Guide to Petrophysical Interpretation

Guide to Petrophysical Interpretation Daniel A. Krygowski Austin Texas USA

This Guide contains references to, and specifically lists, trademarks and service marks of the following companies, their subsidiaries, and/or their parent companies: Baker Hughes, 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.

© 1995, 2000, 2003 Daniel A. Krygowski All rights reserved. No part of this Guide shall be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or by any information 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 from copying. Users may copy this file from the original compact disk to the hard drive of the computers on which they are the primary users. Making copies for purposes beyond those of personal reference is not permitted.

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

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 short courses, especially the basic well logging course taught by Dr. George Asquith and myself under the sponsorship of the AAPG. It is meant to be a quick guide or a memory aid to those needing to interpret well log data (wireline or MWD), and a starting point for more detailed study when needed. The document is a summary of each common openhole petrophysical measurement; the interpretation goals and details, a brief explanation of the physics and operating constraints, and some of the nomenclature related to each measurement. The measurements are listed below, and are those that have been traditionally used to determine formation lithology, porosity, and fluid saturation. The measurements are arranged by interpretation goal, rather than by tool physics, so that the user can more readily compare the interpretation methodologies of measurements that are focused on a common goal, such as the determination of porosity. In addition, there is a section on openhole log interpretation that is again meant as a general guide, not as an exhaustive study of all interpretation techniques. The measurements/topics covered here are: Correlation/Lithology Spontaneous Potential (SP) Gamma Ray Caliper Porosity Sonic/Acoustic Density Neutron Porosity Measurement Combinations Resistivity Induction Logs Laterologs Microresistivity (Rxo) Logs Openhole Log Interpretation An Annotated Bibliography is included to guide the user to more complete reference material.

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

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 in an “API standard” (three data tracks) display. While the Gamma Ray and Spontaneous Potential (SP) are often used for correlation, they are also useful for the determination of gross formation lithology (reservoir vs. non-reservoir). In addition, both can be used to determine the shaly sand calculation parameter Shale Volume (Vshale), and the SP can be used to determine formation water resistivity, Rw. The Caliper measurement determines hole size, which can be an indicator of the quality of other logging measurements, and which is used in some of the corrections made to those measurements to account for changes in the borehole environment.

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

SP 1 Correlation/Lithology

Spontaneous Potential Interpretation Goals Correlation of formations from well to well. Gross lithology (reservoir vs. non-reservoir). Estimate of formation water resistivity, Rw. Estimate of shale (clay) content. Qualitative indication of permeability. Identification of depositional environments.

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

SP 2 Correlation/Lithology

Spontaneous Potential Tool Diagram Halliburton array induction (HRAI) showing the SP electrode (“SP band”).

Physics of the Measurement The SP is a passive measurement of very small electrical voltages resulting from electrical currents in the borehole caused by the differences in the salinities (resistivities) of the formation connate water (Rw) and the drilling mud filtrate (Rmf), and by the presence of ion selective shale beds. The voltage changes are measured by a downhole electrode relative to a surface ground. Unlike other logging tools which are displayed on a specific scale with a specified reference value, the SP has no specified origin and values used for computation are referenced to deflection from the nearby shale baseline 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 least understood measurements, in terms of basic physical principles of operation.

Volume of Investigation

SP

Vertical Resolution (feet)

Radius of Investigation

Precision (+-)

1/porosity

shallow

1mV

Operational Constraints The 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 mud

© 2000 Halliburton

Logging speed: The logging speed is constrained by other measurements in the toolstring. Comments: Usually run with induction logs and old electric logs, the SP can also be run with laterologs, sonics, micrologs, dipmeters, and sidewall cores. There usually is no separate "SP tool".

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

SP 3 Correlation/Lithology

Spontaneous Potential Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Baker Atlas Spontaneous Potential Computalog Spontaneous Potential Halliburton Spontaneous Potential Gearhart Spontaneous Potential, SP Welex Spontaneous Potential, SP Reeves Wireline Spontaneous Potential Schlumberger Spontaneous Potential Tucker Wireline Spontaneous Potential MWD/LWD There are no MWD/LWD SP measurements

Mnemonic SP SP SP

SP SP SP Mnemonic

Curves Displayed (Curves are listed by generic name, common mnemonics (if any) and measurement units.) Curve Name Spontaneous Potential

Mnemonics SP

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

Units of Measurement mV

SP 4 Correlation/Lithology

Spontaneous Potential Log Example

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

SP 5 Correlation/Lithology

Spontaneous Potential Interpretation Details CORRELATION OF FORMATIONS Curves are scanned for similarities in shape and magnitude.

GROSS LITHOLOGY Reservoirs are shown as deflections (either positive or negative) from a relatively stable (and arbitrary) shale baseline. The direction of the deflection is determined by the relative salinities (resistivities) of the formation water (Rw) and the mud filtrate (Rmf), and is not directly related to formation porosity or permeability. As a rule of thumb the following relationships are true: If Rmf > Rw, then the SP deflection is negative. If Rmf = Rw, then the SP deflection is zero. If Rmf < Rw, then the SP deflection is positive.

ESTIMATE OF FORMATION WATER RESISTIVITY (Rw) SP response equation:  R mfe SP = − K ⋅ log  R we

   

SP = Spontaneous Potential (from the log) K = temperature-dependent factor (K=61+ 0.133*T; T in °F). Rmfe = equivalent mud filtrate resistivity. Rwe = equivalent formation water resistivity. The magnitude of the SP is measured from the shale baseline near the zone of interest. The baseline is usually assumed to have a value of zero. "Equivalent" resistivities are required to correct for the non-linear relationship between resistivity and ionic activity which exists at high NaCl 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: R w = 10

(K ⋅log(Rmf )+ SP ) / K where Rmf is corrected to formation temperature.

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

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

SP 6 Correlation/Lithology

Spontaneous Potential ESTIMATE OF SHALE (CLAY) CONTENT Shale/clay volume equation:  SPclean − SPlog Vclay = V shale =   SPclean − SPshale

   

Vclay = Vshale = Shale or clay volume. SPlog = SP in the zone of interest (read from the log). SPclean = maximum SP deflection from a nearby clean wet zone in the same well. SPshale = SP value at the shale baseline (often considered to be zero). This method assumes a constant Rw for all zones considered. It also assumes that the response of the SP to shaliness is linear. The terms “shale” and “clay” are used almost interchangeably in log analysis techniques, even though the understanding of the difference between shale and clay have matured since the development of the techniques.

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

IDENTIFICATION OF DEPOSITIONAL ENVIRONMENTS Depositional 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. Depositional environment interpretation will work best if data from several wells are used to create a threedimensional 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 in values of Rmf from well to well or the presence of hydrocarbons, can produce the same effects on the 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 for Rmf differences.

COMPARISON OF SP BETWEEN WELLS When 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 has no 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, Rmf, in different wells.

o

The presence of hydrocarbons in one of the wells,

o

A change in the formation water resistivity, Rw.

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

SP 7 Correlation/Lithology

Spontaneous Potential Secondary Effects ENVIRONMENTAL EFFECTS Shale: The presence of shale in the formation will cause a smaller deflection (either positive or negative) from the shale baseline than in an equivalent clean formation. The response is assumed to be linear. Hydrocarbons: Oil or gas in the formation will cause a smaller deflection from the shale baseline than 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, electrical storms, 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 the formation and the borehole. This phenomenon will appear as excessive SP values beyond that anticipated from the Rmf/Rw contrast. This is a rare phenomenon. Baseline drift: The gradual change in SP baseline (that is, the value of the SP in shales), either positive or negative, with depth. Many possible environmental and equipment factors can contribute to this phenomenon which must be recognized during the interpretation. The causes of 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 can be 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 by any physical phenomena. Positioning of the baseline is done for aesthetic reasons (and ease of reading the curve) rather than as part of calibration to a universal standard.

INTERPRETATION EFFECTS Hydrocarbons and/or shale (clay) in the formation will cause the calculated Rw to be higher than the actual formation water resistivity; this will cause the water saturation, Sw, calculated from Archie's Equation to also be higher than the actual formation water saturation.

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

SP 8 Correlation/Lithology

Spontaneous Potential Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control The 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 previous runs 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.

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

SP 9 Correlation/Lithology

Spontaneous Potential PROCEDURE FOR DETERMINATION OF Rw FROM THE SP Taken from the procedure outlined in Schlumberger chartbooks. Use the Log Example in this section. 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 chart Gen-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:  BHT − AMST  FT =  ⋅ FD  + AMST TD  

4: Convert Rmf from surface temperature to formation temperature (use Schlumberger chart Gen9 with Rmf at measured temperature from the log heading). Rmf = _______ohm-m @ ________°F (measured temperature) Rmf = _______ohm-m @ ________°F (formation temperature). The following equation (Arps equation) can also be used: R FM =

RTk (Tk + 6.77 ) (TFM + 6.77 )

RFM = fluid resistivity at formation temperature TFM (in °F). RTk = known resistivity at a known temperature, Tk. Tk = known temperature (in °F). 5: Convert Rmf at formation temperature to Rmfeq using one of the following: a: If Rmf @ 75 °F > 0.1 ohm-m, use Rmfeq = 0.85•Rmf. b: If Rmf @ 75 °F < 0.1 ohm-m, use Schlumberger chart SP-2. (a and b are included on Chart SP-1 of the Schlumberger chartbook). Rmfeq = ______ohm-m @ ________°F (formation temperature). 6: Using SP, formation temperature, and Rmfeq, enter Schlumberger chart SP-1 to find Rweq. Rweq = _______ohm-m @ _________°F (formation temperature). The following equation can also be used:

R weq = 10

(K ⋅log (Rmfsq )+ SP ) / K

7: Convert Rweq to Rw using Schlumberger chart SP-2. Rw = _______ohm-m @ ________°F (formation temperature).

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

SP 10 Correlation/Lithology

Spontaneous Potential PROCEDURE FOR DETERMINATION OF Rw FROM THE SP: Taken from the procedure outlined in Western Atlas chartbooks. Use the Log Example in this section. 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 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:  BHT − AMST  FT =  ⋅ FD  + AMST TD  

4: Convert Rmf from surface temperature to formation temperature (use Atlas chart 1-5 with Rmf at measured temperature from the log heading). Rmf = _______ohm-m @ ________°F (measured temperature) Rmf = _______ohm-m @ ________°F (formation temperature). The following equation (Arps equation) can also be used: R FM =

RTk (Tk + 6.77 ) (TFM + 6.77 )

RFM = fluid resistivity at formation temperature TFM (in °F). RTk = known resistivity at a known temperature, Tk. Tk = known temperature (in °F). 5: Using SP, formation temperature, and Rmf, use Atlas chart 2-2 to find Rweq. Rweq = _______ohm-m @ _________°F (formation temperature). The following equation can also be used: R weq = R mfeq ⋅10 SP / (61+ 0.133⋅BHT )

6: Convert Rweq to Rw using Atlas chart 2-3. Rw = _______ohm-m @ ________°F (formation temperature). The following equation can also be used: R weq + 0.131 ⋅10 [1 / log (BHT / 19.9 )]− 2.0 Rw = − 0.5 ⋅ R weq + 10 [0.0426⋅log (BHT / 50.8 )]

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

SP 11 Correlation/Lithology

Spontaneous Potential PROCEDURE FOR DETERMINATION OF Rw FROM THE SP: ANSWER Taken from the procedure outlined in Schlumberger chartbooks. Use the Log Example in this section. 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_ feet Formation depth (FD) = _10,317_ feet Bottom hole temperature (BHT) = _175__ °F Formation temperature (FT) = __168__ °F Annual Mean Surface Temperature (AMST) = __80__°F

 175 − 80   BHT − AMST  FT =  ⋅ FD  + AMST =   + 80 = 168 TD    11,196  (Schlumberger chart Gen-6, with total depth and maximum temperature from the log heading, can be used in place of the above equation.) 4: Convert Rmf from surface temperature to formation temperature using the “Arps equation” below. Rmf = __0.58__ohm-m @ ___70___°F (measured temperature) Rmf = __0.26__ohm-m @ __168___°F (formation temperature).

R FM =

RTk (Tk + 6.77 ) 0.58 ⋅ (70 + 6.77 ) = = 0.26 (TFM + 6.77 ) (168 + 6.77 )

RFM = fluid resistivity at formation temperature TFM (in °F). RTk = known resistivity at a known temperature, Tk. Tk = known temperature (in °F). (Schlumberger chart Gen-9, with Rmf at measured temperature from the log heading, can be used in place of the above equation.) 5: Calculate the SP factor, K:

K = 61 + 0.133 ⋅ FT = 61 + 0.133 ⋅ 168 = 83.3 6: Using SP, formation temperature, and Rmf, calculate Rw from the equation below. Rw = __0.023__ohm-m @ ___168___°F (formation temperature).

R w = 10

(K ⋅log(Rmf )+ SP ) / K

= 10 (83.3⋅log (0.26 )+ ( −87 ) ) / 83.3 = 0.023

(Schlumberger chart SP-1 can be used in place of the above equation to find Rw.) Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA

GR 1 Correlation/Lithology

Gamma Ray Interpretation Goals Correlation of formations. Gross lithology. Estimate of shale (clay) content. Clay typing. Fracture identification. Source rock identification.

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

GR 2 Correlation/Lithology

Gamma Ray Tool Diagram

Physics of the Measurement

Halliburton spectral gamma ray tool (CSNG)

The number of naturally occurring gamma rays, from potassium, uranium, thorium, and associated daughter products, is counted by the detector in both natural gamma ray and spectral gamma ray tools. Spectral tools also measure the energy of each detected gamma ray. The range, or spectrum, of energy detected is divided into windows, or limited energy ranges, which indicate the elemental gamma ray source (i.e., the specified isotopes of potassium, uranium, or thorium).

Volume of Investigation

Gamma Ray Spectral Gamma Ray

Vertical Resolution 90%

Radius of Investigation50%

Precision (+-)

18-36 in. 12in.* 18-36 in. 12in.*

4 in. 11 in.@90% 4 in. 11 in.@90%

4 API units 5 API Units

* with enhanced resolution processing

Operational Constraints The 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 mud Logging speed: For standard gamma ray measurements, the logging speed is constrained by the other measurements in the toolstring. For “spectral” gamma ray , 10 feet/minute. Comments:

© 1999 Halliburton

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

GR 3 Correlation/Lithology

Gamma Ray Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Mnemonic Baker Atlas Gamma Ray GR Spectralog SL Computalog Gamma Ray GR Spectral Gamma Ray SGR Halliburton Gamma Ray GR Compensated Spectral Natural Gamma Ray CSNG Natural 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 Wireline Compact Gamma Ray MCG, MGS Spectral Gamma Sonde Schlumberger Integrated Porosity Lithology IPL Platform Express *Gamma Ray, GR; *Natural Gamma Ray Spectrometry Log, NGS, NGT Tucker Wireline Gamma Ray Tool GRT MWD/LWD Mnemonic Baker Hughes INTEQ Directional-Gamma DG Resistivity-Gamma-Directional RGD Exlog *Gamma Ray, DLWD component Teleco *Gamma Ray, DG, DDG, RGD, ReGD component Pathfinder Directional Gamma Ray HDS1 Resistivity Gamma Ray CWRD Schlumberger LWD (Anadrill) Vision 475 *Gamma Ray; *Resistivity at Bit, RAB (focused gamma ray) Sperry Sun DGR Sensors DGR MWD 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 Gamma Ray, Total Gamma Ray Uranium-Free Gamma Ray Potassium Uranium Thorium

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

Mnemonics GR GRS, SGR, KTH POTA, K URAN, U THOR, TH

Units of Measurement API Units API Units Percent ppm ppm

GR 4 Correlation/Lithology

Gamma Ray Log Example

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

GR 5 Correlation/Lithology

Gamma Ray Interpretation Details CORRELATION OF FORMATIONS Curves are scanned for similarities in shape and magnitude.

GROSS LITHOLOGY In general, reservoirs are less radioactive than shales. However, some sandstones and dolomites can be radioactive.

ESTIMATE OF SHALE (CLAY) CONTENT The magnitude of the gamma ray in the formation of interest (relative to that of nearby clean and shale zones) is related to the shale content of the formation. The relationship between gamma ray magnitude and shale content may be linear or non-linear. The relationships are all empirical. Gamma Ray Index, IGR:

I GR =

GRlog − GRclean GRshale − GRclean IGR describes a linear response to shaliness or clay content. GRlog = log reading at the depth of interest GRclean = Gamma Ray value in a nearby clean zone GRshale = Gamma Ray value in a nearby shale

Linear Gamma Ray - clay volume relationship: Vshale = IGR Non-linear Gamma Ray - clay volume relationships: Steiber:

V shale = Clavier:

I GR 3.0 − 2.0 ⋅ I GR

[

V shale = 1.7 ⋅ 3.38 ⋅ (I GR + 0.7 ) Larionov (Tertiary rocks):

(

]

2 0.5

)

V shale = 0.083 ⋅ 2 3.7⋅I GR − 1 Larionov (older rocks):

[(

)

V shale = 0.33 ⋅ 2 2⋅I GR − 1.0

]

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

GR 6 Correlation/Lithology

Gamma Ray All the above relationships are empirical. The choice of which to use is up to the user, and depends on other information that may be available. If no other information is known, the linear relationship is probably the best choice, although it is the most pessimistic (that is, it predicts the most 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 reading and the clean and shale values. The terms “shale” and “clay” are used almost interchangeably in log analysis techniques, even though the understanding of the difference between shale and clay have matured since the development of the techniques.

* CLAY TYPING The method involves plotting the potassium responses against those of thorium which will give some indication of the type of clay present in the formation. This technique assumes the presence of pure clays, which rarely exist in reservoirs. Because of its limitations, this technique is 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 clays and the gamma rays resulting from uranium which are not necessarily associated with clays.

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

* SOURCE ROCK IDENTIFICATION Consistently 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.

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

GR 7 Correlation/Lithology

Gamma Ray Secondary Effects ENVIRONMENTAL EFFECTS Hole 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 muds affect all count rates. Logging Speed: In older logs, the logging speed may cause some variation in the response, with logs acquired at a faster speed having somewhat less definition and activity than those acquired at slower speeds.

INTERPRETATION EFFECTS Sandstones and dolomites may occasionally be radioactive and respond as shales. A DensitySonic crossplot may help to distinguish radioactive ("hot") reservoirs from shales.

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

GR 8 Correlation/Lithology

Gamma Ray Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control The 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 previous runs or repeat sections. Cross-check the curve character with other curves from the same logging run.

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

CAL 1 Correlation/Lithology

Caliper Interpretation Goals Indication of hole diameter and volume. Input for environmental corrections for other measurements. Qualitative indication of permeability. Correlation. Log quality control.

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

CAL 2 Correlation/Lithology

Caliper Tool Diagram

Physics of the Measurement

Halliburton 4-arm caliper tool (FACT).

For wireline tools, the physical movement of arms on the tool is converted to a diameter measurement through electrical circuitry. The arms are intended to either keep the tool centered in the borehole, or to push the tool against the borehole wall. Some MWD tools generate a caliper curve based on the differences in the response of the detectors as the tool rotates. Other tools use ultrasonic sensors to generate a caliper by measuring the time taken for an acoustic pulse to travel from the sensor to the formation wall and back.

Volume of Investigation Vertical Resolution

Depth of Investigation

Precision

Not defined

None

Not defined

Caliper

Operational Constraints The tool can be run: open hole

centered1

cased hole

eccentered1

In a borehole fluid of: gas or air water or water-based mud oil or oil-based mud

© 1999 Halliburton

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

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

CAL 3 Correlation/Lithology

Caliper Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Baker Atlas Caliper *4-Arm Dual Caliper, *4CAL; *Multi Finger Caliper, MFC Computalog Caliper Dual Axis Calipers Multi Sensor Caliper Halliburton Caliper *Four Arm Caliper Tool, FACT; *Four Independent Arm Caliper, FIAC Gearhart *Caliper, CL; *X-Y Caliper Welex *Caliper, CL Reeves Wireline Two Arm Caliper Compact Two Arm Caliper *Caliper, CAL; *Four Arm Caliper, FAC Schlumberger Environmental Measurement Sonde *Caliper, CAL; *Borehole Geometry Tool, BGT Tucker Wireline Centralizer Caliper Tool XY Caliper Tool MWD/LWD Baker Hughes INTEQ Caliper Corrected Neutron Exlog (none) Teleco (none) Pathfinder Density Neutron Caliper Density Neutron Standoff Caliper Tool Schlumberger LWD (Anadrill) *Compensated Density Neutron, CDN (Downhole Sonic Caliper) Sperry Sun Acousticaliper MWD tool

Mnemonic CAL

DAC MSC CL

TAC MCT EMS

CCT XYT Mnemonic CCN

DNSC DSNCM

Curves Displayed (Curves are listed by generic name, common mnemonics (if any) and measurement units.) Curve Name Caliper

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

Mnemonics CAL, CALI

Units of Measurement Inches, cm

CAL 4 Correlation/Lithology

Caliper Log Example

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

CAL 5 Correlation/Lithology

Caliper Interpretation Details INDICATION 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 the length of the long and short axis. One arm or two arm calipers will tend to be more sensitive than three-arm calipers. Calipers which show diameter in two orthogonal directions will show holes which have become elongated. Hole volume is computed by integrating the hole volume calculated at each depth sample. The hole is assumed to be circular for a single diameter measurement, and assumed elliptical for a two dimensional measurement.

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

QUALITATIVE INDICATION OF PERMEABILITY The existence of mudcake (when the borehole diameter is less than the bit size) is an indication of the infiltration of mud into the formation. Because of differences in mud type, density, and other parameters, the magnitude of permeability cannot be determined. Mudcake is usually noted as a comparison to bit size. When the hole is washed out, the presence of mudcake can be masked by the washout.

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

LOG QUALITY CONTROL Indications from the Caliper that the hole is rough is a warning that measurements which are from tools pressed against the borehole wall, such as Density, Neutron, and the microresistivity curves, may not be reliable.

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

CAL 6 Correlation/Lithology

Caliper Secondary Effects ENVIRONMENTAL EFFECTS 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 EFFECTS Occasionally, mud cake indications can be masked by a washed out borehole.

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

CAL 7 Correlation/Lithology

Caliper Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control Check the caliper value in casing against the casing diameter. Shale values should be similar to those in nearby wells. Check repeatability; curves should have the same values and character as those from previous runs or repeat sections. Cross-check the curve character with other curves from the same logging run.

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

Porosity

Porosity This section contains information about the three common porosity measurements; Sonic/Acoustic, Density, and Neutron. Although called “porosity” measurements, none of the logging tools actually measure porosity directly. It is this indirectness that leads, in part, to the interpretation of the measurements in pairs or in triads. The Porosity Combination part of this section details the interpretations that produce better estimates of porosity, and as a by-product, estimates of formation lithology.

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

SON 1 Porosity

Sonic/Acoustic Interpretation Goals Porosity (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).

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

SON 2 Porosity

Sonic/Acoustic Tool Diagram

Physics of the Measurement

Halliburton Full Wave Sonic tool (FWST) in its long-spaced configuration.

A high frequency (10’s of KHz) acoustic pulse from a 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 an interval transit time called delta t (∆t orDT). The delta t is the transit time of the wave front over one foot of formation. If the entire acoustic waveform is captured, arrival times and attenuations (energy decrease) of several portions of the waveform can be measured including: compressional (the standard delta t), shear, and Stoneley. “Compensated” tools use multiple transmitterreceiver pairs to minimize the effects of borehole size changes. “Array” or similarly named tools usually have 4 or more receivers, and the data from all receivers is processed to determine arrival times. Some tools are designed specifically for shear wave measurements.

Volume of Investigation Vertical Resolution 90%

Radius of Investigation50%

Precision (+-)

12 in.*

~6 in.

1 usec/ft

DT

*depends on receiver spacing

Operational Constraints The tool can be run: open hole

centered1

cased hole

eccentered1

In a borehole fluid of: gas or air water or water-based mud oil or oil-based mud

© 2000 Halliburton

Logging speed: 60 feet/minute. “Array” or “full wave” tools may require slower logging speeds. Comments: 1 To minimize signal attenuation, the tool should be run centered in holes smaller than 16 inches, and eccentered in holes larger than 16 inches. The tool should always have some standoff in order to reduce road noise.

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

SON 3 Porosity

Sonic/Acoustic Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Mnemonic Baker Atlas Acoustic Properties Explorert APX Cross-Multipole Array Acoustic XMAC Borehole Compensated Acoustilog DAL, AC *Long Spaced BHC Acoustic, ACL; *Multiple Array Acoustilog, MAC; *Digital Array Acoustilog, DAC Computalog Borehole Compensated Sonic BCS Digital Acoustic Array DAR High resolution sonic logs (BCS variants) Long Spaced Sonic, LSS; Sonic Signature Log, SSL Halliburton Full Wave Sonic FWS Multipole 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 Wireline Compensated Sonic Sonde CSS Long Spaced Compensated Sonic Sonde LCS Compact Sonic Sonde MSS Ultrasonic Gase Detector UGD *Sonic Waveform, SW Schlumberger Dipole Shear Sonic Imager DSI *Borehole Compensated Sonic Log, BHC; *Long Spaced Sonic, LSS; *Array-Sonic Tucker Wireline Compensated Sonic Tool CST Long Spaced Sonic Tool LST MWD/LWD Mnemonic Baker Hughes INTEQ No information available. Exlog *(none) Teleco *(none) Pathfinder Density Neutron Caliper DNSC Schlumberger LWD (Anadrill) IDEAL Sonic-While-Drilling Tool ISONIC Sperry Sun Bi-Modal Acoustic Tool BAT

Curves Displayed (Curves are listed by generic name, common mnemonics (if any) and measurement units.) Curve Name Interval transit time, travel time (for compressional, shear, and/or Stoneley waves)

Mnemonics

Units of Measurement

DT, ∆t

usec/ft, usec/m

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

SON 4 Porosity

Sonic/Acoustic Log Example

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

SON 5 Porosity

Sonic/Acoustic Waveform display

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

SON 6 Porosity

Sonic/Acoustic Variable density display

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

SON 7 Porosity

Sonic/Acoustic Interpretation Details CHARACTERISTIC VALUES:

Sandstone Limestone Dolomite Anhydrite Halite Coal Steel Gas Oil

Matrix Value (Wyllie) DTMa 51.3 to 55.6 168 to 182 43.5 to 47.6 143 to 156 38.5 to 43.5 126 to 143 50 164 67 220 >100 >328 57 187

Matrix Value (Raymer-Hunt-Gardner)) DTMa 56 184 49 161 44 144 50 164 67 220 >100 >328 57 187

Water Units

usec/ft

usec/m

usec/ft

usec/m

Fluid Value DTFl

920 230 179 to 208 (189) usec/ft

3018 755 587 to 682 (620) usec/m

POROSITY Wyllie Time-Average Equation:

SPHI = φ S =

∆t − ∆t ma DT − DTMa 1 1 • • = DTFl − DTMa Bcp ∆t fl − ∆t ma Bcp

SPHI = φS= sonic (acoustic) porosity DT = ∆t = sonic travel time (from the log) DTMa = ∆tma = matrix travel time DTFl = ∆tfl = fluid travel time Bcp = compaction correction, where

Bcp =

DTShale ≥ 1 .0 100

The Bcp factor was added to the equation when it was found that the equation gave highly optimistic porosity values in unconsolidated sands. DTShale is picked from a shale near the zone of interest. The correction factor is never less than 1.0. Raymer-Hunt-Gardner Equation (Schlumberger “Empirical Relation”):

SPHI = φ S =

5 DT − DTMa 5 ∆t − ∆t ma • = • DT ∆t 8 8

SPHI = φS= 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.

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

SON 8 Porosity

Sonic/Acoustic Like the Wyllie equation, Raymer-Hunt-Gardner is based on empirical data. It is non-linear in form, resulting in lower porosities than Wyllie for high DT, as in uncompacted sands. No compaction correction is needed. The choice of which equation to use depends on the interpreter. If other porosity information is available, 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). Since the Sonic log "sees" the formation close to the borehole, the fluid is assumed to be the drilling mud filtrate. The formation fluid traveltime, DTFl, varies somewhat with the salinity of the formation, but is usually assumed to be 189 usec/ft.

LITHOLOGY IDENTIFICATION Lithology is determined by comparison of delta t with Neutron and Density data in crossplots, in Matrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tool type, Sonic response equation type, and by service company. The ratio of shear to compressional DT may also be an indicator of gross lithology.

SYNTHETIC SEISMOGRAMS Sonic compressional and Density data are used to determine acoustic impedance of the formations along the borehole, and reflection coefficients at bed boundaries. The synthetic seismic trace that is derived from that information can be displayed in depth or time to be compared to the seismic data. The logs can also be modeled with varying fluid properties (and sometimes also with varying porosity), and synthetics calculated from the modeled curves, to help determine the response of the seismic data to the subsurface.

FORMATION MECHANICAL PROPERTIES Compressional and shear sonic data are used with density data to calculate formation properties such 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 while drilling to ensure borehole stability. Information on relative formation strengths supports the design of hydraulic fracturing so that fractures remain in the target formations instead of extending to adjacent formations. Formation strength can also support predictions of drawdown pressures so that sand-free production can be maintained when a well is completed and produced.

DETECTION OF ABNORMAL FORMATION PRESSURES Sonic 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.

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

SON 9 Porosity

Sonic/Acoustic CEMENT BOND QUALITY Using specialized tools, the quality of the cement bond (cement to pipe and cement to formation) can be deduced by the attenuation of the acoustic signal. Essentially, the better the bonding, the more attenuation of the signal.

BOREHOLE SIZE The hole size is produced by a caliper measurement associated with the centralizing equipment on the tool. Movement of the centralizer arms as changes in hole size are encountered are translated to a hole diameter and r

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

SON 10 Porosity

Sonic/Acoustic Secondary Effects ENVIRONMENTAL EFFECTS 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 higher values. Improper centralization, the lack of standoff, or excessive logging speed can result in "road noise", or DT spikes to either higher or lower values.

INTERPRETATION EFFECTS Lithology effects are manifested in the necessity to chose a matrix traveltime (DTMa) value in order to calculate porosity. Porosity calculations in uncompacted formations will yield porosity values higher than actual porosity when using the Wyllie equation. This can be accounted for through the use of the compaction 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 the traveltime in gas is higher than in water.

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

SON 11 Porosity

Sonic/Acoustic Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control There 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. Check repeatability; curves should have the same values and character as those from previous runs or repeat sections. Cross-check the curve character with other curves from the same logging run.

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

DEN 1 Porosity

Density Interpretation Goals Porosity (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).

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

DEN 2 Porosity

Density Tool Diagram

Physics of the Measurement

Halliburton spectral density tool (SDL).

High energy gamma rays are emitted from a chemical source (usually Cesium 137) and interact with the electrons of the elements in the formation. Two detectors in the tool count the number of returning gamma rays which are related to formation electron density. For most earth materials of interest, the electron density is related to formation bulk density through a constant. In newer spectral tools, the number of returning gamma rays at two different energy ranges are measured. The higher energy gamma rays (from Compton Scattering) determine bulk density, and therefore porosity, while the lower energy gamma rays (due to photoelectric effect) are used to determine formation lithology. The lower energy gamma rays are related to the lithology of the formation and show little dependence on porosity or fluid type.

Volume of Investigation Vertical Resolution 90%

Depth of Investigation50%

Precision (+-)

1.5 in.

0.01 g/cm3

0.5 in.

5%

33 in. 5.5 in.* 33 in. 2 in.*

Bulk density PE

*with enhanced resolution processing

Operational Constraints The tool can be run: open hole

centered

cased hole1

eccentered

In a borehole fluid of: gas or air water or water-based mud

© 2000 Halliburton

oil or oil-based mud Logging speed: 60 feet/minute. May require slower speeds for enhanced resolution processing. Comments: 1 Can be run in cased holes in special conditions.

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

DEN 3 Porosity

Density Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Baker Atlas Advantage Porosity Logging Service Compensated Z-Density Compensated Densilog Computalog Spectral Pe Density *Spectral Litho Density, SLD; *Compensated Density, CDL Halliburton Spectral Density Log Gearhart *Spectral Litho-Density, SDL; *Compensated Density Log, CDL Welex *Spectral Density, SDL; *Compensated Density Log, DEN Reeves Wireline Photo Density Sonde Compact PhotoDensity *Compensated Density, CDS Schlumberger Integrated Porosity Lithology *LithoDensity Log, LDT; *Compensated Formation Density Log, FDC Tucker Wireline Compensated Density Tool Lithology Density Tool MWD/LWD Baker Hughes INTEQ Optimized Rotational Density Modular Density/Lithology Exlog *(none) Teleco *Modular Density Porosity, MDP Pathfinder Density Neutron Standoff Caliper Tool Density Neutron Caliper Schlumberger LWD (Anadrill) Vision475 Sperry Sun Azimuthal Stabilized Litho Density MWD Triple Combo *Simultaneous Formation Density, SFD

Mnemonic APLS ZDL CDL SPeD SDL

PDS MPD

IPL CDT LDT ORD MDL

DNSCM DNSC

ASLD

Curves Displayed (Curves are listed by generic name, common mnemonics (if any) and measurement units.) Curve Name Bulk density Density porosity (referenced to a specific lithology) Density correction Photoelectric effect (lithology indicator) Caliper (hole diameter)

Mnemonics RHOB, DEN, ZDEN DPHI, PHID, DPOR DRHO PE, Pe, PEF CALI, CAL

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

Units of Measurement g/cm3, kg/m3 %, v/v decimal g/cm3, kg/m3 b/e Inches, cm

DEN 4 Porosity

Density Log Example

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

DEN 5 Porosity

Density Interpretation Details CHARACTERISTIC VALUES Matrix Value RhoMa 2.65 2650 2.71 2710 2.87 2870 2.98 2980 2.04 2040 ~1.2 ~1200 4.09 4090

Sandstone Limestone Dolomite Anhydrite Halite Coal Barite Gas Oil Water Units

g/cm3

Kg/m3

Fluid Value RhoFl

.2 ~0.85 1.0 to 1.2 g/cm3

200 ~850 1000 to 1200 Kg/m3

Lithology PEF 1.81 5.08 3.14 5.05 4.65 0.2 267. 0.95 0.12 0.36 to 1.1 b/e

POROSITY

DPHI = φ D =

RhoMa − RHOB ρ ma − ρb = RhoMa − RhoFl ρ ma − ρ fl

DPHI = φD = density porosity RHOB = ρb = bulk density (from the log) RhoMa = ρma = matrix density RhoFl = ρfl = 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 tool type, Sonic response equation type, and by service company. The photoelectric effect (PEF) curve can be used alone to determine a single lithology, or in combination 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 is less than the density porosity in a porous and permeable zone. Both curves must be corrected to the lithology of the zone of interest. Similar crossover may occur as part of a lithology effect, as when both the Density and Neutron tools are recorded on limestone matrix, and the lithology is actually a sandstone. SYNTHETIC SEISMOGRAMS Sonic compressional and Density data are used to determine acoustic impedance of the formations along the borehole, and reflection coefficients at bed boundaries. The synthetic seismic trace that is derived from that information can be displayed in depth or time to be compared to the seismic data.

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

DEN 6 Porosity

Density FORMATION MECHANICAL PROPERTIES Compressional and shear sonic data are used with density data to calculate formation properties such 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 while drilling to ensure borehole stability. Information on relative formation strengths supports the design of hydraulic fracturing so that fractures remain in the target formations instead of extending to adjacent formations. Formation strength can also support predictions of drawdown pressures so that sand-free production can be maintained when a well is completed and produced. CLAY CONTENT (SHALINESS) Density and Neutron data are crossplotted, and a shale point identified on the plot (generally from associated Gamma Ray data). The distance between the shale point and a clean formation line is a measure of the clay content of an individual zone, with the shaliness relationship assumed to be a linear function of that distance. BOREHOLE SIZE A mechanical arm opposite the sensors and source hold the density tool against the borehole wall. Movement of the arm is calibrated to indicate hole diameter. Because of tool design, the tool will tend to measure the longest diameter of the hole when the hole is elongated.

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

DEN 7 Porosity

Density Secondary Effects ENVIRONMENTAL EFFECTS Enlarged borehole (>9 inches): RHOB < formation bulk density (DPHI > PHIactual). Rough hole: RHOB < formation bulk density (DPHI > PHIactual). This is due to the sensor pad losing contact with the borehole wall. Other indications of a rough hole will be a highly variable Caliper curve, and a high-valued density correction (DRHO) curve. There are no environmental corrections than can be applied to correct for loss of pad contact. Barite muds: RHOB > formation bulk density (DPHI < PHIactual), and PEF > PEFactual. INTERPRETATION EFFECTS Lithology: The porosity calculated from bulk density will be affected by the choice of matrix density, RhoMa, which varies with lithology. In dense formations, such as anhydrite, the density porosity will be negative because the assumed matrix density is less than the actual formation matrix density. Fluid content: The porosity calculated from bulk density will be affected by the choice of fluid density, RhoFl, which varies with fluid type and salinity. In routine calculations the zone investigated 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 the Density 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 and Density 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 the calculated Density porosity is erroneous because of differences between the assumed matrix and/or fluid density values and the actual densities in the formation.

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

DEN 8 Porosity

Density Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control Density porosity should equal Neutron porosity in clean, wet formations, when both are properly corrected 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 pad contact. • DRHO values deviating by more than 0.10 indicate the density value is not quantitatively 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 pad wear (density readings could be questionable), or other problems. • Large DRHO values opposite an apparently smooth borehole wall may indicate fractures (or other small irregularities at the wall surface). PE will not be reliable in heavy muds, and will show values well over 5. Shale values should be similar to those in nearby wells. Check repeatability; curves should have the same values and character as those from previous runs or repeat sections. Cross-check the curve character with other curves from the same logging run.

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

NEU 1 Porosity

Neutron Interpretation Goals Porosity (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.

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

NEU 2 Porosity

Neutron Tool Diagram

Physics of the Measurement

Halliburton neutron tool (DSN-II).

A chemical source (Americium-Beryllium) emits high energy neutrons which are slowed by formation nuclei. Two detectors in the tool count the number of returning capture gamma rays or neutrons (depending on the type of tool). The detector count rates are inversely proportional to the amount of hydrogen in the formation ("hydrogen index"). By assuming that all the hydrogen resides in the pore space of the formation (as water or hydrocarbons), the hydrogen index can be related to 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 an accelerator to generate neutrons, eliminating the need for a chemical source. This minimizes safety issues on the rig floor and in the event the tool is lost in the hole.

Volume of Investigation Vertical Resolution 90%

Radius of Investigation50%

Precision (+-)

36 in. 20 in.*

6 in.

0.4 p.u.

30-44 in.

6 in.

1 p.u.

20 in.

8 in.

NA

thermal epithermal Gammaneutron

*with enhanced resolution processing © 1999 Halliburton

Operational Constraints The 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 mud Logging speed: 60 feet/minute. May require slower speeds for enhanced resolution processing. Comments:

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

NEU 3 Porosity

Neutron Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Mnemonic Baker Atlas Compensated Neutron Log CN *Sidewall Epithermal Neutron Log, SWN; Neutron Log, NEU Computalog Compensated Neutron Service CNS *Sidewall Neutron Log, SNL Halliburton Dual-Spaced Neutron II DSN II Dual-Spaced Epithermal Neutron DSEN Gearhart *Compensated Neutron Log, CNS; *Sidewall Neutron Log, SNL; *Neutron Log, NL Welex Dual Spaced Neutron II, DSN II; Dual Spaced Neutron, DSN; *Sidewall Neutron, SWN; *Neutron, NEU Reeves Wireline Compensated Neutron Sonde CNS Compact Dual Neutron MDN Schlumberger Integrated Porosity Lithology IPL Platform Express *Compensated Neutron Log, CNL; *Sidewall Neutron Log, SNP; *Gamma Ray-Neutron Tool, GNT Tucker Wireline Compensated Neutron Tool CNT MWD/LWD Mnemonic Baker Hughes INTEQ Caliper Corrected Neutron CCN Modular Neutron Porosity MNP Exlog *(none) Teleco Modular Nuclear Porosity, MNP Pathfinder Density Neutron Caliper DNSC Schlumberger LWD (Anadrill) Vision475 *Compensated Neutron Density, CDN Sperry Sun Compensated Thermal Neutron CTN MWD Triple Combo Compensated Neutron Porosity CNφ

Curves Displayed (Curves are listed by generic name, common mnemonics (if any) and measurement units.) Curve Name Neutron porosity (referenced to a specific lithology)

Mnemonics NPHI, PHIN, NPOR

For older (GNT) tools, Counts

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

Units of Measurement %, v/v decimal Counts/second, API Neutron units

NEU 4 Porosity

Neutron Log Example

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

NEU 5 Porosity

Neutron Interpretation Details CHARACTERISTIC VALUES: These values are for Schlumberger CNL tools, with NPHI curve mnemonic (not TNPH), with lithology referenced to LIMESTONE. Values will change with logging company and tool vintage (type). Matrix Value Sandstone Limestone Dolomite Anhydrite Halite Coal Gas Oil Water Units

-0.02 0.00 0.01 -0.02 -0.03 >0.40

v/v decimal

Fluid Value -2 0 1 -2 -3 >40

%

1 v/v decimal

100 %

POROSITY Except for the obsolete "Gamma Ray Neutron" tools, Neutron porosity is calculated by the acquisition software and is displayed directly on the log. This porosity is referenced to a specific lithology, usually limestone. Corrections to the porosity to account for the lithology actually present can be done through charts or appropriate algorithms. NOTE: It is important to use the chart or algorithm for the correct Neutron tool and acquisition company. Each tool has a unique lithologic response, and use of the wrong algorithm will result in erroneous porosity estimation. The older "gamma ray-neutron" tools will show response in counts per second or API Units on a linear scale. The neutron count rate (or API value) decreases with increasing porosity. In these displays, increasing porosity is shown by movement of the curve to the left of the scale (just like for the newer tools which display porosity directly). These values can be converted to porosity through calibration to core data, or by rules of thumb which approximate the response. The core calibration and rules of thumb tend to apply only to specific reservoirs or over limited geographic areas. All Neutron tools can be run in cased holes to determine formation porosity. Corrections must be made for the presence of casing and cement.

LITHOLOGY IDENTIFICATION Lithology is determined by comparison of neutron porosity with Sonic and Density data in crossplots, in Matrix Identification (MID) plots, and in M-N (A-K) plots. The charts may vary by Neutron tool type, Sonic response equation type, and by service company.

GAS INDICATION Gas is indicated when the Density and Neutron "crossover"; that is, when the neutron porosity is less than the density porosity in a porous and permeable zone. Both curves must be corrected to the lithology of the zone of interest. Similar crossover may occur as part of a lithology effect, as when both the Density and Neutron tools are recorded on limestone matrix, and the lithology is actually a sandstone. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA

NEU 6 Porosity

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

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

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

NEU 7 Porosity

Neutron Secondary Effects ENVIRONMENTAL EFFECTS Enlarged borehole: NPHI > PHIactual Mudcake: NPHI < PHIactual Borehole salinity: NPHI < PHIactual Formation salinity: NPHI > PHIactual Mud weight: NPHI < PHIactual Pressure: NPHI > PHIactual Temperature: NPHI < PHIactual 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 EFFECTS Shaliness: NPHI > PHIactual in shaly zones. Thermal neutron tools are more affected (read higher in shales) than are epithermal neutron tools. Gas: NPHI < PHIactual in gassy zones. See also the section on "Gas Indication" on the previous page. Lithology: In general, for logs recorded in limestone units, if the actual lithology is sandstone, the log porosity is less than the true porosity, and if the actual lithology is dolomite, the log porosity is greater than the actual porosity. See the Neutron porosity equivalence curves in the chartbooks.

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

NEU 8 Porosity

Neutron Neutron environmental corrections

© 1988 Schlumberger

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

NEU 9 Porosity

Neutron Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control Neutron porosity should equal Density porosity in clean, wet formations, when properly corrected for lithology. Shale values should be similar to those in nearby wells. Check repeatability; curves should have the same values and character as those from previous runs or repeat sections. Cross-check the curve character with other curves from the same logging run.

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

Combo 1 Porosity

Porosity Combinations Porosity measurement combinations Remember that “porosity” tools don’t 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 porosity to 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 be assumed.

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 techniques Quicklook 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 data points with respect to pure lithology reference data. The plots may also contain data in the z-axis. Algorithmic calculation techniques are derived from these plots.

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

Combo 2 Porosity

Porosity Combinations Neutron-Density Quicklook method

shale limestone limestone dolomite shale sandstone sandstone anhydrite shale salt shale coal shale limy dolomite sandy limestone dolomitic sand shale

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

Combo 3 Porosity

Porosity Combinations Neutron-Density Quicklook method Approach: Compare the positions of the curves with respect to each other, as well as with respect to the 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/cm3, or scaled to approximate the Neutron porosity scale. The formation fluid is either water or oil, but NOT gas.

Responses Lithology

Porosity

Neutron-Density response

Pe response

Shale

--

Neutron greater than Density by some variable amount depending on the shale composition and depth.

Variable, but about 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 14 porosity 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 8 porosity units.

2 or slightly less.

Sandstone

0.05

Neutron values less than Density (“crossover”) by 6 to 8 porosity units.

2 or slightly less.

Anhydrite

--

Neutron porosity greater than Density by 14 porosity units or more. Neutron porosity near zero.

About 5.

Shale

--

As described in the Shale section above.

As above.

Salt

--

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

About 4.7.

Shale

--

As described in the Shale section above.

As above.

Coal

--

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

Less than 1.

Shale

--

As described in the Shale section above.

As above.

Limy Dolomite

0.10

Variable response with lithologic mix, but Neutron generally greater than Density.

3 to 5.

Sandy LImestone

0.10

Variable response with lithologic mix, but Neutron generally less than Density.

2 to 3.

Dolomitic Sand

0.10

Highly variable, with Neutron greater or less than Density, depending on the lithologic mix.

2 to 5.

Shale

--

As described in the Shale section above.

As above.

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

Combo 4 Porosity

Porosity Combinations Neutron-Density Quicklook: sandstone

shale salt shale shaly gas sand shaly oil sand shaly wet sand clean wet sand shale dolomite shale limestone clean wet sand shale

In this example, the Neutron and Density are displayed with respect to a sandstone matrix (matrix density = 2.65 g/cm3). Note the Neutron-Density crossover in the limestone zone.

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

Combo 5 Porosity

Porosity Combinations Two-Mineral Crossplots METHODOLOGY The four crossplots in this section are interpreted in a similar manner. Given two porosity measurements, the crossplots can be solved for a mineral pair and porosity. There are three lithology lines displayed on the crossplot: sandstone (quartz), limestone (calcite), and dolomite. The lithology lines are marked with porosity values, usually in percent. There may also be additional mineral points on the crossplots; anhydrite and salt are commonly displayed. The log values for a particular interval or depth are plotted on the crossplot to create a point, and the location of the point with respect to the lithology lines is an indication of the lithology and porosity of the point. If the point falls directly on a lithology line, the lithology of the point corresponds to the lithology of the line, and the porosity of the point corresponds to the porosity of the line at that location. If the point falls between two lines, it can be assumed to be a mixture of the lithologies of those two lines. It contains a greater percentage of the mineral of the line to which it is closest. The porosity of the point is determined by connecting the porosity points on the lines, and estimating the porosity of the point by its relationship to those connecting lines. Note that depending on the location of the plotted point, there may be more than one solution for the lithology, and that the porosity will vary according to the lithology solution that is chosen. For example, in the Neutron-Density crossplot on the following page: Neutron limestone porosity (x-axis) = 15% (0.15) Bulk density (y-axis) = 2.50 g/cm3 From the location of the point, the lithology is estimated as limy dolomite (the point is closer to the dolomite line than to the calcite (limestone) line), with a porosity of 15%. An equally reasonable interpretation is that the point represents a sandy dolomite (the point is between the quartz and dolomite lines, but much closer to the dolomite line), with a porosity of 15.5%.

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

Combo 6 Porosity

Porosity Combinations Neutron-Density crossplot

© 1994 Halliburton Porosity is relatively invariant with lithologic assumptions (quartz-dolomite or calcite-dolomite). The tools are usually run together, making the data combination relatively common. Because of the differences in response of Neutron tools, the charts from different service companies and tool types will vary significantly. .

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

Combo 7 Porosity

Porosity Combinations 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.

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

Combo 8 Porosity

Porosity Combinations Spectral 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.

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

Combo 9 Porosity

Porosity Combinations 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 potentially productive formations will plot in the area of the lithology lines, while shales will plot generally in the lower right quadrant of the plot.

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

Combo 10 Porosity

Porosity Combinations Two-mineral crossplots: Summary Crossplot

Advantages

Limitations

Neutron-Density

Given two possible lithology pair solutions, the porosity will remain relatively invariant between solutions.

In rough holes or in heavy drilling muds, the density data may be invalid.

The combination of neutron and density measurements is the most common of all porosity tool pairs.

Neutron-Sonic

Given two possible lithology pair solutions, the porosity will remain relatively invariant between solutions.

The combination of sonic and neutron data (without the density) is not common.

The sonic is less sensitive to rough holes than the density.

Density (bulk density-Pe)

Both measurements are made with the same logging tool; both will often be available.

The choice of lithology pair will have a significant effect of the estimation of porosity. In rough holes or in heavy drilling mud, the data may be invalid. The Pe measurement is relatively new, and will not be present in wells logged before about 1978.

Sonic-Density

Best for identifying radioactive reservoirs, rather than predicting lithology and porosity:

The choice of lithology pair will have a significant effect of the estimation of porosity.

Potential reservoirs will plot along the closely spaced lithology lines while shales will tend to fall toward the lower right of the plot. This can indicate the presence of radioactive reservoirs which are intermingled with shales (which tend to have high radioactivity).

The lithology lines are closely spaced, so any uncertainty in the measurements will produce large changes in the lithology and porosity estimates.

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

Combo 11 Porosity

Porosity Combinations Three-Measurement Crossplots METHODOLOGY 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 restricted to a two-dimensional plot, intermediate quantities which collapse the three measurements to two axes are calculated and plotted. The older M-N plot used sonic, density, and neutron values to calculate M (a function of sonic and density) and N (a function of neutron and density). Newer techniques, and the addition of an additional measurement, photoelectric effect (Pe or PEF), derive “apparent matrix” values. Apparent matrix density, Rhomaa (a function of density and neutron) is plotted against apparent matrix sonic traveltime, DTmaa (a function of sonic and neutron). Apparent matrix density is also plotted against apparent matrix photoelectric cross section, Umaa (a function of density, neutron, and photoelectric effect). In these techniques, any three mineral points are plotted as the vertices of a triangle. The relationship of a plotted apparent matrix point to the triangle determines the components of the formation represented by the point.

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

Combo 12 Porosity

Porosity Combinations M-N plots

© 1998 Schlumberger

M =

DT fluid − DT RHOB − Rho fluid

⋅ 0.01

N=

φ Nfluid − φ N RHOB − Rho fluid

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.”

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

Combo 13 Porosity

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

This is a Neutron-Density crossplot, focused on the lithologic response of the measurements, and ignoring the porosity response. Apparent matrix density is derived from this plot.

© 1994 Halliburton

This is a Neutron-Sonic crossplot, focused on the lithologic response of the measurements, and ignoring the porosity response. Apparent matrix traveltime is derived from this plot.

© 1994 Halliburton

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

Combo 14 Porosity

Porosity Combinations 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 endpoints indicate increased amounts of that mineral.

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

Combo 15 Porosity

Porosity Combinations Preliminary chart for the Neutron-Spectral Density MID plot

© 1994 Halliburton The apparent matrix volumetric cross section is determined from the bulk density and PE, and the total porosity (from the Neutron-Density crossplot.

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

Combo 16 Porosity

Porosity Combinations Neutron-Spectral Density 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 endpoints indicate increased amounts of that mineral.

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

Combo 17 Porosity

Porosity Combinations Three-mineral crossplots: Summary Technique

Notes

Comments

M-N Lithology

M = f(DT, RHOB)

“M” and “N” here are different from, and should not be confused with, the “m” and “n” exponents in Archie’s equation.

N = f(φN, RHOB)

The location of the mineral points on the plot depends on mud salinity, matrix traveltime, and the porosity range. This is the oldest of the three-mineral techniques, and is probably the least desirable to use. Neutron-Density-Sonic MID plot

RhoMaapp = f(RHOB, φN, φTotal)

The mineral triangle for the sandstonelimestone-dolomite group is narrow.

DTMaapp = f(DT, φN, φTotal) Neutron-Spectral Density MID plot

RhoMaapp = f(RHOB, φN, φTotal) UMaapp = f(Pe, RHOB, φTotal)

Requires only Neutron and Spectral Density tools. Sensitive to rough hole data problems. Large mineral triangle for the sandstonelimestone-dolomite group.

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

Combo 18 Porosity

Porosity Combinations Beyond three minerals Solution 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, and anhydrite) plus shale, and also estimates water saturation.

Fluid component volumes Solid component volumes

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

Resistivity

Resistivity This section addresses three categories of resistivity measurements; Induction logs, Laterologs, and Microresistivity (Rxo) measurements. The induction and laterologs both attempt to measure the resistivity of the undisturbed part of the formation, laterally distant from the borehole. The measurements achieve the same goal through different physics of the measurements. The microresistivity measurements for the most part use the same physics as the laterologs, but are designed to measure the resistivity of the formation very close to the borehole, 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.

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

IL 1 Resistivity

Induction Interpretation Goals True (undisturbed) formation resistivity, Rt. Fluid saturation, Sw, via Archie's Equation. Geopressure (overpressure) detection. Diameter of invasion. Correlation.

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

IND 2 Resistivity

Induction Tool Diagram

Physics of the Measurement

Halliburton array induction log (HRI).

Transmitter coils induce an alternating current in the formation. Receiver coils sense the response of the formation, both in magnitude and phase. This response is proportional to the formation conductivity (the inverse of resistivity). Multiple transmitter and receiver coils are used in an effort to minimize borehole and invasion effects on the tool. Newer versions of the tool make better, and digitally recorded, measurements of the in-phase and out-of-phase parts of the signal, and operate at different frequencies, in order to improve the accuracy of the tool. Accuracy is further enhanced by environmental corrections done in real time. “Array” tools have many receivers, usually at small spacings, and rely on signal processing to create a common vertical resolution for all measurements.

Volume of Investigation Vertical Resolution 90% *

Radius of Investigation 50%

Deep

24 in.

91 in.

Medium

24 in.

39 in.

Shallow

Rw, then Rxo > Shallow > Deep. Shale values should be similar to those in nearby wells. Check repeatability; curves should have the same values and character as those from previous runs or repeat sections. Cross-check the character of the curve with other curves from the same logging run.

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

Rxo 1 Resistivity

Microresistivity, ”Rxo” Interpretation Goals Flushed zone formation resistivity, Rxo. Flushed zone water saturation, Sxo, via Archie's Equation. Indication of permeability. Thin bed definition. Fracture identification. Invasion corrections to other resistivity measurements.

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

Rxo 2 Resistivity

Microresistivity, ”Rxo” Tool Diagram

Physics of the Measurement

Halliburton Micro Spherically Focused Log (MSFL).

Electrical current is forced into the formation by closely spaced electrodes mounted on pads pressed against the borehole wall. Some designs, like the MicroSpherically Focused Log, use focusing electrodes similar to the laterolog, while other (older) designs, like the MicroLog, do not focus the current.

Volume of Investigation Vertical Resolution 90%

Radius of Investigation 50%

3 in.

1-4 in.

1.0 in.

1.5 in.

1.5 in.

4 in.

MSFL Microlog microlateral Microlog microinverse

Precision (+-)

0.1 ohm.m 0.1 ohm.m 0.1 ohm.m

Operational Constraints The 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 mud Logging speed: 60 feet/minute Comments:

© 1999 Halliburton

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

Rxo 3 Resistivity

Microresistivity, ”Rxo” Measurement Names Measurement names preceded by an asterisk (*) are not listed in current acquisition company literature, and may no longer be available, or are obsolete. WIRELINE Mnemonic Baker Atlas Minilog ML Micro Laterolog MLL Micro Spherical Laterolog MSL Proximity Log PROX Computalog Micro Resistivity Tool MRT400 Micro Spherically Focused Log MSFL Micro Electric Log, MEL Halliburton Micro Spherically Focused Log MSFL Microlog ML *MicroLaterolog, MLL Gearhart Micro-Triple Resistivity, MTR; Micro-Electrical Log, MEL; Micro-Laterolog, MLL Welex Microlog, ML; Microguard, MGL Reeves Wireline Micro Resistivity Sonde MRS MicroLog Sonde MLS Mud Resistivity Sonde RMS Schlumberger Array Induction Resistivity AIT Array Laterolog Resistivity HRLA *Micro Spherically Focused Resistivity Tool, SRT, MSFL; *Microlaterolog, ML; *Microlog Proximity Tool, MPT; *MicroLog Tool, MLT; *Micro-Cylindrically Focused Logging Device, MCFL Tucker Wireline Microspherically Focused Tool MFT Micro Log Tool MLT MWD/LWD Mnemonic There are no MWD/LWD tools specifically defined as Rxo

Curves Displayed (Curves are listed by generic name, common mnemonics (if any) and measurement units.) Curve Name For Micrologs: Micronormal resistivity Microinverse resistivity For other Rxo measurements: Micro Spherically Focused resistivity Micro Laterolog

Mnemonics

Units of Measurement

MNOR MINV

ohm.m ohm.m

MSFL MLL

ohm.m ohm.m

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

Rxo 4 Resistivity

Microresistivity, ”Rxo” Log Example

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

Rxo 5 Resistivity

Microresistivity, ”Rxo” Microlog example

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

Rxo 6 Resistivity

Microresistivity, ”Rxo” Interpretation Details FLUSHED ZONE FORMATION RESISTIVITY, Rxo Flushed zone formation resistivity, Rxo, can be determined, with minimal environmental corrections, from any of the microresistivity measurements, except for the Microlog. This value is used in Archie’s equation to determine flushed zone water saturation, Sxo, or to indicate moved fluids by comparison to the undisturbed formation resistivity, Rt.

FLUSHED ZONE WATER SATURATION, Sxo Archie's Equation:

S xo

 a ⋅ Rmf =  m  φ ⋅ R xo

1

n   

Sxo = flushed zone water saturation Rmf = mud filtrate resistivity Rxo = flushed zone resistivity (from the microresistivity log) φ = porosity a = cementation factor m = cementation exponent n = saturation exponent Archie's equation assumes that all electrical conductivity occurs in the water saturated portion of the porosity in a rock, with the rock matrix and any hydrocarbons acting as insulators. The presence of clays in the formation (a "shaly sand") creates additional formation conductivity (a lower formation resistivity than an equivalent "clean" sand). In this case, Archie's equation will predict a water saturation greater than is actually in the formation. Several "shaly sand equations" have been developed to account for the effects of clays. The most commonly used are Simandoux, Dual Water, and Waxman-Smits. In the flushed zone form of Archie's equation shown here, Rt is replaced by Rxo, and Rw is replaced by Rmf, with the assumption that all the original water has been replaced by drilling mud filtrate. Comparison of Sxo and Sw (using the same form of Archie's equation) gives some indication of (qualitative) permeability, and the amount of hydrocarbons which will be moved during production. Because of the design of MicroLogs, the resistivity from the log may vary significantly from the actual resistivity of the formation. They should not be used in these calculations.

INDICATION OF PERMEABILITY For Micrologs: The micronormal resistivity is greater than the microinverse resistivity ("positive separation"). There should also be mudcake, as shown by a decrease in the caliper reading. For other Rxo tools: Compare the reading with the resistivity from deeper reading tools. The relationship between the readings will depend on the contrast between the formation water resistivity and the mud filtrate resistivity.

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

Rxo 7 Resistivity

Microresistivity, ”Rxo” FRACTURE IDENTIFICATION Rapid curve movement, or "hashiness", may be an indicator of fractures as the tools see conductive mud-filled fractures alternating with less conductive beds. Rough hole may cause the same response. This technique should be used only as one piece of information along with others in trying to determine the presence of fractures.

THIN BED DEFINITION These tools will identify very thin beds. The bed definition can be used qualitatively to estimate the effect on the deeper reading tools. Bed thickness information from these tools can also be used in software which attempts to make quantitative thin bed (or laminated reservoir) corrections to other resistivity and porosity tools.

INVASION CORRECTIONS TO OTHER RESISTIVITY MEASUREMENTS Rxo tools are usually run in combination with two deeper reading tools (e.g. deep and shallow laterolog, deep and medium induction log). Using the combination of three measurements, invasion corrections may be made using "tornado charts" or equivalent algorithms.

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

Rxo 8 Resistivity

Microresistivity, ”Rxo” Secondary Effects ENVIRONMENTAL EFFECTS Mudcake corrections may need to be made if the measurements are to be used quantitatively. Micro Laterologs provide good Rxo readings for invasion thicknesses of as little as four inches, but require mudcake corrections for mudcakes larger than 1/4 inch. On the other hand, no mud cake correction is required for the Proximity log unless mudcake thickness is over 3/4 inch or very high Rxo to mudcake resistivity (Rmc) ratios exist. However, the Proximity log has a much larger depth of investigation, and unless flushing has proceeded to 40 inches from the wellbore, one cannot be sure of getting an Rxo reading not affected by the uninvaded rock resistivity. The MSFL tool is a compromise to give reasonable Rxo readings without requiring mudcake correction except for large mudcakes Rough hole will cause the pad to lose contact with the borehole wall. No corrections can be made to the data to correct for the effect.

INTERPRETATION EFFECTS Clays in the formation have the same effect on these resistivity tools as on the deeper reading tools. Flushed zone forms of the various shaly sand equations can be written. Where hydrocarbons have been flushed away from the vicinity of the wellbore, the resistivity effect may be less severe for the Rxo device than for the deeper reading tools responding to the uninvaded (or less severely invaded) rock beyond the "flushed zone". However, Sxo calculations may still be affected similarly to Sw calculations in fresh water mud systems since clay conductivity effects are more pronounced in less saline environments. Then, with fresh mud systems in saline water saturated rocks, the resistivity effect will be larger for the Rxo devices (i.e. clay conductivity component more significant).

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

Rxo 9 Resistivity

Microresistivity, ”Rxo” Environmental Corrections This table indicates the corrections for the borehole and formation conditions that can be made for each logging measurement. The corrections that are applicable to the measurement are shown in bold. CORRECTION borehole mud weight bed thickness invasion mud cake borehole salinity formation salinity standoff pressure temperature excavation propagation time attenuation lithology

COMMENTS

Not all acquisition companies may have the correction indicated on this chart, or make corrections for all generations of the tool. For newer logs, corrections may have been made at the time of data acquisition. Check the log header for information. Algorithms which are equivalent to (or often better than) the chartbooks may be available from the acquisition company, or in some formation evaluation software packages.

Quality Control Microresistivity curves should overlay deeper-reading curves in impermeable beds. Separation with deeper-reading logs should be indicative of invasion or borehole effects. Curves may not repeat as well as other logs due to variations in pad path and possible resulting changes in hole conditions or fracturing. Check caliper for very thick mudcakes requiring quantitative corrections. Shale values should be similar to those in nearby wells. Check repeatability; curves should have the same values and character as those from previous runs or repeat sections. Cross-check the curve character with other curves from the same logging run.

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

Interpretation

Openhole Interpretation This section is intended to give a flavor for openhole interpretation, as a supplement to the tool sections that precede it. It is not intended to provide a comprehensive compilation of interpretive techniques. The general scanning techniques, quicklook techniques, and quantitative analysis flowchart may be of the most use to the reader. The reader is referred to the Annotated Bibliography, especially (in order) the works of Asquith and Krygowski (in press), Dewan (1983), Hearst et al (2000), and Bassiouni (1994).

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

OH 1 Interpretation

Openhole Interpretation Introduction The traditional goals of openhole “log analysis” are porosity and water saturation, and occasionally, lithology. These goals have driven the techniques to strive for more accurate predictions of these quantities, to give the most accurate answers with which to determine formation hydrocarbon volumes and producibility. This approach has also tended to create specialists which have little interaction with other disciplines, except to gather data from them, and then deliver “the answer” to them. In recent years, a dichotomy in interpretation has developed, where interpreters are increasingly called on to provide just enough information for an accurate “yes/no” decision, with details to follow later (if at all). This approach also requires the interpreter to become an active part of an asset team, incorporating the work of others in his/her process, and delivering the results of that process to other team members in a timely manner. In this context, the interpreter is expected to be an active member of the team, producing results that explicitly account for the information provided by others. The interpreter is also expected to be aware of, and interested in, the other team disciplines as a way to improve and integrate his/her interpretations.

Contents of this section This section looks at the process of openhole interpretation, primarily of well logs. No distinction is made between the data gathered by wireline tools as contrasted with MWD/LWD tools. In the interpretive arena, the measurements are essentially identical. Introduction Contents Comments General scanning technique General scanning workflows Neutron-Density quicklook for determining lithology and estimating porosity Rwa quicklook for identifying potential productive zones Quantitative analytical techniques Data sources and output quantities Analytical workflow Determination of formation lithology Calculation of shale volume (in shaly formations) Calculation of porosity Estimation of formation water resistivity, Rw Temperature correction Mud filtrate resistivity, Rmf Determination of true formation resistivity, Rt Calculation of formation water saturations: Sw and Sxo

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

OH 2 Interpretation

Openhole Interpretation General scanning techniques Clastics: Because the shales surrounding clastic reservoirs tend to have slowly varying resistivity with depth, the scanning process targets formation resistivity to identify zones of interest. Carbonates: Because the resistivity of a sequence of carbonate formations may vary over a wide range, the scanning process targets formation porosity to identify zones of interest.

Look for clean zones 1

Soft rocks (Clastics)

Hard rocks (Carbonates)

Look for resistivity 2

Look for porosity

LOW

HIGH

LOW

Water zone Use as baseline (wet) comparison.

HIGH

Tight. Unlikely pay.

Check resistivity Check porosity LOW HIGH

HIGH

LOW Tight. Unlikely pay.

Water zone Use as baseline (wet) comparison.

Zone of interest

Zone of interest

Begin detailed analysis

1: Zones which appear to be shales may be radioactive productive zones. 2: Shaly zones may produce even when having low resistivity.

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

OH 3 Interpretation

Openhole Interpretation Quicklook Techniques Quicklook techniques can be the next step after scanning the logs, or can be conducted during the scanning process. Two of several techniques, Neutron-Density and Apparent Water Resistivity, are discussed here.

NEUTRON-DENSITY QUICKLOOK

shale limestone limestone dolomite shale sandstone sandstone anhydrite shale salt shale coal shale limy dolomite sandy limestone dolomitic sand shale

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

OH 4 Interpretation

Openhole Interpretation The Neutron-Density quicklook technique is a quick way of determining formation lithology. The most important aspect of the technique is determining the relative positions of the neutron and density curves (with respect to each other). While the positions of the curves on the log will vary with changing porosity, the relative positions of the curves will remain fairly constant with lithology. The photoelectric effect curve (Pe) is not required for the technique, but may be useful to resolve some ambiguities which occur with some lithologic mixtures. The following conditions must be met for the technique to work well: •

The Neutron porosity curve is recorded on a limestone matrix.

•

The Density porosity is calculated with a limestone matrix (matrix density = 2.71 g/cm3 or 2710 Kg/m3). Alternately, the bulk density curve can be used if it is scaled to closely approximate the scale of the neutron porosity curve (as shown in this example).

•

The formations are assumed to be clean (no clays/shales).

•

The formation fluids are assumed to be liquid-filled (water or oil only; no gas present).

The porosity of the formation can be estimated by taking the average of the neutron porosity and density porosity readings. In most cases, this will provide a porosity within one porosity unit of that derived from neutron-density crossplot porosity techniques. The descriptions in the table below correspond to the lithologies in the example on the previous page. The responses listed in the table are general responses for the listed lithology types. Lithology

Porosity

Neutron-Density response

Pe response

Shale

--

Neutron greater than Density by some variable amount depending on the shale composition and depth.

Variable, but about 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 14 porosity 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 8 porosity units.

2 or slightly less.

Sandstone

0.05

Neutron values less than Density (“crossover”) by 6 to 8 porosity units.

2 or slightly less.

Anhydrite

--

Neutron porosity greater than Density by 14 porosity units or more. Neutron porosity near zero.

About 5.

Shale

--

As described in the Shale section above.

As above.

Salt

--

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

About 4.7.

Shale

--

As described in the Shale section above.

As above.

Coal

--

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

Less than 1.

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

OH 5 Interpretation

Openhole Interpretation Lithology

Porosity

Neutron-Density response

Pe response

Shale

--

As described in the Shale section above.

As above.

Limy Dolomite

0.10

Variable response with lithologic mix, but Neutron generally greater than Density.

3 to 5.

Sandy LImestone

0.10

Variable response with lithologic mix, but Neutron generally less than Density.

2 to 3.

Dolomitic Sand

0.10

Highly variable, with Neutron greater or less than Density, depending on the lithologic mix.

2 to 5.

Shale

--

As described in the Shale section above.

As above.

APPARENT WATER RESISTIVITY, Rwa, QUICKLOOK The Rwa technique relies on the comparison of calculated values of water resistivity between intervals in a well. This comparison can be made between different zones, or within the same zone if a water-hydrocarbon contact is suspected in that zone. The assumption is that this lowest value of Rwa is the closest approximation to the true formation water resistivity, Rw, and that values of Rwa greater than the minimum value are indicative of the presence of hydrocarbons. A water saturation can also be calculated from the values of Rwa. The technique is: Calculate an “apparent” water resistivity, Rwa, from the porosity and uninvaded zone resistivity measurements. Look for the lowest value of Rwa in a porous and permeable zone and compare it to the values of Rwa calculated in the other zones. If desired, an Archie water saturation can be calculated from the Rwa values in the compared zones. The patterns to observe are: The zone with the lowest value of Rwa is the most likely to be water-bearing, and the value of Rwa is closest to the actual value of Rw in the formation. Zones with values of Rwa greater than the minimum observed are likely to have some hydrocarbon saturation. Interpretation pitfalls: The Rw values in the zones that are compared are assumed to be the same. In low porosity zones (less than about 10 percent porosity), the Rwa value will be lower than the actual Rw value. The basis for the technique: Recall from Archie’s equation that

Ro = F ⋅ Rw

OH.01

and

F=

a

φm

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

OH.02

OH 6 Interpretation

Openhole Interpretation Combining equations OH.01 and OH.02, and solving for Rw yields:

Rw =

Ro ⋅ φ m a

OH.03

From equation OH.03 above, define “apparent” water resistivity, Rwa, as:

Rwa =

Rt ⋅ φ m a

OH.04

In water-bearing zones (Sw = 1.0): Rt = Ro and Rwa = Rw In hydrocarbon-bearing zones (Sw < 1.0): Rt > Ro and Rwa > Rw By comparing a number of zones (or different depths in the same zone, where a waterhydrocarbon contact is suspected), and assuming the zone with the lowest value of Rwa is wet, that minimum value of Rwa can be used as an estimate for the value of Rw in all the zones being considered. If the zone with the minimum Rwa value actually contains some hydrocarbons, then the other zones will be even more hydrocarbon bearing than anticipated. In practice, especially when calculated and displayed as a curve, the following values can be used for simplicity: a = 1.0, m = 2.0. The Deep Induction or Deep Laterolog is used as Rt, usually without any environmental corrections. Porosity is usually derived from the sonic or density, with the proper matrix and fluid parameters for the formations to be encountered. If available in real time during logging, the neutron-density crossplot porosity should be used for the best estimate of porosity.

SCANNING AND QUICKLOOK TECHNIQUES: SUMMARY The purpose of scanning and quicklook techniques is to identify potential zones of interest (both hydrocarbon-bearing and water-bearing) from the bulk of the drilled interval which usually has no production potential. Even in the era of computer-aided data processing, where the difference in time of processing is trivial between the entire well and only interesting zones, these techniques are useful in helping the interpreter to quickly focus on the zones in the well with the most potential.

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

OH 7 Interpretation

Openhole Interpretation Quantitative analytical techniques This diagram shows the output quantities targeted in the analytical techniques, and the data sources and parameters needed to derive those quantities.

Data Source

Input Data and Parameters

Resistivity (deep-reading)

Rt

Resistivity (shallow-reading)

Rxo

Output Quantities

Sw Sxo

Density

Neutron

Φ (Phi) Moveable Hydrocarbons

Sonic Magnetic Resonance Spontaneous Potential (SP)

Vshale

Bulk Volume Water (BVW)

Rw Permeability

Gamma Ray Rmf Wellsite Measurements Laboratory Measurements Local Knowledge

Reserves a m n

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

OH 8 Interpretation

Openhole Interpretation Analytical workflow Determine formation lithology

If needed, Calculate shale volume, Vsh If a microresistivity (Rxo) measurement is available: Calculate porosity

Estimate formation water resistivity, Rw

Estimate mud filtrate resistivity, Rmf

Determine true formation resistivity, Rt

Determine flushed zone resistivity, Rxo

Pick Archie parameters: a, m, n If needed, pick shaly sand parameters: Vshale, Rshale, …

Calculate formation water saturation, Sw

Calculate flushed zone water saturation, Sxo

Predict moveable hydrocarbons

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

OH 9 Interpretation

Openhole Interpretation Determination of formation lithology SAMPLES: CUTTINGS AND CORES The best estimate of formation lithology will obviously come from a sample of the formation. However, even a detailed lithologic description will not guarantee the value of porosity tool matrix parameters (that is, a “clean sandstone” may not have a matrix density value of 2.65 g/cc), but the value will probably be close to the “standard” value. Lithologic descriptions will help the evaluation process by narrowing the bounds of many analysis parameters, and by alerting the analyst to secondary minerals or conditions which may have an effect on the interpretation. Specific core measurements (porosity, grain density, permeability, ...) can help fine-tune analytical techniques. It is important to remember, however, that core measurements have about the same precision (or alternatively, the same range of uncertainty) as logging measurements. One should consider an interpretation as the “reconciliation of a variety of data types” rather than “calibrating the logs”. “Remember that the piece of core you have so thoroughly characterized is the only piece of rock which is no longer part of the reservoir that you are trying to produce.” -Dr. Folkert Brons, The University of Texas, ca.1974

LOCAL KNOWLEDGE Knowledge of the lithology of a formation in a specific geographic area is often almost as good as lithologic descriptions from the specific well in question, in terms of predicting analytical parameters. Often, the knowledge of local experts will extend beyond just the lithology to other commonly used analytical parameters.

INDICATIONS OF GROSS LITHOLOGY The SP and Gamma Ray can provide indications of gross lithology; that is, they can be used to distinguish reservoir from non-reservoir. Their use should be in conjunction with other logs to confirm the indication, since both logs are subject to secondary effects which will affect their reservoir detection capabilities. These effects are: Gamma Ray Reservoirs with high gamma radioactivity will look like shales. SP Reservoirs with high clay content may look like shales. If mud filtrate and formation water resistivities are equal, no SP will be developed.

NEUTRON-DENSITY QUICKLOOK The Neutron-Density quicklook technique is detailed in the section on general scanning, beginning on page OH 3.

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

OH 10 Interpretation

Openhole Interpretation POROSITY CROSSPLOTS: TWO-MINERAL TECHNIQUES Using two porosity measurements in an x-y plot (“crossplot”) tends to minimize some of the environmental and porosity effects which impact individual tools, and produces better estimates of lithology (and porosity) than by using a single porosity measurement. To use the technique, the interpreter must assume the presence of some two-mineral pair. Any two minerals may be used as long as they plot uniquely on the crossplot. For all the crossplots listed in the table below, lines for sandstone (quartz), limestone (calcite), and dolomite are shown. The Neutron-Density crossplot is the most desirable of the four possible crossplots, and is shown here as an example.

In the crossplot above, the point, at (10, 2.50), could have two possible lithologic mixtures: •

The point could be a mixture of calcite and dolomite, since it lies between those lithology lines. Because it lies closer to the calcite line, it is assumed to have more calcite than

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

OH 11 Interpretation

Openhole Interpretation dolomite (a “dolomitic limestone”?). Based on a linear interpolation of the distance between the lithology lines, it contains approximately 70 percent calcite and 30 percent dolomite. •

The point could also indicate a mixture of quartz and dolomite because it also lies between the quartz and dolomite lines. Ignoring the calcite line, this “sandy dolomite” is approximately 60 percent dolomite and 40 percent quartz, based on the distances of the point from each of the lines.

The table below summarizes the two-mineral crossplots, and lists them in descending order of preference of use.

Crossplot

Advantages

Limitations

Neutron-Density

Given two possible lithology pair solutions, the porosity will remain relatively invariant between solutions.

In rough holes or in heavy drilling muds, the density data may be invalid.

The combination of neutron and density measurements is the most common of all porosity tool pairs. Neutron-Sonic

Given two possible lithology pair solutions, the porosity will remain relatively invariant between solutions.

The combination of sonic and neutron data (without the density) is not common.

The sonic is less sensitive to rough holes than the density. Density (bulk density-Pe)

Both measurements are made with the same logging tool; both will often be available.

The choice of lithology pair will have a significant effect of the estimation of porosity. In rough holes or in heavy drilling mud, the data may be invalid. The Pe measurement is relatively new, and will not be present in wells logged before about 1978.

Sonic-Density

Best for identifying radioactive reservoirs, rather than predicting lithology and porosity: Potential reservoirs will plot along the closely spaced lithology lines while shales will tend to fall toward the lower right of the plot. This can indicate the presence of radioactive reservoirs which are intermingled with shales (which tend to have high radioactivity).

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

The choice of lithology pair will have a significant effect of the estimation of porosity. The lithology lines are closely spaced, so any uncertainty in the measurements will produce large changes in the lithology and porosity estimates.

OH 12 Interpretation

Openhole Interpretation POROSITY CROSSPLOTS: THREE-MINERAL TECHNIQUES A natural extension of the two-mineral technique is the three-mineral technique. Similar to the two-mineral technique, any three minerals that plot distinctly on the crossplot can be used, although calcite-quartz-dolomite and calcite-dolomite-anhydrite triangles are most usually shown. The Neutron-Density-Sonic technique is used here as an example. •

Total porosity is determined from the Neutron-Density crossplot.

•

Apparent matrix density is determined from a form of the Neutron-Density crossplot focused on matrix density determination.

This is a Neutron-Density crossplot, focused on the lithologic response of the measurements, and ignoring the porosity response.

© 1994 Halliburton

•

Apparent matrix traveltime is determined from a form of the Neutron-Sonic crossplot focused on matrix traveltime determination.

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

© 1994 Halliburton

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

OH 13 Interpretation

Openhole Interpretation •

Apparent matrix traveltime and apparent matrix density are plotted against a mineral triangle. The proximity of the data to the mineral endpoints of the triangle indicate the mineral composition of each point.

© 1994 Halliburton As with the two-mineral techniques, the lithology estimation assumes a linear relationship, and should be used as a general indicator of lithologic content, rather than of specific lithologic percentages.

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

OH 14 Interpretation

Openhole Interpretation The table below lists the three-mineral techniques. The M-N Lithology technique is the oldest of the three techniques, and the least desirable to use. Technique

Notes

Comments

M-N Lithology

M = f(DT, RHOB)

“M” and “N” here are different from, and should not be confused with, the “m” and “n” exponents in Archie’s equation.

N = f(φN, RHOB)

The location of the mineral points on the plot depends on mud salinity, matrix traveltime, and the porosity range. This is the oldest of the three-mineral techniques, and is probably the least desirable to use. Neutron-Density-Sonic MID plot

RhoMaapp = f(RHOB, φN, φTotal)

The mineral triangle for the sandstonelimestone-dolomite group is narrow.

DTMaapp = f(DT, φN, φTotal) Neutron-Spectral Density MID plot

RhoMaapp = f(RHOB, φN, φTotal) UMaapp = f(Pe, RHOB, φTotal)

Requires only Neutron and Spectral Density tools. Sensitive to rough hole data problems. Large mineral triangle for the sandstonelimestone-dolomite group.

POROSITY CROSSPLOTS: MULTIMINERAL TECHNIQUES Multimineral techniques (usually greater than three minerals) are usually based on probabilistic techniques where the lithology (and often porosity) are estimated from the “ideal” mineral responses provided (either by the logging company or the user) for each logging measurement. In general, the more measurements that have been made, the more complex the lithologic model that can be assumed. These techniques have no chartbook format, and can only be used through sophisticated algorithms and computer programs.

DETERMINATION OF FORMATION LITHOLOGY: SUMMARY All available data should be used in determining formation lithology. Cuttings and cores are the best indicators, and the comparison of the logs to cores and cuttings will help in reconciling any differences in interpretation.

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

OH 15 Interpretation

Openhole Interpretation Calculation of shale volume Not long after the work of Archie and others in devising a method to quantify water saturation from logs, it became clear that there were limitations to the method, especially in formations containing shale and/or clay, and commonly referred to as “shaly sands”. The early literature tended to refer to the formations as containing “shale”, and a number of modifications were made to Archie’s equation which used shale volume (among other parameters) to account for those effects. As our understanding of geological processes matured, it became understood that “shale” and “clay” were different, and that “shaly sands” were usually not just sands with shales mixed in, but sands which contained clays; clays which could be very different from the clays present in the shales near those sands of interest. Again, the literature and our interpretive techniques often use the terms “shale volume” and “clay volume” interchangeably. Most of the shaly sand techniques developed over the years concern themselves with shale volume, but a few, notably the Waxman-Smits and Dual Water methods, seek to use the electrical properties of the clays in the formations to predict an accurate water saturation. This section addressed the calculation of shale volume that is then used to determine porosity and water saturation in shaly sands.

SP, SPONTANEOUS POTENTIAL

Vshale =

PSP − SSP SPshale − SSP

OH.05

Where: Vshale = volume of shale PSP = pseudo static spontaneous potential (maximum SP of the shaly formation). SSP = static spontaneous potential of a nearby thick clean sand. SPshale = value of SP in a shale (usually assumed to be zero)

GAMMA RAY Gamma Ray Index, IGR:

I GR =

GRlog − GRclean GRshale − GRclean

OH.06

IGR describes a linear response to shaliness or clay content. GRlog = log reading at the depth of interest GRclean = Gamma Ray value in a nearby clean zone GRshale = Gamma Ray value in a nearby shale Linear Gamma Ray - clay volume relationship: Vshale = IGR

Non-linear Gamma Ray - clay volume relationships:

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

OH.07

OH 16 Interpretation

Openhole Interpretation Steiber:

V shale = Clavier:

I GR 3.0 − 2.0 ⋅ I GR

OH.08

[

V shale = 1.7 ⋅ 3.38 ⋅ (I GR + 0.7 ) Larionov (Tertiary rocks):

(

]

2 0.5

)

V shale = 0.083 ⋅ 2 3.7⋅I GR − 1 Larionov (older rocks):

[(

)

V shale = 0.33 ⋅ 2 2⋅I GR − 1.0

]

OH.09

OH.10

OH.11

All the non-linear gamma ray relationships are more optimistic than the linear relationship; that is; for an equivalent gamma ray response, they return a lower shale volume than the linear response.

Baker Atlas, 1985

NEUTRON-DENSITY V shale =

φN − φD φ NShale − φ DShale

OH.12

This technique assumes that the neutron and density porosities are corrected to the proper lithology, and that the response relationship of the measurements between shale and the clean formation is linear.

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

OH 17 Interpretation

Openhole Interpretation Calculation of porosity, φ This and the following page outline a general interpretation flow which considers the availability of lithologic and other rock information in the determination of porosity. The more specific calculation methods which follow can be used within this general context.

Is the lithology known? no

yes

(Go to the next page.)

Are rock descriptions and/or measurements available? no

yes

Are two or more porosity measurements available? no

Are two or more porosity measurements available? no

yes Use porosity crossplot techniques to determine lithology and porosity.

Use porosity crossplot techniques to determine lithology and porosity.

Use rock description and data to choose the lithology matrix parameter.

Is a clay correction needed? yes

yes

no

Apply the clay correction. Is a clay correction needed? yes

Use the most likely estimate of lithology to calculate porosity.

no

Apply the clay correction.

Are the crossplot results and rock data in agreement?

Depending on the lithology assumed and the actual formation lithology, porosity estimates can be in error by as much as 6 porosity units.

yes

no Reconcile rock and log data.

Effective porosity, φe

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

OH 18 Interpretation

Openhole Interpretation Is the lithology known? no

(Go to the previous page.)

yes

Are rock descriptions and/or measurements available? no

yes

Are the porosity curve lithology (matrix) and fluid settings in agreement with the known lithology? yes

Are the porosity curve lithology (matrix) and fluid settings in agreement with the known lithology?

no

yes

Reconcile log, rock, and fluid data. Compute porosities.

Compute the porosity using the matrix setting for the known lithology.

Is a clay correction needed? yes

no

Is a clay correction needed? yes

no

no

Apply the clay correction.

Apply the clay correction.

Is log-derived porosity in agreement with available rock measurements?

yes

no

Reconcile rock and log data. Effective porosity, φe

Volume of pores Total volume of rock Effective Porosity = The amount of porosity which is interconnected and able to transmit fluid.

Total Porosity =

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

OH 19 Interpretation

Openhole Interpretation POROSITY FROM SINGLE MEASUREMENTS Density log

RhoMa − RHOB ρ ma − ρ b = RhoMa − RhoFl ρ ma − ρ fl

DPHI = φ D =

OH.13

DPHI = φD = density porosity RHOB = ρb = bulk density (from the log) RhoMa = ρma = matrix density RhoFl = ρfl = fluid density (often assumed to be mud filtrate density) Sonic log Wyllie Time-Average Equation:

SPHI = φ S =

∆t − ∆t ma DT − DTMa 1 1 • • = DTFl − DTMa Bcp ∆t fl − ∆t ma Bcp

OH.14

SPHI = φS= sonic (acoustic) porosity DT = ∆t = sonic travel time (from the log) DTMa = ∆tma = matrix travel time DTFl = ∆tfl = fluid travel time Bcp = compaction correction, where

Bcp =

DTShale ≥ 1 .0 100

The Bcp factor was added to the equation when it was found that the equation gave highly optimistic porosity values in unconsolidated sands. DTShale is picked from a shale near the zone of interest. The correction factor is never less than 1.0. Gardner-Hunt-Raymer Equation (Schlumberger Empirical Relation):

SPHI = φ S =

5 DT − DTMa 5 ∆t − ∆t ma • = • DT ∆t 8 8

OH.15

SPHI = φS= 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. Neutron log Except for the obsolete "Gamma Ray Neutron" tools, Neutron porosity is calculated by the acquisition software and is displayed directly on the log. This porosity is referenced to a specific lithology, usually limestone. Corrections to the porosity to account for the lithology actually present can be done through charts or appropriate algorithms. NOTE: It is important to use the chart or algorithm for the correct Neutron tool and acquisition company. Each tool has a unique lithologic response, and use of the wrong algorithm will result in erroneous porosity estimation. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA

OH 20 Interpretation

Openhole Interpretation The older "gamma ray-neutron" tools will show response in counts per second or API Units. In these displays, increasing porosity is shown my movement of the curve to the left of the scale (just like for the newer tools which display porosity directly). These values can be converted to porosity through calibration to core data, or by rules of thumb which approximate the response. The core calibration and rules of thumb tend to apply only to specific reservoirs or over limited geographic areas. All Neutron tools can be run in cased holes to determine formation porosity. Corrections must be made for the presence of casing and cement.

POROSITY FROM MEASUREMENT COMBINATIONS (CROSSPLOTS) Using two porosity measurements in an x-y plot (“crossplot”) tends to minimize some of the environmental and lithologic effects which impact porosity estimation from individual tools, and produces better estimates of porosity (and lithology) than by using a single porosity measurement. To use the technique, the interpreter must assume the presence of some two-mineral pair. Any two minerals may be used as long as they plot uniquely on the crossplot. For all the crossplots listed in the table below, lines for sandstone (quartz), limestone (calcite), and dolomite are shown. The Neutron-Density crossplot is the most desirable of the four possible crossplots, and is shown here as an example.

© 1994 Halliburton Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA

OH 21 Interpretation

Openhole Interpretation To estimate the porosity of the point at (10, 2.50), a mineral pair must first be chosen. In this case, the pair is calcite-dolomite. The porosity is estimated by connecting the porosity values on each line and reading the porosity from the points location (in this case, about 9.5 percent or 0.095) The table below (also shown in the lithology determination section) summarizes the crossplot techniques. In general, the sonic-density crossplot is not recommended for porosity determination. Most of the crossplots have algorithmic equivalents which are easier to use for large amounts of data. Crossplot

Advantages

Limitations

Neutron-Density

Given two possible lithology pair solutions, the porosity will remain relatively invariant between solutions.

In rough holes or in heavy drilling muds, the density data may be invalid.

The combination of neutron and density measurements is the most common of all porosity tool pairs. Neutron-Sonic

Given two possible lithology pair solutions, the porosity will remain relatively invariant between solutions.

The combination of sonic and neutron data (without the density) is not common.

The sonic is less sensitive to rough holes than the density. Density (bulk density-Pe)

Both measurements are made with the same logging tool; both will often be available.

The choice of lithology pair will have a significant effect of the estimation of porosity. In rough holes or in heavy drilling mud, the data may be invalid. The Pe measurement is relatively new, and will not be present in wells logged before about 1978.

Sonic-Density

Best for identifying radioactive reservoirs, rather than predicting lithology and porosity:

The choice of lithology pair will have a significant effect of the estimation of porosity.

Potential reservoirs will plot along the closely spaced lithology lines while shales will tend to fall toward the lower right of the plot. This can indicate the presence of radioactive reservoirs which are intermingled with shales (which tend to have high radioactivity).

The lithology lines are closely spaced, so any uncertainty in the measurements will produce large changes in the lithology and porosity estimates.

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

OH 22 Interpretation

Openhole Interpretation POROSITY FROM MEASUREMENT COMBINATIONS (QUICKLOOK) The Neutron and Density can be used in combination to determine porosity without using crossplot techniques. These are usually used as a “quicklook” technique, rather than a rigorous determination of porosity. If the lithology and formation fluid are unknown:

φ=

φN +φD

OH.16

2

Notes for use: •

The porosities should be recorded on limestone matrix in complex lithologies.

•

Use of the method in gas zones will yield slightly low porosity values (0 to 0.025) depending on the porosity range and the value of Sxo.

•

Use of the method in water or oil zones yields values of porosity which are very close to actual porosities.

If the lithology is known and the formation fluid is gas:

φ=

φ D2 + φ N2 2

=

2 1 φD + φN 3 3

OH.17

Notes for use: •

The porosities should be recorded on, or corrected to, the actual formation lithology.

CALCULATION OF EFFECTIVE POROSITY The general form of the equation to convert from total porosity to effective porosity is:

(

φ e = φ − φ shale ⋅ V shale

)

Where: φe = effective porosity φ = porosity calculated from the measurement φshale = value of the porosity measurement in a nearby shale Vshale = shale volume

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

OH.18

OH 23 Interpretation

Openhole Interpretation Estimating formation water resistivity, Rw APPARENT WATER RESISTIVITY, Rwa, TECHNIQUE The Rwa technique relies on the comparison of calculated values of water resistivity between intervals in a well. This comparison can be made between different zones, or within the same zone if a water-hydrocarbon contact is suspected in that zone. The assumption is that this lowest value of Rwa is the closest approximation to the true formation water resistivity, Rw, and that values of Rwa greater than the minimum value are indicative of the presence of hydrocarbons. A water saturation can also be calculated from the values of Rwa. The details of the technique are shown in the scanning and quicklook section. By comparing a number of zones (or different depths in the same zone, where a waterhydrocarbon contact is suspected), and assuming the zone with the lowest value of Rwa is wet, that minimum value of Rwa can be used as an estimate for the value of Rw in all the zones being considered. If the zone with the minimum Rwa value actually contains some hydrocarbons, then the other zones will be even more hydrocarbon bearing than anticipated. In practice, especially when calculated and displayed as a curve, the following values can be used for simplicity: a = 1.0, m = 2.0. The Deep Induction or Deep Laterolog is used as Rt, usually without any environmental corrections. Porosity is usually derived from the sonic or density, with the proper matrix and fluid parameters for the formations to be encountered. If available in real time during logging, the neutron-density crossplot porosity should be used for the best estimate of porosity.

Rw FROM THE SP From a water-bearing zone near the zone of interest, calculate Rw by:

Rw =

R weq + 0.131 ⋅ 10 [1 / log ( BHT / 19.9 )]− 2

− 0.5 ⋅ R weq + 10 [0.0426 / log ( BHT / 50.8 )]

OH.18

A simplified equation that will yield adequate results is:

Rw = 10

(K ⋅log (Rmf )+ SP ) / K

where K = 61 + 0.133 ⋅ T (T in degF)

OH.19

The presence of shale and/or hydrocarbons will cause the Rw calculated from the PS to be too high. This will cause the Sw calculated from that Rw to also be too high. Significant amounts of ions other than NaCl will also cause Rw to be in error.

Rw FROM A PICKETT PLOT The Pickett method is a graphical solution of Archie’s equation in terms of resistivity. Archie’s equation is solved for resistivity:

Rt =

a ⋅ Rw

φ m ⋅ Swn

OH.20

Taking the logarithm of the equation produces:

log(Rt ) = log(a ⋅ Rw ) − m log(φ ) − n log(S w ) Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA

OH.21

OH 24 Interpretation

Openhole Interpretation If the zone is water-bearing, Sw = 1, log(Sw) = 0, and the equation reduces to:

log(Rt ) = log(a ⋅ Rw ) − m log(φ )

OH.22

This form of the equation (y = b + mx) indicates that by plotting Rt on the y-axis (on a logarithmic scale) against porosity (φ) on the x-axis (on a logarithmic scale), one can determine the product (a Rw) from the intercept of the line (b), and the cementation exponent, m, from the slope of the line (m). In practice, the resistivity, Rt, is usually plotted on the x-axis and the porosity, φ, on the yaxis. Using the convention, the equation becomes:

log(φ ) = log(a ⋅ Rw ) −

1 log(Rt ) − n log(S w ) m

OH.23

Plotting a mixture of water-bearing and hydrocarbon-bearing points on a Pickett plot results in the following attributes (as shown below): Water-bearing points of different porosities plot along a straight line with a slope of (–1/m) and an intercept (at porosity = 1.0) of (aRw). From this line, the cementation exponent, m, can be determined, and if the tortuosity factor, a, is known (or can be estimated), Rw can be predicted. This is the water-bearing, or Ro, line. Hydrocarbon-bearing points will lie away from the line, moved horizontally to the right from the water-bearing line by their increased resistivity. The horizontal distance of a point from the water-bearing line depends on the water saturation, Sw, of that point. If the saturation exponent, n, is known (or can be estimated), the water saturation can be determined. Lines of constant water saturation lie parallel to the water-bearing line. 1.00

Density porosity, DPHI

! !

!!

! !

! !!

0.10

30

50 70 100 Sw

0.01

0.10

1.00

10.00 True resistivity, Rt

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

100.00

OH 25 Interpretation

Openhole Interpretation RW FROM PRODUCTION TESTS: This is the best value of Rw when available. NOTE: Sometimes produced water is not formation water (e.g., water of condensation from gas wells, acid contaminated load water). ALSO: Be sure to that the reported value of Rw is corrected to formation temperature before using in in the interpretation.

RW FROM DRILL STEM TESTS (DST): NOTE: Water from drill stem tests is often contaminated with mud filtrate. The best value is usually obtained from the sample chamber measurement. Be sure to that the reported value of Rw is corrected to formation temperature before using in in the interpretation.

RW FROM WATER CATALOGUES: These catalogues are compiled by individual companies, professional societies (SPWLA, SPE), and state agencies (geological surveys, water boards). NOTE: Be sure to that the reported value of Rw is corrected to formation temperature before using in in the interpretation.

RW FROM LOCAL KNOWLEDGE: This is usually from the expertise of individuals with experience in a certain area. NOTE: Be sure to that the reported value of Rw is corrected to formation temperature before using in in the interpretation.

TEMPERATURE CORRECTIONS The Rwa, SP, or Pickett plot techniques produce values for Rw that are at formation temperature. The other sources for Rw will yield values or results which resistivities may not be measured at formation temperature. In order for Rw to be used properly in Archie’s equation, it must be corrected to formation temperature. The next section discusses the calculation of formation temperature and the temperature correction of fluid resistivities.

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

OH 26 Interpretation

Openhole Interpretation Temperature corrections Formation temperature can be found by the following equation:  BHT − AMST  FT =  ⋅ FD  + AMST TD  

OH.24

Where: FT = formation temperature BHT = bottom hole temperature AMST = annual mean surface temperature TD = total depth FD = formation depth Resistivity of a fluid at a desired temperature is: R FM =

RTk (Tk + 6.77 ) (TFM + 6.77 )

Where: RFM = resistivity at formation temperature TFM (in °F). RTk = known resistivity at a known temperature, Tk. Tk = known temperature (in °F).

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

OH.25

OH 27 Interpretation

Openhole Interpretation Mud filtrate resistivity, Rmf Mud filtrate resistivity is required for the calculation of Rw from the SP, and for the calculation of Sxo using Archie’s equation. Mud filtrate resistivity is measured at the wellsite at the time of logging and is reported as a resistivity measured at a specific temperature. Rmf must be corrected to formation temperature (using the temperature correction equations above) before being used in those calculations.

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

OH 28 Interpretation

Openhole Interpretation Determining true formation resistivity, Rt In the majority of cases, the deepest-reading measurement from either the induction log or the laterolog will very closely approximate the true undisturbed formation resistivity, Rt. The deep induction curve or the deep laterolog curve on older tools, or the deepest reading curve on “array” or “imaging” tools will be satisfactory. In the case of extreme invasion, unusual borehole fluids, or enlarged boreholes, environmental corrections may be required. Invasion corrections should be made under the following circumstances: If ILM/ILD > 1.2, correct ILD for invasion. IF LLD/LLS >1.05, correct LLD for invasion. Where: ILD = deep induction log reading ILM = medium induction log reading LLD = deep laterolog reading LLS = shallow laterolog reading Environmental corrections, if they are made, need to be made in the following order and circumstances: Correction

Induction Log

Laterolog

Borehole

If hole diameter > 10 in.

If hole diameter > 10 in. For LLS: hole diameter > 10 in. and Rt > 50 ohm.m

Mud Resistivity

Rm < 0.5 ohm.m

None

Bed Thickness

If thickness < 4 feet

If thickness < 4 feet

Invasion

When ILM/ILD > 1.2

When LLD/LLS > 1.05

(ILD is not corrected by more than 0.75)

(LLD is not corrected by more than 1.8)

Note that invasion corrections will yield a value of Rt less than ILD and a value of Rt greater than LLD.

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

OH 29 Interpretation

Openhole Interpretation Calculating formation water saturation: Sw and Sxo ARCHIE’S EQUATION Water saturation (Sw) of a reservoir's uninvaded zone is calculated by the Archie (1942) formula:

 a ⋅ Rw S w =  m  Rt ⋅ φ

  

1 n

OH.26

Where:

Sw = water saturation of the uninvaded zone Rw = resistivity of formation water at formation temperature Rt = true formation resistivity (i.e., Deep Induction or Deep Laterolog corrected for invasion) φ = porosity

a = tortuosity factor m = cementation exponent n = saturation exponent Water saturation of a formation's flushed zone (Sxo) is also based on the Archie equation, but two variables are changed: mud filtrate resistivity, Rmf, in place of formation water resistivity, Rw, and flushed zone resistivity, Rxo, in place of uninvaded zone resistivity, Rt. 1

S xo

 a ⋅ Rmf  n  =  m  ⋅ R φ  xo 

OH.27

Where: Sxo = water saturation of the flushed zone Rmf = resistivity of the mud filtrate at formation temperature Rxo = shallow resistivity from a very shallow reading device, such as Laterolog-8, Microspherically Focused Log, or Microlaterolog φ = porosity

a = tortuosity factor m = cementation exponent n = saturation exponent Water saturation of the flushed zone (Sxo) can be used as an indicator of hydrocarbon moveability. For example, if the value of Sxo is much larger than Sw, then hydrocarbons in the flushed zone have probably been moved or flushed out of the zone nearest the borehole by the invading drilling fluids (Rmf).

APPARENT WATER RESISTIVITY, Rwa Details of the Rwa technique are in the scanning and quicklook section. An Archie water saturation can also be calculated from the ratio of the Rwa values.

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

OH 30 Interpretation

Openhole Interpretation Sw =

Rwa minimum R wa zone

OH.28

Where the cementation exponent, n, in the equation above is assumed to be 2. A shortcut to the saturation calculation, used as a scanning aid, is: (Rwa zone/Rwa minimum) = 3 yields Sw = 0.58; (Rwa zone/Rwa minimum) = 4 yields Sw = 0.50; (Rwa zone/Rwa minimum) = 5 yields Sw = 0.45. Where a = 1.0 and m = 2.0.

PICKETT PLOTS Details of the Pickett plot technique are shown in the Determining water resistivity section. The water saturation of a point plotting away from the water-bearing line on the Pickett plot can be determined by the equation:

R S w =  o  Rt

1

n  

OH.29

In practice, this means reading the resistivity of the point (Rt) and the resistivity of the waterbearing line (Ro) at the same porosity value as the point, estimating a value for saturation exponent, n, and making the calculation. 1.00

Sw

Density porosity, porosity, DPHI

!

! !

!

!!

! ! !

0.10

30

50 70 100

Sw

0.01

0.10

1.00

10.00

True resistivity, Rt

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

100.00

OH 31 Interpretation

Openhole Interpretation SHALY SAND ANALYSIS Not long after the work of Archie and others in devising a method to quantify water saturation from logs, it became clear that there were limitations to the method, especially in formations containing shale and/or clay, and commonly referred to as “shaly sands”. The early literature tended to refer to the formations as containing “shale”, and a number of modifications were made to Archie’s equation which used shale volume (among other parameters) to account for those effects. Effects of clays and shales on logging measurements. Measurement

Effect

Spontaneous Potential, SP

Decrease in magnitude with respect to the shale baseline.

Gamma Ray

Increased radioactivity, shown as less movement away from the nearby shale values than an equivalent clean sand.

Sonic

A sonic porosity higher than the actual formation porosity due to the higher traveltime of the clays/shales.

Neutron

A neutron porosity higher than the actual formation porosity due to the water which is part of the clay structure, and which is adsorbed on the clay surfaces.

Density

A density porosity which is higher than the actual formation porosity due to the generally lower matrix densities of most clay minerals. If the matrix density of the clay is close to that of the formation matrix, there will be little or no effect on porosity.

Resistivity

A decrease in resistivity when compared to an equivalent clean formation, due to the conductivity of the clay. This will produce a calculated water saturation which is greater than the actual formation water saturation. (Archie’s equation assumes that all conductivity is from the formation water, and that the formation matrix is completely non-conducting.)

After the shale corrected porosity has been determined, the water saturation can be calculated. A variety of techniques are briefly introduced below. As with Archie’s equation, the substitution of Rmf for Rw and Rxo as Rt will yield calculations of Sxo instead of Sw. 1950’s The automatic compensation technique. It used the resistivity and sonic logs with Archie’s equation. Since the presence of shale caused the porosity, φS, to read too high and the resistivity, Rt, to read too low, one compensated for the other in the saturation equation:

S w = 0 .9

Rw / Rt

φS

OH.30

1960’s With the advent of the density log, the dispersed clay model gained popularity. In this model, the density was assumed to respond only to the liquid-filled porosity, while the sonic was affected by the clays, with the difference, q, being the fraction of the intergranular space filled with clay:

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

OH 32 Interpretation

Openhole Interpretation q=

φS − φD φS

OH.31

and the saturation given by: 2  0.8 ⋅ R q q w   + −   2 2  φ S ⋅ Rt  2   Sw =  (1 − q )

OH.32

1960’s and 1970’s A number of Vsh –based methods became popular, many of which are still being used. These included: Fertl, 1975: 2 a ⋅ Vsh  1  Rw  a ⋅ Vsh    + Sw = ⋅  − 2  φ  Rt  2   

OH.33

Where: a = 0.25 in the Gulf Coast, and a = 0.35 in the Rocky Mountains. Schlumberger, 1975:

Sw =

 Vsh   Rsh

2

 V φ2  + − sh 0.2 ⋅ Rw ⋅ Rt ⋅ (1 − Vsh ) Rsh 

φ2

OH.34

0.4 ⋅ Rw ⋅ (1 − Vsh ) Simandoux, 1963:

  0 .4 ⋅ R w    ⋅ S w =  2  φ   

 Vsh   Rsh

2   Vsh  5 ⋅φ 2  + − Rt ⋅ Rw Rsh   

OH.35

The Dual Water method is perhaps the most widely used of those techniques which go beyond the shale volume methods. This method is more fully described in Dewan (1983) and Bassiouni (1994). The bound and free water resistivities are determined from nearby shales and clean sands, and the apparent water resistivity, Rwa, in the sand of interest is calculated. The total (shale corrected) water saturation of the formation is:

S wt = b + b 2 +

Rw Rwa

Where:

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

7.48

OH 33 Interpretation

Openhole Interpretation b=

S wb (1 − (Rw Rb )) 2

7.49

The effective water saturation of the formation is:

S we =

S wt − S wb 1 − S wb

7.50

And the volumetric fraction of hydrocarbons is:

φ h = φ t (1 − S wt ) Where φt = total porosity (from the neutron and density).

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

7.51

Appendix

Appendix This section contains three listings: References with comments, an Annotated Bibliography, and Links of Interest.

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

Appendix

References The charts illustrated in this document were taken from the following sources. A copyright citation immediately follows each figure. Western Atlas Logging Services, 1985, Log Interpretation Charts, Rev. 12/95; Baker Atlas, Houston, Texas. Halliburton Energy Services, 1994, Log Interpretation Charts, Third Printing, Houston, Texas. Schlumberger, 1998, Log Interpretation Charts; Schlumberger Wireline and Testing, SMP-7006, Sugar Land, Texas.

The Tool Diagrams in each measurement section were taken from the Halliburton website in late 1999 and early 2000. They are intended to give the reader a general idea of the configuration and size of a “typical” logging tool of the particular measurement type. At the time that the figures were copied, the website was open to all interested parties. At present (Fall of 2003), much of the information on the website is open only to registered users. See www.halliburton.com

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

Biblio 1 Appendix

Annotated Bibliography Not all the resources listed here are accompanied by comments. Some resources are identified at the beginning of the citation as follows: G* General logging tools and techniques. C* Cased hole tools and techniques. O* Old (pre-1960’s) logging tools and techniques. M* Magazine with significant formation evaluation content. Also see Links of Interest for internet websites that were active at the time of publication of this document.

_____, 1984, Wireline Logging Tool Catalogue: Houston, Gulf Publishing Company. G* Asquith, George and Daniel Krygowski, in press, Basic Well Log Analysis: Tulsa, AAPG. A good introductory text. Provides general interpretive techniques without details of tool operation or interpretation pitfalls. Problems with solutions give a good opportunity for practice. G* Asquith, George, 1982, Basic Well Log Analysis for Geologists: Tulsa, AAPG. A good introductory text. Superceded by Asquith and Krygowski (in press). C* Bateman, Richard M., 1985, Cased Hole Analysis and Reservoir Performance Monitoring: Boston, IHRDC (most recently available through Prentiss-Hall). Bateman, Richard M., 1985, Log Quality Control: Boston, IHRDC (most recently available through Prentiss-Hall). G* Bateman, Richard M., 1985, Open Hole Log Analysis and Formation Evaluation: Boston, IHRDC (most recently available through Prentiss-Hall). A comprehensive book covering mud logging, coring, and MWD, as well as open hole logging. Detailed in tool operation and interpretation; contains occasional simple problems with answers. Bassiouni, Zaki, 1994, Theory, Measurement, and Interpretation of Well Logs: Richardson, Texas, SPE Textbook Series, Volume 4,. A comprehensive logging book for those who want to delve into the details of tool operation and interpretation. Bigelow, E. L., 1987, Fundamentals of Diplog Analysis: Houston, Atlas Wireline Services (now part of Baker Hughes). A good text regarding the interpretation of Atlas Diplogs, and the response of dipmeters to specific sedimentary environments. Brock, Jim, 1984, Analyzing Your Logs, Volume I: Tyler, Texas, Petro-Media. Brock, Jim, 1984, Analyzing Your Logs, Volume II: Tyler, Texas, Petro-Media.

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

Biblio 2 Appendix

Annotated Bibliography Crain, E. R., 1986, The Log Analysis Handbook, Volume 1: Quantitative Log Analysis Methods: Tulsa, PennWell Books. Desbrandes, Robert, 1985, Encyclopedia of Well Logging: Houston, Gulf Publishing Co. G* Dewan, John T., 1983, Essentials of Modern Open-Hole Log Interpretation: Tulsa, PennWell Books. A very good general coverage of open hole logging. Provides insight to tool operation and environmental effects without confusing details. Measurements are grouped on the basis of measurement goals (e.g., porosity) rather than the physical basis of the measurement. Doveton, John, 1986, Log Analysis of Subsurface Geology: Somerset, New Jersey, John Wiley & Sons. A good treatment of many of the geological aspects of logs. Begins with simple concepts and expands to relatively complex mathematical treatment of the data. Dresser Atlas, 1982, Well Logging and Interpretation Techniques, The Course for Home Study, Second Edition: Houston, Dresser Atlas. A self-paced course which does a relatively good job in introducing the basics of well logging. Concepts are reinforced with problems (answers are provided). Ellis, Darwin V., 1987, Well Logging for Earth Scientists: New York, Elsevier Science Publishing Co., Inc. A comprehensive general text with emphasis on the physics of logging measurements. G* Etnyre, Lee M., 1989, Finding Oil and Gas From Well Logs: New York, Van Nostrand Reinhold. A good general text which first addresses the formation physical properties to be measured, then the logging measurements. Problems (with answers) help the reader grasp the concepts presented. O* Frank, Rollyn W., 1986, Prospecting with Old E-Logs: Houston, Schlumberger Educational Services,. Helander, Donald P., 1983, Fundamentals of Formation Evaluation: Tulsa, OGCI Publications. Hearst, Joseph R., Philip H. Nelson, Frederick L. Paillett, 2000, Well Logging for Physical Properties, Second Edition: Chichester, John Wiley & Sons, Ltd. Emphasizes the physics behind logging measurements more than the interpretation. A good text for understanding measurement principals. O* Hilchie, Douglas W., 1979, Old Electrical Log Interpretation: Douglas Hilchie, Inc., Golden, CO. Reprinted by AAPG (2003). Hilchie, Douglas W., 1982, Applied Openhole Log Interpretation: Golden, Colorado, Douglas Hilchie, Inc. (out of print).

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

Biblio 3 Appendix

Annotated Bibliography Hilchie, Douglas W., 1987, The Geologic Well Log Interpreter: Boulder, Colorado, Douglas Hilchie, Inc. (out of print) Hilchie, Douglas W., 1989, Advanced Well Log Interpretation (1989 Edition): Boulder, Colorado, Douglas s Hilchie, Inc. (out of print) Hilchie, Douglas W., 1990, WIRELINE, A History of the Well Logging and Perforating Business in the Oil Fields: Boulder, Colorado, Douglas Hilchie, Inc. An interesting history drawn from many sources. Somewhat disjointed because of the company-by-company history approach, but entertaining and informative nevertheless. Johnson, David E. and Kathyrne E. Johnson, 1988, Well Logging for the Nontechnical Person: Tulsa, PennWell Publishing Company. Jorden, James R., and Frank L. Campbell, 1984, Well Logging I - Rock Properties, Borehole Environment, Mud and Temperature Logging: SPE Monograph Volume 9: Dallas, Texas, Society of Petroleum Engineers. Jorden, James R., and Frank L. Campbell, 1986, Well Logging II - Electric and Acoustic Logging: SPE Monograph Volume 10: Dallas, Texas, Society of Petroleum Engineers. Labo, J., 1987, A Practical Introduction to Borehole Geophysics: Tulsa, Society of Exploration Geophysicists; Geophysical References, Volume 2. O* Pirson, Silvain J., 1963, Handbook of Well Log Analysis: Englewood Cliffs, New Jersey, Prentiss-Hall. Although not intended as an "old E-log" book, its age makes it so. Has good information about interpreting the older logs. Pirson, Silvain J., 1970, Geologic Well Log Analysis: Houston, Gulf Publishing Company. Ransom, Robert C., 1995, Practical Formation Evaluation: New York, John Wiley & Sons, Inc. Rider, M. H., 1986, The Geological Interpretation of Well Logs: Glasgow, Blackie Halsted Press. Schlumberger, 1986, Dipmeter Interpretation (Publication SMP-7002): Houston, Schlumberger Well Services. Operational details and interpretation examples of Schlumberger dipmeter data and processing. C* Schlumberger, 1989, Cased Hole Log Interpretation Principles/Applications (Publication SMP7025): Houston, Schlumberger Well Services. Covers a wide range of cased hole and production logging measurements and their interpretation. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA

Biblio 4 Appendix

Annotated Bibliography G* Schlumberger, 1989, Log Interpretation Principles/Applications (Publication SMP-7017): Houston Schlumberger Well Services. Openhole log data acquisition and interpretation done the Schlumberger way. A good basic reference. Serra, Oberto, 1984, Fundamentals of Well-Log Interpretation; Volume 1, The Acquisition of Logging Data (Developments in Petroleum Science 15a): Amsterdam, The Netherlands, Elsevier Publishing Company. Much detail of measurement theory and tool operation (geared mostly to Schlumberger tools); almost nothing about interpretation. A very good reference for those interested in how and why logging tools work. Serra, Oberto, 1984, Fundamentals of Well-Log Interpretation; Volume 2, The Interpretation of Logging Data (Developments in Petroleum Science 15b): Amsterdam, The Netherlands, Elsevier Publishing Company. Covers many details of geologic interpretation and reservoir evaluation with a decided Schlumberger flavor. Serra, Oberto, 1985, Sedimentary Environments from Wireline Logs (Publication SMP-7008): Houston, Schlumberger Well Services. A detailed look at common sedimentary environments and the responses of logging tools (especially dipmeters) to them. Detailed, with many examples. M* Society of Exploration Geophysicists, monthly magazine, Geophysics: SEG, Tulsa. Rarely has logging papers; those appearing usually deal with tool theory. C* Society of Petroleum Engineers, 1985, SPE Reprint Series Number 19, Production Logging: Dallas, Society of Petroleum Engineers. A group of reprinted production logging papers. Society of Petroleum Engineers, 1986, SPE Reprint Series Number 21, Openhole Well Logging: Richardson, Texas, Society of Petroleum Engineers. A group of reprinted openhole well logging papers. M* Society of Petroleum Engineers, monthly magazine, Journal of Petroleum Technology (JPT): Richardson, Texas, Society of Petroleum Engineers. Occasional well logging and petrophysical papers of a more general nature than appear in SPE Formation Evaluation.

. O* Society of Professional Well Log Analysts, Houston Chapter, 1978, The Art of Ancient Log Analysis: Houston, SPWLA. Society of Professional Well Log Analysts, 1984, Glossary of Terms & Expressions Used in Well Logging, Second Edition: Houston, SPWLA,. A very good guide to sorting through the jargon of well logging; a good desk reference.

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

Biblio 5 Appendix

Annotated Bibliography

M* Society of Petrophysicists and Well Log Analysts, bimonthly magazine, Petrophysics (formerly The Log Analyst): Houston, SPWLA. Papers geared to well logging and petrophysics. Society of Petrophysicists and Well Log Analysts, yearly beginning ca. 1963, SPWLA Logging Symposium Transactions: Houston, SPWLA. (Now available on compact disk.) Copies of papers presented at the Annual Logging Symposium. Tittman, Jay, 1986, Geophysical Well Logging: New York, Academic Press, Inc.,. Although addressing data interpretation briefly, the book's strength lies in its explanation of the physics of logging tool measurements.

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

Links 1 Appendix

Links of Interest Wireline and MWD Companies Baker Atlas (a division of Baker Hughes) http://www.bakerhughes.com/bakeratlas (More technical information with login to BakerHughesDirect) Baker Hughes INTEQ (a division of Baker Hughes) http://www.bakerhughes.com/inteq/index.htm (More technical information with login to BakerHughesDirect) Halliburton Logging Services http://www.halliburton.com/oil_gas/sd0900.jsp (Technical information available only with login to MyHalliburton.) PathFinder Energy Services http://www.pathfinderlwd.com/main.html Precision Wireline Services (formerly Computalog) http://www.computalog.com/ Reeves Wireline http://www.reeves-wireline.com/ Schlumberger http://www.slb.com/Hub/ (“Premium content” available with login.) Schlumberger LWD http://www.slb.com/Hub/ (“Premium content” available with login.) Sperry-Sun (a division of Halliburton) http://www.halliburton.com/oil_gas/sd1318.jsp (Technical information available only with login to MyHalliburton.) Tucker Energy Services http://www.tuckerenergy.com/

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

Links 2 Appendix

Links of Interest Organizations Society of Petrophysicists and Well Log Analysts (SPWLA) http://www.spwla.org Petrotechnical Open Standards Consortium (POSC) http://www.posc.org

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

END Guide to Petrophysical Measurements, 2003