -- Neutron porosity slightly negative. Density porosity >40porosity units (bulk density near 2.0). Check the caliperfor bad hole and bad density data.

About 4.7.


Coal -- Responses variable depending on coal composition.High Neutron and Density porosities (low bulk density).

Less than 1.


Limy

Dolomite

0.10 Variable response with lithologic mix, but Neutron

generally greater than Density.

3 to 5.

SandyLImestone

0.10 Variable response with lithologic mix, but Neutrongenerally less than Density.

2 to 3.

DolomiticSand

0.10 Highly variable, with Neutron greater or less thanDensity, depending on the lithologic mix.

2 to 5.




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Combo 4Porosity


Neutron-Density Quicklook: sandstone

shale

salt

shale

shaly gas sand

shaly oil sand

shaly wet sand

clean wet sand

shale

shale

shale

dolomite

limestone

clean wet sand

shale

salt

shale

shaly gas sand

shaly oil sand

shaly wet sand

clean wet sand

shale

shale

shale

dolomite

limestone

clean wet sand

In this example, the Neutron and Density are displayed with respect to a sandstone matrix (matrixdensity = 2.65 g/cm3).

Note the Neutron-Density crossover in the limestone zone.



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Combo 7Porosity


Neutron-Sonic Crossplot

1994 Halliburton

Porosity is relatively invariant with lithologic assumptions (quartz-dolomite or calcite-dolomite).

Historically the tools are not run in combination.

This may be useful if the hole is rough and the density values are questionable.



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Combo 8Porosity

Porosity CombinationsSpectral Density (bulk density-Pe) crossplot

1998 Schlumberger

Requires only one porosity tool (with two measurements).

Porosity varies significantly with the choice of the mineral pair.



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Combo 9Porosity


Density-Sonic crossplot

1994 Halliburton

Porosity and lithology estimates are subject to large errors.

This is a good plot for distinguishing hot, or radioactive, formations from shales. The potentiallyproductive formations will plot in the area of the lithology lines, while shales will plot generally inthe lower right quadrant of the plot.



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Combo 11Porosity


Three-Measurement CrossplotsMETHODOLOGY

The three crossplots in this section are interpreted in a similar manner. Given three porosity

measurements, a three-mineral matrix can be determined. Because the techniques are restrictedto a two-dimensional plot, intermediate quantities which collapse the three measurements to twoaxes are calculated and plotted.

The older M-N plot used sonic, density, and neutron values to calculate M (a function of sonic anddensity) and N (a function of neutron and density).

Newer techniques, and the addition of an additional measurement, photoelectric effect (Pe orPEF), derive apparent matrix values. Apparent matrix density, Rhomaa (a function of densityand neutron) is plotted against apparent matrix sonic traveltime, DTmaa (a function of sonic andneutron). Apparent matrix density is also plotted against apparent matrix photoelectric crosssection, Umaa (a function of density, neutron, and photoelectric effect).

In these techniques, any three mineral points are plotted as the vertices of a triangle. Therelationship of a plotted apparent matrix point to the triangle determines the components of theformation represented by the point.



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Combo 12Porosity


M-N plots

1998 Schlumberger

01.0!

"

"#

fluid

fluid

Rho RHOB

DT DT M

fluid

N Nfluid

Rho RHOB N

"

"#

$ $

There is a dependence of the technique on salinity, matrix travel time, and porosity range.

Older Baker Atlas (then Dresser Atlas) literature showed a similar technique called A-K plots.



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Combo 13Porosity


Preliminary charts for the Neutron-Density-Sonic MID plotTo use the plot, apparent matrix density and apparent matrix traveltime must first be calculated.

This is a Neutron-Density crossplot, focusedon the lithologic response of themeasurements, and ignoring the porosityresponse.

Apparent matrix density is derived from thisplot.

1994 Halliburton

This is a Neutron-Sonic crossplot,focused on the lithologic response ofthe measurements, and ignoring theporosity response.

Apparent matrix traveltime is derivedfrom this plot.

1994 Halliburton



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Combo 14Porosity


Neutron-Density-Sonic MID Plot

1994 Halliburton

A three-mineral matrix model is assumed. Any three minerals that have unique locations on the

plot with respect to the other two minerals can be used. The proximity to the mineral endpointsindicate increased amounts of that mineral.



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Combo 16Porosity


Neutron-Spectral Density MID Plot

1994 Halliburton

A three-mineral matrix model is assumed. Any three minerals that have unique locations on theplot with respect to the other two minerals can be used. The proximity to the mineral endpointsindicate increased amounts of that mineral.



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Combo 17Porosity


Three-mineral crossplots: SummaryTechnique Notes Comments

M-N Lithology M = f(DT, RHOB)

N = f( $N, RHOB)

M and N here are different from, and

should not be confused with, the m and nexponents in Archies equation.

The location of the mineral points on theplot depends on mud salinity, matrixtraveltime, and the porosity range.

This is the oldest of the three-mineraltechniques, and is probably the leastdesirable to use.

Neutron-Density-SonicMID plot

RhoMa app =

f(RHOB, $N, $Total )

DTMa app =

f(DT, $N, $Total )

The mineral triangle for the sandstone-limestone-dolomite group is narrow.

Neutron-Spectral DensityMID plot

RhoMa app =

f(RHOB, $N, $Total )

UMa app =

f(Pe, RHOB, $Total )

Requires only Neutron and Spectral Densitytools.

Sensitive to rough hole data problems.

Large mineral triangle for the sandstone-limestone-dolomite group.



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Combo 18Porosity


Beyond three mineralsSolution of a problem with more than three minerals is beyond the scope of graphical solutions.

The technique shown below solves for 4 minerals (in this case, quartz, calcite, dolomite, andanhydrite) plus shale, and also estimates water saturation.

Solid component volumes

Fluid component volumes

Solid component volumes

Fluid component volumes



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Resistivity

Resistivity

This section addresses three categories of resistivity measurements; Induction logs ,Laterologs , and Microresistivity (Rxo) measurements. The induction and laterologsboth attempt to measure the resistivity of the undisturbed part of the formation, laterallydistant from the borehole. The measurements achieve the same goal through differentphysics of the measurements.

The microresistivity measurements for the most part use the same physics as thelaterologs, but are designed to measure the resistivity of the formation very close to theborehole, in the zone that has been flushed by the drilling fluid.

Both measurements (as well as some measurements of intermediate lateral distance)are useful; their use in concert provides a better estimate of undisturbed (true)formation resistivity, and also provides a qualitative estimate of formation producibility.



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IL 1Resistivity

Induction

Interpretation GoalsTrue (undisturbed) formation resistivity, R t.

Fluid saturation, S w, via Archie's Equation.

Geopressure (overpressure) detection.Diameter of invasion.Correlation.



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IND 2Resistivity

Induction

Tool DiagramHalliburton array induction log (HRI).

1999 Halliburton

Physics of the MeasurementTransmitter coils induce an alternating current inthe formation. Receiver coils sense the responseof the formation, both in magnitude and phase.This response is proportional to the formationconductivity (the inverse of resistivity). Multipletransmitter and receiver coils are used in an effortto minimize borehole and invasion effects on thetool. Newer versions of the tool make better, anddigitally recorded, measurements of the in-phaseand out-of-phase parts of the signal, and operate atdifferent frequencies, in order to improve theaccuracy of the tool. Accuracy is further enhancedby environmental corrections done in real time.Array tools have many receivers, usually at smallspacings, and rely on signal processing to create acommon vertical resolution for all measurements.


Resolution90% *

Radius ofInvestigation

50%

Precision(+-)

Deep 24 in. 91 in. 0.25mmho

Medium 24 in. 39 in. 0.25mmho

Shallow


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IND 3Resistivity

Induction

Measurement NamesMeasurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may nolonger be available, or are obsolete.WI

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