Guide to Petrophysical Interpretation

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(1)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..

(2) © 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.

(3) 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.

(4) 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.

(5) 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.

(6) 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.

(7) 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.

(8) SP 4 Correlation/Lithology. Spontaneous Potential Log Example. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(9) 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.

(10) 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.

(11) 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.

(12) 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.

(13) 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.

(14) 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.

(15) 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.

(16) 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.

(17) 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.

(18) 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.

(19) GR 4 Correlation/Lithology. Gamma Ray Log Example. Guide to Petrophysical Interpretation Daniel A. Krygowski, Austin Texas USA.

(20) 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.

(21) 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.

(22) 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.

(23) 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.

(24) 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.

(25) 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..

(26) 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.

(27) CAL 4 Correlation/Lithology. Caliper Log Example. Guide to Petrophysical Interpretation Daniel A. Krygowski, Austin Texas USA.

(28) 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.

(29) 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.

(30) 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.

(31) 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.

(32) 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.

(33) 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.

(34) 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.

(35) SON 4 Porosity. Sonic/Acoustic Log Example. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(36) SON 5 Porosity. Sonic/Acoustic Waveform display. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(37) SON 6 Porosity. Sonic/Acoustic Variable density display. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(38) 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.

(39) 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.

(40) 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.

(41) 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.

(42) 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.

(43) 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.

(44) 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.

(45) 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.

(46) DEN 4 Porosity. Density Log Example. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(47) 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.

(48) 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.

(49) 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.

(50) 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.

(51) 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.

(52) 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.

(53) 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.

(54) NEU 4 Porosity. Neutron Log Example. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(55) 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.

(56) 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.

(57) 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.

(58) NEU 8 Porosity. Neutron Neutron environmental corrections. © 1988 Schlumberger. Guide to Petrophysical Interpretation © 1995, 2000, 2003 Daniel A. Krygowski, Austin Texas USA.

(59) 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.

(60) 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.

(61) 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.

(62) 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.

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