log interpretation charts

8/21/2019 Log Interpretation Charts

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LogInterpretationCharts

2009 Edition REm

RInd

RLl

NMR

Neu

Dens

SP

GR

Gen

http://www.slb.com/content/services/evaluation/index.asp?



Contents

Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi

Genera

l

Symbols Used in Log Interpretation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-1 . . . . . . . . . . . . . . . . . . . . . . 1

Estimation of Formation Temperature with Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-2 . . . . . . . . . . . . . . . . . . . . . . 3

Estimation of Rmf and Rmc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-3 . . . . . . . . . . . . . . . . . . . . . . 4

Equivalent NaCl Salinity of Salts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-

4 . . . . . . . . . . . . . . . . . . . . . . 5

Concentration of NaCl Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-5 . . . . . . . . . . . . . . . . . . . . . . 6

Resistivity of NaCl Water Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-6 . . . . . . . . . . . . . . . . . . . . . . 8

Density of Water and Hydrogen Index of Water and Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-7 . . . . . . . . . . . . . . . . . . . . . . 9

Density and Hydrogen Index of Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-8 . . . . . . . . . . . . . . . . . . . . . 10

Sound Velocity of Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-9 . . . . . . . . . . . . . . . . . . . . . 11

Gas Effect on Compressional Slowness. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-9a . . . . . . . . . . . . . . . . . . . 12

Gas Effect on Acoustic Velocity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen

-9b . . . . . . . . . . . . . . . . . . . 13

Nuclear Magnetic Resonance Relaxation Times of Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-10 . . . . . . . . . . . . . . . . . . . 14

Nuclear Magnetic Resonance Relaxation Times of Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-11a . . . . . . . . . . . . . . . . . . 15

Nuclear Magnetic Resonance Relaxation Times of Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-11b . . . . . . . . . . . . . . . . . . 16

Capture Cross Section of NaCl Water Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-12 . . . . . . . . . . . . . . . . . . . 18

Capture Cross Section of NaCl Water Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-13 . . . . . . . . . . . . . . . . . . . 19

Capture Cross Section of Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-14 . . . . . . . . . . . . . . . . . . . 21

EPT* Propagation Time of NaCl Water Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-15 . . . . . . . . . . . . . . . . . . . 22

EPT Attenuation of NaCl Water Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-16 . . . . . . . . . . . . . . . . . . . 23EPT Propagation Time–Attenuation Crossplot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gen-16

a . . . . . . . . . . . . . . . . . . 24

Gamma Ray

Contents




arcVISION675* Gamma Ray—6.75-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-20 . . . . . . . . . . . . . . . . . . . . 39arcVISION825* Gamma Ray—8.25-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-21 . . . . . . . . . . . . . . . . . . . . 40

arcVISION900* Gamma Ray—9-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-22 . . . . . . . . . . . . . . . . . . . . 41

arcVISION475 Gamma Ray—4.75-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-23 . . . . . . . . . . . . . . . . . . . . 42



arcVISION900 Gamma Ray—9-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-26 . . . . . . . . . . . . . . . . . . . . 45

EcoScope* Integrated LWD Gamma Ray—6.75-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-27 . . . . . . . . . . . . . . . . . . . . 46

EcoScope Integrated LWD Gamma Ray—6.75-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GR-28 . . . . . . . . . . . . . . . . . . . . 47

Spontaneous Potent

ial

R weq Determination from ESSP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SP-1 . . . . . . . . . . . . . . . . . . . . . . 49

R weq versus R w and Formation Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SP-2 . . . . . . . . . . . . . . . . . . . . . . 50

R weq versus R w and Formation Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SP-3 . . . . . . . . . . . . . . . . . . . . . . 51

Bed Thickness Correction—Open Hole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SP-

4 . . . . . . . . . . . . . . . . . . . . . . 53Bed Thickness Correction—Open Hole (Empirical) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SP-5 . . . . . . . . . . . . . . . . . . . . . . 54

Bed Thickness Correction—Open Hole (Empirical) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SP-6 . . . . . . . . . . . . . . . . . . . . . . 55

Densit

y

Porosity Effect on Photoelectric Cross Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dens-1. . . . . . . . . . . . . . . . . . . . 56

Apparent Log Density to True Bulk Density . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dens-2. . . . . . . . . . . . . . . . . . . . 57

Neutron

Dual-Spacing Compensated Neutron Tool Charts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Compensated Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-1 . . . . . . . . . . . . . . . . . . . . . 60

Contents




Contents

adnVISION675* Azimuthal Density Neutron—6.75-in. Tool and 8-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-35 . . . . . . . . . . . . . . . . . . . 84adnVISION675 BIP Neutron—6.75-in. Tool and 8-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-36 . . . . . . . . . . . . . . . . . . . 85

adnVISION675 Azimuthal Density Neutron—6.75-in. Tool and 10-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-37 . . . . . . . . . . . . . . . . . . . 86

adnVISION675 BIP Neutron—6.75-in. Tool and 10-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-38 . . . . . . . . . . . . . . . . . . . 87

adnVISION825* Azimuthal Density Neutron—8.25-in. Tool and 12.25-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-39 . . . . . . . . . . . . . . . . . . . 88

CDN Compensated Density Neutron and adnVISION825s* Azimuthal Density Neutron—

8-in. Tool and 12-in. Borehole. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-40 . . . . . . . . . . . . . . . . . . . 89

CDN Compensated Density Neutron and adnVISION825s Azimuthal Density Neutron—8-in. Tool and 14-in. Borehole. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-41 . . . . . . . . . . . . . . . . . . . 90

CDN Compensated Density Neutron and adnVISION825s Azimuthal Density Neutron—

8-in. Tool and 16-in. Borehole. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-42 . . . . . . . . . . . . . . . . . . . 91

EcoScope* Integrated LWD BPHI Porosity—6.75-in. Tool and 8.5-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-43 . . . . . . . . . . . . . . . . . . . 93

EcoScope Integrated LWD BPHI Porosity—6.75-in. Tool and 9.5-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-44 . . . . . . . . . . . . . . . . . . . 94

EcoScope Integrated LWD TNPH Porosity—6.75-in. Tool and 8.5-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-45 . . . . . . . . . . . . . . . . . . . 95

EcoScope Integrated LWD TNPH Porosity—6.75-in. Tool and 9.5-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-46 . . . . . . . . . . . . . . . . . . . 96EcoScope Integrated LWD—6.75-in. Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Neu-47 . . . . . . . . . . . . . . . . . . . 98

Nuclear Magnetic Resonance

CMR* Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CM

R-1 . . . . . . . . . . . . . . . . . . . . 99

Resist

iv

ity L

aterolog

ARI* Azimuthal Resistivity Imager . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-1 . . . . . . . . . . . . . . . . . . . . 101

High-Resolution Azimuthal Laterolog Sonde (HALS). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-2 . . . . . . . . . . . . . . . . . . . . 102High-Resolution Azimuthal Laterolog Sonde (HALS). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-3 . . . . . . . . . . . . . . . . . . . . 103

High-Resolution Azimuthal Laterolog Sonde (HALS). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-

4 . . . . . . . . . . . . . . . . . . . . 104

Hi h R l ti A i th l L t l S d (HALS) RLl 5 105




CHFR* Cased Hole Formation Resistivity Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-50. . . . . . . . . . . . . . . . . . . 121CHFR Cased Hole Formation Resistivity Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-51. . . . . . . . . . . . . . . . . . . 122

CHFR Cased Hole Formation Resistivity Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RLl-52. . . . . . . . . . . . . . . . . . . 123

Resistiv ity Induction

AIT* Array Induction Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RInd-1 . . . . . . . . . . . . . . . . . . 125

AIT Array Induction Imager Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Resistiv ity Electromagnetic

arcVISION475 and ImPulse 43 ⁄ 4-in. Array Resistivity Compensated Tools—2 MHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REm-11 . . . . . . . . . . . . . . . . . 131




arcVISION675 63 ⁄ 4-in. Array Resistivity Compensated Tool—400 kHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REm-15 . . . . . . . . . . . . . . . . . 135




arcVISION675 63 ⁄ 4-in. Array Resistivity Compensated Tool—2 MHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REm-19 . . . . . . . . . . . . . . . . . 139







arcVISION825 81⁄4-in Array Resistivity Compensated Tool—400 kHz REm-26 146

Contents




Contents

arcVISION900 9-in. Array Resistivity Compensated Tool—2 MHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REm-38 . . . . . . . . . . . . . . . . . 158arcVISION675, arcVISION825, and arcVISION900 Array Resistivity Compensated Tools—400 kHz . . . . . . . . . . . . . . . . REm-55 . . . . . . . . . . . . . . . . . 160

arcVISION and ImPulse Array Resistivity Compensated Tools—2 MHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REm-56 . . . . . . . . . . . . . . . . . 161

arcVISION675 and ImPulse Array Resistivity Compensated Tools—2 MHz and 16-in. Spacing . . . . . . . . . . . . . . . . . . . . . REm-58 . . . . . . . . . . . . . . . . . 162





arcVISION675 and ImPulse Array Resistivity Compensated Tools—2 MHz with Dielectric Assumption . . . . . . . . . . . REm-63 . . . . . . . . . . . . . . . . . 167

Formation Resistiv ity

Resistivity Galvanic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-1 . . . . . . . . . . . . . . . . . . . . . 168

High-Resolution Azimuthal Laterlog Sonde (HALS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-2 . . . . . . . . . . . . . . . . . . . . . 169

High-Resolution Azimuthal Laterlog Sonde (HALS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-3 . . . . . . . . . . . . . . . . . . . . . 170

geoVISION675* Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-10 . . . . . . . . . . . . . . . . . . . . 171geoVISION675 Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-11 . . . . . . . . . . . . . . . . . . . . 172

geoVISION675 Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-12 . . . . . . . . . . . . . . . . . . . . 173

geoVISION675 Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-13 . . . . . . . . . . . . . . . . . . . . 174

geoVISION825* 81 ⁄ 4-in. Resistivity-at-the-Bit Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-14 . . . . . . . . . . . . . . . . . . . . 175

geoVISION825 81 ⁄ 4-in. Resistivity-at-the-Bit Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-15 . . . . . . . . . . . . . . . . . . . . 176



arcVISION Array Resistivity Compensated Tool—400 kHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-31 . . . . . . . . . . . . . . . . . . . . 179

arcVISION and ImPulse Array Resistivity Compensated Tools—2 MHz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rt-32 . . . . . . . . . . . . . . . . . . . . 180




Contents

Litholog yDensity and NGS* Natural Gamma Ray Spectrometry Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-1 . . . . . . . . . . . . . . . . . . . 193

NGS Natural Gamma Ray Spectrometry Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-2 . . . . . . . . . . . . . . . . . . . 194

Platform Express* Three-Detector Lithology Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-3 . . . . . . . . . . . . . . . . . . . 196

Platform Express Three-Detector Lithology Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-4 . . . . . . . . . . . . . . . . . . . 197

Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-5 . . . . . . . . . . . . . . . . . . . 198

Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-6 . . . . . . . . . . . . . . . . . . . 200

Environmentally Corrected Neutron Curves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-7 . . . . . . . . . . . . . . . . . . . 202

Environmentally Corrected APS Curves. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-8 . . . . . . . . . . . . . . . . . . . 204

Bulk Density or Interval Transit Time and Apparent Total Porosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-9 . . . . . . . . . . . . . . . . . . . 206

Bulk Density or Interval Transit Time and Apparent Total Porosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-10 . . . . . . . . . . . . . . . . . . 207

Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-11 . . . . . . . . . . . . . . . . . . 209

Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lith-12 . . . . . . . . . . . . . . . . . . 210

Porosity Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-1 . . . . . . . . . . . . . . . . . . . . 212

Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-2 . . . . . . . . . . . . . . . . . . . . 213

Density Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-3 . . . . . . . . . . . . . . . . . . . . 214

APS Near-to-Array (APLC) and Near-to-Far (FPLC) Logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-4 . . . . . . . . . . . . . . . . . . . . 216

Thermal Neutron Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-5 . . . . . . . . . . . . . . . . . . . . 217

Thermal Neutron Tool—CNT-D and CNT-S 21 ⁄ 2-in. Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-6 . . . . . . . . . . . . . . . . . . . . 218

adnVISION475 4.75-in. Azimuthal Density Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-7 . . . . . . . . . . . . . . . . . . . . 219






Contents

Density and APS Epithermal Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-25. . . . . . . . . . . . . . . . . . . 243Density, Neutron, and R xo Logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-26. . . . . . . . . . . . . . . . . . . 245

Hydrocarbon Density Estimation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Por-27. . . . . . . . . . . . . . . . . . . 246

Saturation

Porosity Versus Formation Resistivity Factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-1. . . . . . . . . . . . . . . . . 247

Spherical and Fracture Porosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-2. . . . . . . . . . . . . . . . . 248

Saturation Determination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-3. . . . . . . . . . . . . . . . . 250

Saturation Determination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-4. . . . . . . . . . . . . . . . . 252

Graphical Determination of S w from S wt and S wb. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-5. . . . . . . . . . . . . . . . . 253

Porosity and Gas Saturation in Empty Hole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-6. . . . . . . . . . . . . . . . . 254

EPT Propagation Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-7. . . . . . . . . . . . . . . . . 255

EPT Attenuation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatOH-8. . . . . . . . . . . . . . . . . 256

Capture Cross Section Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatCH-1 . . . . . . . . . . . . . . . . . 258

Capture Cross Section Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatCH-2 . . . . . . . . . . . . . . . . . 260RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 261

RST Reservoir Saturation Tool—1.6875 in. and 2.5 in. in 6.125-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatCH-3 . . . . . . . . . . . . . . . . . 262

RST Reservoir Saturation Tool—1.6875 in. and 2.5 in. in 9.875-in. Borehole . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SatCH-4 . . . . . . . . . . . . . . . . . 263

RST Reservoir Saturation Tool—1.6875 in. and 2.5 in. in 8.125-in. Borehole with 4.5-in. Casing at 11.6 lbm/ft . . . . SatCH-5 . . . . . . . . . . . . . . . . . 264

RST Reservoir Saturation Tool—1.6875 in. and 2.5 in. in 7.875-in. Borehole with 5.5-in. Casing at 17 lbm/ft . . . . . . SatCH-6 . . . . . . . . . . . . . . . . . 265

RST Reservoir Saturation Tool—1.6875 in. and 2.5 in. in 8.5-in. Borehole with 7-in. Casing at 29 lbm/ft . . . . . . . . . . . SatCH-7 . . . . . . . . . . . . . . . . . 266

RST Reservoir Saturation Tool—1.6875 in. and 2.5 in. in 9.875-in. Borehole with 7-in. Casing at 29 lbm/ft . . . . . . . . SatCH-8 . . . . . . . . . . . . . . . . . 267

Permeability

Permeability from Porosity and Water Saturation Perm-1 269




PorosityForeword

This edition of the Schlumberger “chartbook” presents severalinnovations.

First, the charts were developed to achieve two purposes:

Correct raw measurements to account for environmental effects

Early downhole measurements were performed in rather uniform

conditions (vertical wells drilled through quasi-horizontal thick

beds, muds made of water with a narrow selection of additives,

and limited range of hole sizes), but today wells can be highly

deviated or horizontal, mud contents are diverse, and hole sizes

range from 2 to 40 in. Environmental effects may be large. In

addition, they compound. It is essential to correct for these effects

before the measurements are used.

Use environmentally corrected measurements for interpretation

Charts related to measurements that are no longer performedare not included in this chartbook. However, because many oil and

gas companies use logs acquired years or even decades ago, the

second chartbook, Historical Log Interpretation Charts, contains

these old charts.

Why publish charts on paper in our electronic age? It is true that

software may be more effective than pencil to derive results. Even

more so, this chartbook cannot cope with the complex well situations

that are encountered. Using software is the only way to proceed.

Thus, the chartbook has two primary functions: Training

The chartbook is essential for educating junior petrophysicists

about the different effects on the measurements. In the interpre-

tation process, the chartbook unveils the relationships between

the different parameters.

Sensitivity analysis

A chart gives the user a graphical idea of the sensitivity of an out-

put to the various inputs (see Chart Gen-1). The visual presenta-

tion is helpful for determining if an input parameter is critical.

The user can then focus on the most sensitive inputs.

Foreword



Gen

General

Symbols Used in Log InterpretationGen-1

(former Gen-3)

di

dj

h

Adjacent bed

Zone of transition

orannulus

Flushedzone

Adjacent bed

(Bed thickness)

Mud

hmc

dh

Rm

Rs

Rs

Resistivity of the zone

Resistivity of the water in the zone

Water saturation in the zone

Rmc

Mudcake

Rmf

Sxo

Rxo

Rw

Sw

R t

Ri

Uninvadedzone



General

Gen

Estimation of Formation Temperature with Depth

PurposeThis chart has a twofold purpose. First, a geothermal gradient can

be assumed by entering the depth and a recorded temperature at

that depth. Second, for an assumed geothermal gradient, if the tem-

perature is known at one depth in the well, the temperature at

another depth in the well can be determined.

Description

Depth is on the y-axis and has the shallowest at the top and the

deepest at the bottom. Both feet and meters are used, on the left

and right axes, respectively. Temperature is plotted on the x-axis,

with Fahrenheit on the bottom and Celsius on the top of the chart.

The annual mean surface temperature is also presented in

Fahrenheit and Celsius.

ExampleGiven: Bottomhole depth = 11,000 ft and bottomhole tempera-

ture = 200°F (annual mean surface temperature = 80°F).

Find: Temperature at 8,000 ft.

Answer: The intersection of 11,000 ft on the y-axis and 200°F

on the x-axis is a geothermal gradient of approximately

1.1°F/100 ft (Point A on the chart).

Move upward along an imaginary line parallel to the con-

structed gradient lines until the depth line for 8,000 ft isintersected. This is Point B, for which the temperature

on the x-axis is approximately 167°F.



General

Gen

General

Estimation of Formation Temperature with DepthGen-2

(former Gen-6)

27 50 75 100 125 150 175

16 25 50 75 100 125 150 175

Temperature (°C)

Temperature gradient conversions: 1°F/100 ft = 1.823°C/100 m 1°C/100 m = 0.5486°F/100 ft

Depth

(thousands

of feet)

Depth(thousandsof meters)

Annual meansurface temperature

5

10

15

20

1

2

3

4

5

6

0.6 0.8 1.0 1.2 1.4 1.6°F/100 ft

1.09 1.46 1.82 2.19 2.55 2.92°C/100 m

B

A

Geothermal gradient



General

Gen

Estimation of Rmf and Rmc

Fluid Properties Gen-3

(former Gen-7)

PurposeDirect measurements of filtrate and mudcake samples are preferred.

When these are not available, the mud filtrate resistivity (Rmf ) and

mudcake resistivity (Rmc) can be estimated with the following

methods.

Description

Method 1: Lowe and Dunlap

For freshwater muds with measured values of mud resistivity (R m)

between 0.1 and 2.0 ohm-m at 75°F [24°C] and measured values of mud density (ρm) (also called mud weight) in pounds per gallon:

Method 2: Overton and Lipson

For drilling muds with measured values of Rm between 0.1 and

10.0 ohm-m at 75°F [24°C] and the coefficient of mud (K m) given

as a function of mud weight from the table:

ExampleGiven: Rm = 3.5 ohm-m at 75°F and mud weight = 12 lbm/gal

[1,440 kg/m3].

Find: Estimated values of Rmf and Rmc.

Answer: From the table, K m = 0.584.

Rmf = (0.584)(3.5)1.07 = 2.23 ohm-m at 75°F.

Rmc = 0.69(2.23)(3.5/2.23)2.65 = 5.07 ohm-m at 75°F.

log .= . .R

Rmf

mm

− ×( )0 396 0 0475 ρ

R K R

R RR

R

mf m m

mc mf m

mf

= ( )

= ( )

1 07

2 65

0 69

.

.

. .

Mud Weight

lbm/gal kg/m3 Km

10 1,200 0.847

11 1,320 0.708

12 1,440 0.584

13 1,560 0.488

14 1,680 0.412

16 1,920 0.380

18 2,160 0.350



10 20 50 100 200 500 1,000 2,000 5,000 10,000 20,000 50,000 100,000 300,000

2.0

1.5

1.0

0.5

0

–0.5

2.0

1.0

0

Total solids concentration (ppm or mg/kg)

Multiplier

† Multipliers that do not vary appreciably for low concentrations

Li (2.5)†

NH4 (1.9)†

Na and CI (1.0)

NO3 (0.55)†

Br (0.44)†

I (0.28)†

OH (5.5)†

Mg

Mg

K

K

Ca

Ca

CO3

CO3

SO4

SO4

HCO3

HCO3

General

Gen

Equivalent NaCl Salinity of SaltsGen-4

(former Gen-8)



Gen

General

Concentration of NaCl SolutionsGen-5

g/L at

77°F

ppm grains/gal

at 77°F °F/100 ft °C/100 ft °API

Oil GravityConcentrations of NaCl Solutions

Temperature Gradient

Conversion

Specific

gravity (sg) at 60°F

Density of NaCl

solution at

77°F [25°C]

0.15 150

200

300

400

500

600

800

1,000

1,500

2,000

3,000

4,000

5,000

6,000

8,000

10,000

101.00

1.005

2.0

2.5

3.0

0.60

0.62

0.64

0.66

0.68

0.70

0.72

0.74

0.76

0.78

0.80

0.82

0.84

0.860.88

0.900.920.940.960.98

3.5

1.1

1.2

1.3

1.4

1.5

1.6

1.7

100

90

80

70

60

50

40

30

20

1.8

1.9

2.0

12.5

15

20

25

30

40

50

60708090100

125

150

200

250

300

400

500

600

0.2

0.3

0.4

0.5

0.6

0.8

1.0

1.5

2

3

4

5

6

8

10



Gen

General

Resistivity of NaCl Water Solutions

PurposeThis chart has a twofold purpose. The first is to determine the resis-

tivity of an equivalent NaCl concentration (from Chart Gen-4) at a

specific temperature. The second is to provide a transition of resis-

tivity at a specific temperature to another temperature. The solution

resistivity value and temperature at which the value was determined

are used to approximate the NaCl ppm concentration.

Description

The two-cycle log scale on the x-axis presents two temperature

scales for Fahrenheit and Celsius. Resistivity values are on the left

four-cycle log scale y-axis. The NaCl concentration in ppm and

grains/gal at 75°F [24°C] is on the right y-axis. The conversion

approximation equation for the temperature (T) effect on the

resistivity (R) value at the top of the chart is valid only for the

temperature range of 68° to 212°F [20° to 100°C].

Example OneGiven: NaCl equivalent concentration = 20,000 ppm.

Temperature of concentration = 75°F.

Find: Resistivity of the solution.

Answer: Enter the ppm concentration on the y-axis and the tem-

perature on the x-axis to locate their point of intersec-

tion on the chart. The value of this point on the left

y-axis is 0.3 ohm-m at 75°F.

Example TwoGiven: Solution resistivity = 0.3 ohm-m at 75°F.

Find: Solution resistivity at 200°F [93°C].

Answer 1: Enter 0.3 ohm-m and 75°F and find their intersection

on the 20,000-ppm concentration line. Follow the line to

the right to intersect the 200°F vertical line (interpolate

between existing lines if necessary). The resistivity value

for this point on the left y-axis is 0.115 ohm-m.

Answer 2: Resistivity at 200°F = resistivity at 75°F×

[(75 + 6.77)/

(200 + 6.77)] = 0.3 × (81.77/206.77) = 0.1186 ohm-m.



General

Gen

Resistivity of NaCl Water SolutionsGen-6

(former Gen-9)

Resistivity

of solution

(ohm-m)

ppm

10

8

6

5

4

3

2

1

0.8

0.6

0.5

0.4

0.3

0.2

2 0 0

3 0 0

4 0 0

5 0 0

6 0 0 7 0 0 8 0 0

1 , 0 0 0 1 , 2 0 0 1 , 4 0 0 1 , 7 0 0 2 , 0 0 0

3 , 0 0 0

4 , 0 0 0

5 , 0 0 0 6 , 0 0 0 7 , 0 0 0 8 0

Conversion approximated by R2 = R1 [(T1 + 6.77)/(T2 + 6.77)]°F or R2 = R1 [(T1 + 21.5)/(T2 + 21.5)]°C

NaClconcentration

(ppm or

grains/gal)

grains/galat 75°F

10

15

20

25

30

4050

100

150

200250

300

400



General

Gen

Density of Water and Hydrogen Index of Water and HydrocarbonsGen-7

1.20

Pressure NaCl

14.7 psi1,000 psi7,000 psi

25 50 100

Temperature (°C)

Temperature (°F)

Hydrogen Index of Salt Water

Hydrogen Index of Live Hydrocarbons and Gas

Salinity (kppm or g/kg)

150 200

0.8544040030020010040

Hydrocarbons

Water

0.90

0.95

1.00

1.05

1.10

1.15

1.05

1.2

1.0

0.6

0.8

1.00

0.95

0.90

0.850 50 100 150 200 250

Waterdensity(g/cm3)

Hydrogenindex

Hydrogenindex

2 5 0 , 0 0 0 p p m

2 0 0 , 0 0 0 p p m

1 5 0 , 0 0 0 p p m

1 0 0 ,0 0 0 p p m

5 0 ,0 0 0 p p m

D i s t i l l e d w a t e r



General

Gen

Density and Hydrogen Index of Natural GasGen-8

0.3

0.4

0.5

17,500

15,00012,500

10,000

7,500

Pressure (psi)

Gas gravity = 0.65

Gas

density

Gas pressure × 1,000 (psia)

0

0.1

0.2

0.3

0.7

Hgas

Gas tempera ture

(°F)

Gas gravity = 0.6(Air = 1.0)

0.6100

150

200250300350

0.5

0.4

0.3

0.2

0.1

0

0 2 4 6 8 10

Gas

density(g/cm3)



General

Gen

General

Sound Velocity of HydrocarbonsGen-9

Gas gravity = 0.65

Natural Gas

50 100 150 200 250 300 3500

1,000

2,000

3,000

4,000

5,000 200

250

30017,500

15,000

12,500

10,000

7,500

5,000

2,500

14.7

400

500

1,000

2,000

Temperature (°C)

Pressure (psi)

Tempera ture (°F)

Soundvelocity

(ft /s)

Soundslowness

(µs /ft)

0 50 100 150 200

© Schlumberger



Gas Effect on Compressional Slowness

General

Gen-9a

Gen

1000

200

100

200 µs/ft

110 µs/ft

90 µs/ft

70 µs/ft

50

∆ tc(µs/ft)

We tsand

Sandstone

80604020

Wood’s law (e = 5) Power law (e = 3)

Liquid saturation (%)

© Schlumberger



General

Gas Effect on Acoustic VelocitySandstone and Limestone

Gen-9b

Limestone

Sandstone

25

00

5

10

10

15

20

20

25

30 40

20

15

Porosi ty (p.u.)

Velocity(1,000 × ft/s)

Vp

Vs

No gasGas bearing

No gasGas bearing

Gen



General

Gen

PurposeLongitudinal (Bulk) Relaxation Time of Pure Water

This chart provides an approximation of the bulk relaxation time

(T1) of pure water depending on the temperature of the water

DescriptionLongitudinal Relaxation Time

The chart relation is for pure water—the additives in drilling fluids

reduce the relaxation time (T1) of water in the invaded zone The

Nuclear Magnetic Resonance Relaxation Times of WaterGen-10

Longitudinal (Bulk) RelaxationTime of Water

Temperature (°C)

Relaxation time (s)

100

10

1.0

0.1

0.0120 60 100 140 180

T1

Transverse (Bulk and Diffusion)Relaxation Time of Water

Temperature (°C)

Relaxation time (s)

100

10

1.0

0.1

0.0120 60 100 140 180

T2

(TE = 0.2 ms)

T2 (TE = 0.32 ms)

T2 (TE = 1 ms)

T2 (TE = 2 ms)

© Schlumberger



General

Gen

Nuclear Magnetic Resonance Relaxation Times of HydrocarbonsGen-11a

Transverse (Bulk and Diffusion) Relaxation Time of Crude Oil

T1

(s)

Longitudinal (Bulk) RelaxationTime of Crude Oil

Viscosity (cp)

0.1 1 10 100 1,000 10,000 100,000

0.001

0.01

0.1

1

10

0.0001

T2 (s)

Viscosity (cp)

0.1 1 10 100 1,000 10,000 100,000

0.001

0.01

0.1

1

10

0.0001

Diffusion(cm2 /s)

Hydrocarbon Diffusion Coefficient10–3

10–4

10–5

0

Oil (9° at 20°C)

Oil (40° at 20°C)

Diffusion(10–5 cm2 /s)

Water Diffusion Coefficient

10

15

20

Light oil: 45°–60° API 0.65–0.75 g/cm3

Medium oil: 25°–40° API 0.75–0.85 g/cm3

Heavy oil: 10°–20° API 0.85–0.95 g/cm3

TE = 0.2 msTE = 0.32 msTE = 1 msTE = 2 ms

T1



General

Nuclear Magnetic Resonance Relaxation Times of HydrocarbonsGen-11b

0.6

0.8

1.0

1.2

Hydrogenindex

Hydrogen Index of Live Hydrocarbons and Gas

0

2

4

6

0 6,000 9,000

25°C75°C125°C175°C

Longitudinal (Bulk) RelaxationTime of Methane

Pressure (psi)

3,000 12,000

10

8

Transverse (Bulk and Diffusion)Relaxation Time of Methane

100

1

10

T2 (s)TE 0 32

TE = 0.2 ms

T1 (s)

10

15

20

25

30

35

50 100 150 200

Methane Diffusion Coefficient

Diffusion(10–4 cm2 /s)

Temperature (°C)

1,600 psi

3,000

0

0

5

8,300

15,500

22,800

3,900

4,500

Gen

General



General

Capture Cross Section of NaCl Water Solutions

GenPurposeThe sigma value (Σ w ) of a saltwater solution can be determined from

this chart. The sigma water value is used to calculate the water satu-

ration of a formation.

Description

Charts Gen-12 and Gen-13 define sigma water for pressure condi-

tions of ambient through 20,000 psi [138 MPa] and temperatures

from 68° to 500°F [20° to 260°C]. Enter the appropriate chart for

the pressure value with the known water salinity on the y-axis andmove horizontally to intersect the formation temperature. The sigma

of the formation water for the intersection point is on the x-axis.

ExampleGiven: Water salinity = 125,000 ppm, temperature = 68°F at

ambient pressure, and formation temperature = 190°F

at 5,000 psi.

Find: Σ w at ambient conditions and Σ w of the formation.

Answer: Σ w = 69 c.u. and Σ w of the formation = 67 c.u.

If the sigma water apparent (Σ wa ) is known from a clean water

sand, then the salinity of the formation can be determined by enter-

ing the chart from the sigma water value on the x-axis to intersectthe pressure and temperature values.



General

Gen

A m b i e

n t

2 0 0 °

F [ 9 3

° C ]

6 8 ° F

[ 2 0 °

C ]

4 0 0 °

F [ 2 0 5 °

C ]

3 0 0 °

F [ 1 5

0 ° C ]

2 0 0 °

F [ 9 3

° C ]

6 8 ° F

[ 2 0 °

C ]

4 0 0 °

F [ 2 0 5 °

C ]

3 0 0 °

F [ 1 5

0 ° C ]

2 0 0 °

F [ 9 3

° C ]

6 8 ° F

[ 2 0 °

C ]

1 , 0 0 0

p s i [ 6 . 9 M P a ]

0 p s i [ 3

4 M P a ]

300

275

250

225

200

175

150

125

100

75

50

25

0

100

75

50

300

275

250

225

200

300

275

250

225

200

300

275

250

225

200

125

150

175175

150

125

Equivalent water salinity(1,000 × ppm NaCl)

Capture Cross Section of NaCl Water SolutionsGen-12

(former Tcor-2a)



General

Capture Cross Section of NaCl Water SolutionsGen-13

(former Tcor-2b)

Gen

1 0 , 0 0 0 p s i

[ 6 9 M P a ]

5 0 0 ° F [

2 6 0 ° C ]

4 0 0 ° F [

2 0 5 ° C ]

3 0 0 ° F [

1 5 0 ° C ]

2 0 0 ° F [

9 3 ° C

]

6 8 ° F

[ 2 0 ° C ]

4 0 0 ° F [

2 0 5 ° C ]

3 0 0 ° F [

1 5 0 ° C ]

2 0 0 ° F [

9 3 ° C

]

6 8 ° F

[ 2 0 ° C ]

4 0 0 ° F [

2 0 5 ° C ]

3 0 0 ° F [

1 5 0 ° C ]

2 0 0 ° F [

9 3 ° C

]

6 8 ° F

[ 2 0 ° C ]

1 5 , 0 0 0 p

s i [ 1 0 3

M P a ]

ps i [ 1

3 8 M P a ]

300

275

250

225

200

175

150

125

100

75

50

25

0

100

75

50

300

275

250

225

200

300

275

250

225

200

300

275

250

225

200

Equivalent water salinity(1,000 × ppm NaCl)

125

150

175175

150

125



PurposeSigma hydrocarbon (Σh) for gas or oil can be determined by using

this chart. Sigma hydrocarbon is used to calculate the water satura-

tion of a formation.

DescriptionOne set of charts is for measurement in metric units and the other

is for measurements in “customary” oilfield units.

For gas, enter the background chart of a chart set with the reser-

voir pressure and temperature. At that intersection point move left

to the y-axis and read the sigma of methane gas.For oil, use the foreground chart and enter the solution gas/oil

ratio (GOR) of the oil on the x-axis. Move upward to intersect the

appropriate API gravity curve for the oil. From this intersection

point, move horizontally left and read the sigma of the oil on

the y-axis.

ExampleGiven: Reservoir pressure = 8,000 psi, reservoir temperature =

300°F, gravity of reservoir oil = 30°API, and solution

GOR = 200.

Find: Sigma gas and sigma oil.

Answer: Sigma gas = 10 c.u. and sigma oil = 21.6 c.u.

General

Gen

Capture Cross Section of Hydrocarbons



General

Gen

Capture Cross Section of HydrocarbonsGen-14

(former Tcor-1)

20.0

17.5

15.0

12.5

10.0

7.5

5.0

2.5

0

6 8

1 2 5

2 0 0

3 0 0

4 0 0

5 0 0

Reservoir pressure (psia)

0 4,000 8,000 12,000 16,000 20,000

Methane

Temperature (°F)

Σh (c.u.)

Customary

10 100 1,000 10,000

Solution GOR (ft3 /bbl)

Liquid hydrocarbons

C o n d e n s a t e

30°, 40°, and 50°API

20° and 60°API

16

18

20

22

Σh (c.u.)

20.0

Reservoir pressure (mPa)

0 14 28 41 55 69 83 97 110 124 138



General

EPT* Propagation Time of NaCl Water SolutionsGen-15

(former EPTcor-1)

90

80

70

60

50

40

30

tpw (ns/m)

120°C250°F

100°C200°F

80°C175°F

40°C100°F

150°F 60°C

75°F 20°C

125°F

Gen



General

Gen

EPT* Attenuation of NaCl Water SolutionsGen-16

(former EPTcor-2)

0 50 100 150 200 250

Equivalent water salinity (kppm or g/kg NaCl)

–40

–60

–80

120°C250°F100°C200°F 80°C175°F

40°C100°F

150°F 60°C

75°F 20°C

125°F

5,000

4,000

3,000

2,000

1,000

0

Attenuation,Aw

(dB/m)

EPT-D Spreading Loss



General

Gen

EPT* Propagation Time–Attenuation CrossplotSandstone Formation at 150°F [60°C]

Gen-16a

1,000

900

800

700

600

500

400

300

200

100

0

7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

1.0

40 50302010

2.0

5.010.0

50.0

Attenuation(dB/m)

tpl (ns/m)

Sandstone at 150°F [60°C]

Rmfa from EPT log (ohm-m)

E P T

p o r o

s i t y

( φ E P T )

0.02 0.05

0.1

0.2

0.5

*Mark of Schlumberger



Gamma Ray—Wireline

Scintillation Gamma Ray—33 ⁄ 8- and 111 ⁄ 16-in. ToolsGamma Ray Correction for Hole Size and Barite Mud Weight

GR–1(former GR-1)

10.0

7.0

5.0

3.0

2.0

1.0

0.7

0.5

0.3

Correctionfactor

t (g/cm2)

0 5 10 15 20 25 30 35 40

Scintillation Gamma Ray

33 ⁄ 8-in. tool, centered


33 ⁄ 8-in. tool, eccentered


GR




Scintillation Gamma Ray—33 ⁄ 8- and 111 ⁄ 16-in. ToolsGamma Ray Correction for Barite Mud in Various-Size Boreholes

GR-2(former GR-2)

1.2

1.0

0.8

0.6

0.4

0.2

0

Mud weight (lbm/gal)

7 8 9 10 11 12 13 14 15 16 17 18 19 20

1.2

1.0

0.8

0.6

0.4

0.2

0

Fbh

Bmud





33 ⁄ 8-in. tool

111 ⁄ 16-in. tool

GR




Scintillation Gamma Ray—33 ⁄ 8- and 111 ⁄ 16-in. ToolsBorehole Correction for Cased Hole

GR-3(former GR-3)

10.0

7.0

5.0

3.0

2.0

1.0

0.7

0.5

0.3

Correctionfactor

0 5 10 15 20 25 30 35 40

Scintillation Gamma Ray

33 ⁄ 8-in. tool

111 ⁄ 16-in. tool

GR



Gamma Ray—LWD

SlimPulse* and E-Pulse* Gamma Ray ToolsBorehole Correction for Open Hole

GR-6

11

10

9

8

7

6

5

4

3

2

1

0

Correctionfactor

6-in. bit7-in. bit

8.5-in. bit

9.875-in. bit

12.25-in. bit

13.5-in. bit

17.5-in. bit

GR



Gamma Ray—LWD

ImPulse* Gamma Ray— 4.75-in. ToolBorehole Correction for Open Hole

GR-7

1.75

1.50

1.25

1.00

0.75

Correctionfactor

8.5-in. bit

7-in. bit

6-in. bit

GR



Gamma Ray—LWD

PowerPulse* and TeleScope* Gamma Ray—6.75-in. ToolsBorehole Correction for Open Hole

GR-9

3.00

2.75

2.50

2.25

2.00

1.75

1.50

1.25

1 00

Correc tionfac tor

PowerPulse and TeleScope Gamma Ray

8.5-in. bit

8.75-in. bit

10.625-in. bit

9.875-in. bit

12.25-in. bit

GR



Gamma Ray—LWD

PowerPulse* Gamma Ray—8.25-in. Normal-Flow ToolBorehole Correction for Open Hole

GR-10

5.00

4.75

4.50

4.25

4.00

3.75

3.50

3.25

3.00

2.75

2 50

Correction

factor

9.875-in. bit

12.25-in. bit

13.5-in. bit

17.5-in. bit

10.625-in. bit

14.75-in. bit

GR



Gamma Ray—LWD

PowerPulse* Gamma Ray—8.25-in. High-Flow ToolBorehole Correction for Open Hole

GR-11

4.25

4.00

3.75

3.50

3.25

3.00

2.75

2.50

2.25

2.00

1.75

Correctionfactor

17.5-in. bit

14.75-in. bi t

13.5-in. bit

12.25-in. bit

10.625-in. bit

9.875-in. bit

GR



Gamma Ray—LWD

PowerPulse* Gamma Ray—9-in. ToolBorehole Correction for Open Hole

GR-12

7.50

7.00

6.50

6.00

5.50

5.00

4.50

4.00

3.50

3.00

2.50

Correctionfactor 17.5-in. bit

14.75-in. bit

13.5-in. bit

12.25-in. bit

10.625-in. bit

22-in. bit

GR



Gamma Ray—LWD

PowerPulse* Gamma Ray—9.5-in. Normal-Flow ToolBorehole Correction for Open Hole

GR-13

8.00

7.50

7.00

6.50

6.00

5.50

5.00

4.50

4.00

3.50

3.00

Correctionfactor

17.5-in. bit

14.75-in. bit

13.5-in. bit

12.25-in. bit

10.625-in. bit

22-in. bi t

GR



Gamma Ray—LWD

PowerPulse* Gamma Ray—9.5-in. High-Flow ToolBorehole Correction for Open Hole

GR-14

8.00

7.50

7.00

6.50

6.00

5.50

5.00

4.50

4.00

3.50

3.00

2.50

2.00

Correctionfactor

10.625-in. bit

12.25-in. bit

13.5-in. bit

14.75-in. bit

17.5-in. bit

22-in. bit

GR

G R LWD



Gamma Ray—LWD

geoVISION675* GVR* Gamma Ray—6.75-in. ToolBorehole Correction for Open Hole

GR-15

2.75

2.50

2.25

2.00

1.75

1.50

1.25

1.00

0.75

Correctionfactor

8.5-in. bit8.75-in. bit

9.875-in. bit

10.625-in. bit

12.25-in. bit

GR

G R LWD



Gamma Ray—LWD

RAB* Gamma Ray—8.25-in. ToolBorehole Correction for Open Hole

GR-16

3.00

2.75

2.50

2.25

2.00

1.75

1.50

1.25

1.00

0.75

0.50

Correctionfactor

9.875-in. bit

10.625-in. bit

12.25-in. bit

13.5-in. bit

14.75-in. bit

17.5-in. bit

GR

G R LWD



Gamma Ray—LWD

arcVISION475* Gamma Ray—4.75-in. ToolBorehole Correction for Open Hole

GR-19

1.75

1.50

1.25

1.00

0.75

Correctionfactor

8.5-in. bit

7-in. bit

6-in. bit

GR

G R LWD



Gamma Ray—LWD


GR-20

3.50

3.25

3.00

2.75

2.50

2.25

1.75

2.00

1.50

1.25

1.00

0.75

0.50

Correctionfactor

8.5-in. bit

8.75-in. bit

9.875-in. bit

10.625-in. bit

12.25-in. bit

GR

Gamma Ray LWD



Gamma Ray—LWD


GR-21

3.00

2.75

2.50

2.25

2.00

1.50

1.75

1.25

1.00

0.75

0.50

Correctionfactor

9.875-in. bit

10.625-in. bit

12.25-in. bit

13.5-in. bit

14.75-in. bit

17.5-in. bit

GR

Gamma Ray LWD



Gamma Ray—LWD

arcVISION900* Gamma Ray—9-in. ToolBorehole Correction for Open Hole

GR-22

5.5

5.0

4.5

4.0

3.5

2.5

3.0

2.0

1.5

1.0

0.5

Correctionfactor

10.625-in. bit

12.25-in. bit

13.5-in. bit

14.75-in. bit

17.5-in. bit

22-in. bit

GR

Gamma Ray LWD



Gamma Ray—LWD

arcVISION475* Gamma Ray—4.75-in. ToolPotassium Correction for Open Hole

GR-23

100

90

80

70

60

40

50

30

20

10

0

Correctionsubtracted for 5-wt%potassium

(gAPI)

8.3 ppg

9 ppg10 ppg

12 ppg14 ppg

16 ppg18 ppg

20 ppg

GR

Gamma Ray—LWD



Gamma Ray—LWD


GR-24

50

45

40

35

30

20

25

15

10

5

0

Correctionsubtractedfor 5-wt%potassium

(gAPI)

9 ppg

8.3 ppg

10 ppg

12 ppg

14 ppg

16 ppg

18 ppg

20 ppg

GR

Gamma Ray—LWD



Gamma Ray LWD


GR-25

100

90

80

70

60

40

50

30

20

10

0


(gAPI)

10 ppg

9 ppg

8.3 ppg

12 ppg

14 ppg

16 ppg

18 ppg

20 ppg

GR

Gamma Ray—LWD



Gamma Ray LWD

arcVISION900* Gamma Ray—9-in. toolPotassium Correction for Open Hole

GR-26

120

100

80

60

40

20

0


(gAPI)

10 ppg

9 ppg

8.3 ppg

12 ppg

14 ppg

16 ppg

18 ppg

20 ppg

GR

Gamma Ray—LWD



Gamma Ray LWD

EcoScope* Integrated LWD Gamma Ray—6.75-in. ToolBorehole Correction for Open Hole

GR-27

3.00

2.75

2.50

2.25

2.00

1.50

1.75

1.25

1.00

0.75

0.50

Correctionfactor

9.875-in. bit

10.625-in. bit

12.25-in. bit

8.5-in. bit

8.75-in. bit

GR

Gamma Ray–Wireline

Gamma Ray—LWD



50

45

40

35

30

20

25

15

10

5

0

Correc tionsubtrac tedfor 5-wt%potassium

(gAPI)

9 ppg

8.3 ppg

10 ppg

12 ppg

14 ppg

16 ppg

18 ppg

20 ppg

Gamma Ray Wireline

GR

Gamma Ray LWD

EcoScope* Integrated LWD Gamma Ray—6.75-in. ToolPotassium Correction for Open Hole

GR-28

Spontaneous Potential—Wireline



p

SP

Rweq Determination from ESSP

Purpose

This chart and nomograph are used to calculate the equivalent for-mation water resistivity (R weq) from the static spontaneous potential

(ESSP) measured in clean formations. The value of R weq is used in

Chart SP-2 to determine the resistivity of the formation water (R w ).

R w is used in Archie’s water saturation equation.

DescriptionEnter the chart with ESSP in millivolts on the x-axis and move

upward to intersect the appropriate temperature line. From the

intersection point move horizontally to intersect the right y-axis forRmfeq /R weq. From this point, draw a straight line through the equiva-

lent mud filtrate resistivity (Rmfeq) point on the Rmfeq nomograph to

intersect the value of R weq on the far-right nomograph.

The spontaneous potential (SP) reading corrected for the effect

of bed thickness (ESPcor) from Chart SP-4 can be substituted for ESSP.

Example

First determine the value of Rmfeq:

If Rmf at 75°F is greater than 0.1 ohm-m, correct Rmf

to the formation temperature by using Chart Gen-6,

and use Rmfeq = 0.85Rmf .

If Rmf at 75°F is less than 0.1 ohm-m, use Chart SP-2

to derive a value of Rmfeq at formation temperature.

Given: ESSP = –100 mV at 250°F and resistivity of the mud

filtrate (Rmf ) = 0.7 ohm-m at 100°F, converted to 0.33

at 250°F.

Find: R weq at 250°F.

Answer: Rmfeq = 0.85Rmf = 0.85 × 0.33 = 0.28 ohm-m.

Draw a straight line from the point on the Rmfeq /R weq line

that corresponds to the intersection of ESSP = –100 mV

and the interpolated 250°F temperature curve through

the value of 0.28 ohm-m on the Rmfeq line to the R weq line

to determine that the value of R weq is 0.025 ohm-m.

The value of Rmfeq /R weq can also be determined from theequation

ESSP = K c log(Rmfeq /R weq),

where K c is the electrochemical spontaneous potential

coefficient:

K c = 61 + (0.133 × Temp°F)

K c = 65 + (0.24 × Temp°C).




p

SP

Rweq Determination from ESSPSP-1

(former SP-1)

0.01

0.02

0.04

0.06

0.1

0.2

0.4

0.001

0.005

0.01

0.02

0.05

Rmfeq

(ohm-m)

Rmfeq /Rweq

Rmf /Rw

Rweq

(ohm-m)

0.3

0.4

0.6

0.8

1

2

4

0.3

0.4

0.5

0.6

0.8

1

2

3

4




Rweq versus Rw and Formation TemperatureSP-2

(customary, former SP-2)

0.001

0.002

0.005

0.01

0.02

0.05

0.1

0.2

Rweq or Rmfeq

(ohm-m)

500°F400°F

300°F

200°F

150°F

100°F

75°F

Saturation

4 0 0 ° F

5 0 0 ° F

p

SP





pp

SP

Rweq versus Rw and Formation TemperatureSP-3

(metric, former SP-2m)

0.001

0.002

0.005

0.01

0.02

0.05

0.1

0.2

Rweq or Rmfeq

(ohm-m)

250°C200°C

150°C

100°C

75°C

50°C

25°C

Saturation

2 0 0°C

2 5 0 ° C




Bed Thickness Correction—Open Hole

SP

Purpose

Chart SP-4 is used to correct the SP reading from the well log forthe effect of bed thickness. Generally, water sands greater than

20 ft in thickness require no or only a small correction.

DescriptionChart SP-4 incorporates correction factors for a number of condi-

tions that can affect the value of the SP in water sands.

The appropriate chart is selected on the basis of resistivity, inva-

sion, hole diameter, and bed thickness. First, select the row of charts with the most appropriate value of the ratio of the resistivity of shale

(Rs) to the resistivity of mud (Rm). On that row, select a chart for no

invasion or for invasion for which the ratio of the diameter of invasion

to the diameter of the wellbore (d i /dh) is 5. Enter the x-axis with

the value of the ratio of bed thickness to wellbore diameter (h/dh).

Move upward to intersect the appropriate curve of the ratio of the

true formation resistivity to the resistivity of the mud (R t /Rm) for

no invasion or the ratio of the resistivity of the flushed zone to the

resistivity of the mud (R xo /Rm) for invaded zones, interpolatingbetween the curves as necessary. Read the ratio of the SP read from

the log to the corrected SP (ESP /ESPcor) on the y-axis for the point of

intersection. Calculate ESPcor = ESP /(ESP /ESPcor). The value of ESPcor

can be used in Chart SP-1 for ESSP.

Spontaneous Potential-Wireline




SP

Bed Thickness Correction—Open HoleSP-4

(former SP-3)

40 30 20 15 10 7.5 5

1.0

0.8

0.6

0.4

0.2

1.0

0.8

0.6

0.4

0.2

40 30 20 15 10 7.5 5

1.0

0.8

0.6

0.4

0.2

1.0

0.8

0.6

0.4

0.2

40 30 20 15 10 7.5 5

1.0

0.8

0.6

0.4

0.2

1.0

0.8

0.6

0.4

0.2

40 30 20 15 10 7.5 5

1.0

0.8

0.6

0.4

0.2

1.0

0.8

0.6

0.4

0.2

ESP /ESPcor

ESP /ESPcor

Rs

Rm

= 1

Rs

Rm

= 5

Rxo = 0.2R t Rxo = R t

h/dh h/dh

Rxo = 5R t

Invasion, di /dh = 5No Invasion

10

52

20

50

100

200

500

10

5

21

0.5

20

50

100

200500

10

52

1

20

50

100200

500

10

5

2

10.5

20

50

100

200

10

52 1

0.5

20

50

100

200

Rxo /Rm Rxo /Rm Rxo /Rm

Rxo /RmRxo /Rm Rxo /Rm

R t /Rm

R t /Rm

21

1

2

50

10

20

5

0.5

0.2

0.1

100

10

20

50

100

200

5

10

5

2

1

0.5

0.2

20

50

100200

h/dh h/dh




Bed Thickness Correction—Open Hole (Empirical)SP-5

(customary, former SP-4)

ESSP

(%)

Correctionfactor

1.0

1.5

2.0

2.5

3.0

3.5

4.0

5.0

5

20

50

100

200

di (in.)

3 0

3

5 3 5

4 0

4 0

3 0

3 0

3 0

3 0

2 0

8-in. Hole; 33 ⁄ 8-in. Tool, Centered

Ri

Rm

100

90

80

70

60

50

40

30

20

SP





SP

Bed Thickness Correction—Open Hole (Empirical)SP-6

(metric, former SP-4m)

0 .5

200-mm Hole; 86-mm Tool, Centered

ESSP

(%)

Correctionfactor

100

90

80

70

60

50

40

30

20

1.0

1.5

2.020

5

50

100

200

2.5

3.0

3.5

4.0

5.0

di (m)

Ri

Rm

0 . 7 5

0 . 7 5 0 . 7 5

0 . 7 5 0 . 7 5

0 . 8

0 . 8 8 1 . 0

1 . 0

General

Density—Wireline, LWD



1 2 3

Quar tz Dolomite Calci te

GasWa ter

4 5 0.5 0.4 0.3 0.2 0.1 06

Pe φ tPorosity Effect on Pe

Matrix φ t 100% H2O 100% CH4

Quartz0.00 1.81 1.81

0.35 1.54 1.76

Calcite0.00 5.08 5.08

0.35 4.23 4.96

Dolomite0.00 3.14 3.14

0.35 2.66 3.07

Specific — 1.00 0.10gravity

Porosity Effect on Photoelectric Cross SectionDens-1

Purpose

This chart and accompanying table illustrate the effect that porosity,matrix, formation water, and methane (CH4) have on the recorded

photoelectric cross section (Pe).

Enter the chart with the total porosity (φt) from the log and move

downward to intersect the angled line. From this point moveto the left and intersect the line representing the appropriate matrix

material: quartz, dolomite, or calcite minerals. From this intersection

move upward to read the correct Pe.

Dens

© Schlumberger

Density—Wireline, LWD



Dens

Apparent Log Density to True Bulk DensityDens-2

Magnesium

Dolomite

Sandstone + water

Low-pressure gasor air in pores

Sands tone

Sylvite (KCI)

Aluminum

Salt (NaCI)

Add correc tion

from y-axis to ρlog

to obtain true

bulk density, ρb

0.14

0.12

0.10

0.08

0.06

0.04

0.02

–0.02

–0.04

0

ρb – ρlog

(g/cm3)

φ = 40%

φ = 0

φ = 40%

Limes tone

A n t h r a c i t e C o a l B i t u m

i n o u s

Gypsum

Limestone + water

Dolomite + wa ter

Neutron—Wireline



Neu

Dual-Spacing Compensated Neutron Tool Charts

This section contains interpretation charts to cover developments in

compensated neutron tool (CNT) porosity transforms, environmentalcorrections, and porosity and lithology determination.

CSU* software (versions CP-30 and later) and MAXIS* software

compute three thermal porosities: NPHI, TNPH, and NPOR.

NPHI is the “classic NPHI,” computed from instantaneous near

and far count rates, using “Mod-8” ratio-to-porosity transform with

a caliper correction.

TNPH is computed from deadtime-corrected, depth- and

resolution-matched count rates, using an improved ratio-to-porosity

transform and performing a complete set of environmental correctionsin real time. These corrections may be turned on or off by the field

engineer at the wellsite. For more information see Reference 32.

NPOR is computed from the near-detector count rate and TNPH

to give an enhanced resolution porosity. The accuracy of NPOR is

equivalent to the accuracy of TNPH if the environmental effects on

the near detector change less rapidly than the formation porosity.

For more information on enhanced resolution processing, see

Reference 35.

Cased hole CNT logs are recorded on NPHI, computed frominstantaneous near and far count rates, with a cased hole ratio-to-

porosity transform.

Using the Neutron Correction Charts

For logs labeled NPHI:1. Enter Chart Neu-5 with NPHI and caliper reading to convert to

uncorrected neutron porosity.

2. Enter Charts Neu-1 and Neu-3 to obtain corrections for each

environmental effect. Corrections are summed with the uncor-

rected porosity to give a corrected value.

3. Use crossplot Charts Por-11 and Por-12 for porosity and lithology

determination.

For logs labeled TNPH or NPOR, the CSU wellsite surface instru-mentation and MAXIS software have applied environmental correc-

tions as indicated on the log heading. If the CSU and MAXIS

software has applied all corrections, TNPH or NPOR can be used

directly with the crossplot charts. In this case:

1. Use crossplot Charts Por-11 and Por-12 to determine porosity

and lithology.

Neutron—Wireline



Neu

Compensated Neutron ToolEnvironmental Correction—Open Hole

Purpose

Chart Neu-1 is used to correct the compensated neutron log porosity index if the caliper correction was not applied. If the caliper correc-

tion is applied, it must be “backed out” to use this chart.

DescriptionThis chart is used only if the caliper correction was not applied

to the logged data. The parameter section of the log heading lists

whether correction was applied.

Example 1: Backed-Out Correction of TNPH Porosity

Given: Thermal neutron porosity (TNPH) from the log = 32 p.u.

(apparent limestone units) and borehole size = 12 in.

Find: Uncorrected TNPH with the correction backed out.

Answer: Enter the top chart for actual borehole size at the inter-

section point of the standard conditions 8-in. horizontal

line and 32 p.u. on the scale above the chart.

From this point, follow the closest trend line to intersect

the 12-in. line for the borehole size.

The intersection is the uncorrected TNPH value of 34 p.u.

To use the uncorrected value on Chart Neu-1, draw a ver-

tical line from this intersection through the remainder of

the charts, as shown by the red line.

Example 2: Environmentally Corrected THPH

Given: Neutron porosity of 32 p.u. (apparent limestone units), without environmental correction, 12-in. borehole, 1 ⁄ 4-in.

thick mudcake, 100,000-ppm borehole salinity, 11-lbm/gal

natural mud weight (water-base mud [WBM]), 150°F

borehole temperature, 5,000-psi pressure (WBM), and

100,000-ppm formation salinity.

Find: Environmentally corrected TNPH porosity.

Answer: If there is standoff (which is not uncommon), use Chart

Neu-3. Then use Chart Neu-1 by drawing a vertical linethrough the charts for the previously determined

backed-out (uncorrected) 34-p.u. neutron porosity

value.

On each environmental correction chart, enter the y-axis

at the given value and move horizontally left to intersect

the porosity value vertical line.

For example, on the mudcake thickness chart the line

extends from 1 ⁄ 4 in. on the y-axis.

At the intersection point, move parallel to the closest

blue trend line to intersect the standard conditions, as

indicated by the bullet.

The point of intersection with the standard conditions

for the chart is the value of porosity corrected for the

particular environment. The change in porosity value

(either positive or negative) is summed for the charts

and referred to as delta porosity (∆φ).

The ∆φ net correction applied to the uncorrected log neutronporosity is listed in the table for the two examples.

Neutron—Wireline




Neu-1(customary, former Por-14c)

0 10 20 30 40 50

Actual borehole size(in.)

1.0

0.5

0

Mudcake thickness(in.)

250

0

Borehole salinity(1,000 × ppm)

Mud weight(lbm/gal)

Natural

300

B h l t t

18161412

108

Barite

Neutron log porosity index (apparent limestone porosity in p.u.)

2420161284

•

•

•

•

•

1312111098

Neu

Neutron—Wireline



Neu


Neu-2(metric, former Por-14cm)

0 10 20 30 40 50

600500400300200100

Actual borehole size(mm)

25

12.5

0

Mudcake thickness(mm)

250

0

Borehole salinity(g/kg)

149121

1.5

1.0Mud density(g/cm3)

N a t u r a l

2.0

1.0 B

a r i t e

Neutron log porosity index (apparent limestone porosity)

•

•

•

•

•

Neutron—Wireline



Neu

Purpose

Chart Neu-3 is used to determine the porosity change caused by standoff to the uncorrected thermal neutron porosity TNPH from

Chart Neu-1.

DescriptionEnter the appropriate borehole size chart at the estimated neutron

tool standoff on the y-axis. Move horizontally to intersect the uncor-

rected porosity. At the intersection point, move along the closest

trend line to the standard conditions line defined by the bullet to

the right of the chart. This point is the porosity value corrected fortool standoff. The difference between the standoff-corrected porosity

and the uncorrected porosity is the correction itself.

Example

Given: TNPH = 34 p.u., borehole size = 12 in., andstandoff = 0.5 in.

Find: Porosity corrected for standoff.

Answer: Draw a vertical line from the uncorrected neutron log

porosity of 34 p.u. Enter the 12-in. borehole chart at

0.5-in. standoff and move horizontally right to intersect

the vertical porosity line. From the point of intersection

move parallel to the closest trend line to intersect the

standard conditions line (standoff = 0 in.). The standoff-corrected porosity is 32 p.u. The correction is –2 p.u.

Compensated Neutron ToolStandoff Correction—Open Hole

Neutron—Wireline



Neu


Neu-3(customary, former Por-14d)

0 10 20 30 40 50

7

6

5

4

3

2

1

4

3

2

1

0

3

2

1

0

2

1

0

1

0

Actualborehole size

6 in.

8 in.

10 in.

12 in.

18 in.

Standoff(in.)

Neutron log porosity index (apparent limestone porosity in p.u.)

•

•

•

•

Neutron—Wireline



Neu


Neu-4(metric, former Por-14dm)

0 10 20 30 40 50

175

150

125

100

75

50

25

100

75

50

25

0

75

50

25

0

50

25

0

25

0

Actualborehole size

150 mm

200 mm

250 mm

300 mm

450 mm

Standoff(mm)

Neutron log porosity index (apparent limestone porosity)

•

•

•

•

Neutron—Wireline



Neu

Compensated Neutron ToolConversion of NPHI to TNPH—Open Hole

Neu-5(former Por-14e)

Purpose

This chart is used to determine the porosity change caused by the

borehole size to the neutron porosity NPHI and convert the porosity

to thermal neutron porosity (TNPH). This chart corrects NPHI only

for the borehole sizes that differ from the standard condition of 8 in.

Refer to Chart Neu-1 to complete the environmental corrections for

the TPNH value obtained.

Description

Enter the scale at the top of the chart with the NPHI porosity.

Example

At the point of intersection of the vertical line and the

standard conditions line, move parallel to the closest

trend line to intersect the actual borehole size line.

At that intersection point move vertically down to the

bottom scale to determine the TNPH porosity corrected

only for borehole size. This value is also used to deter-

mine the change in porosity as a result of tool standoff.

TNPH = 12.5 + 5 = 17.5 p.u.

TNPH porosity index (apparent limestone porosity in p.u.)

242016128

4

Borehole size(in.)

–5 0 10 20 30 40 50

0 10 20 30 40 50

NPHI porosity index (apparent limestone porosity in p.u.)

•

• Standard conditions

© Schlumberger

Neutron—Wireline



Neu

Compensated Neutron ToolFormation Σ Correction for Environmentally Corrected TNPH—Open Hole

Purpose

This chart is used to further correct the environmentally correctedTNPH porosity from Chart Neu-1 for the effect of the total forma-

tion capture cross section, or sigma (Σ), of the formation of inter-

est. This correction is applied after all environmental corrections

determined with Chart Neu-1 have been applied.

DescriptionEnter the chart with Σ for the appropriate formation along the y-axis

and the corrected TNPH porosity along the x-axis. Where the lines

drawn from these points intersect, move parallel to the closest trendline to intersect the appropriate fresh- or saltwater line to read the

corrected porosity.

The chart at the bottom of the page is used to correct the Σ-

corrected porosity for salt displacement if the formation Σ is due to

salinity. However, this correction is not made if the borehole salinity

correction from Chart Neu-1 has been applied.

Example

Given: Corrected TNPH from Chart Neu-1 = 38 p.u., Σ of thesandstone formation = 33 c.u., and formation salinity =

150,000 ppm (indicating a freshwater formation).

Find: TNPH porosity corrected with Chart Neu-1 and for Σ of

the formation.

Answer: Enter the appropriate chart with the Σ value on the y-axis

and the corrected TNPH value on the x-axis. At the inter-

section of the sigma and porosity lines, parallel the clos-

est trend line to intersect the freshwater line. (If the water in the formation is salty, the 250,000-ppm line

should be used.)

Move straight down from the intersection point to the

formation salinity chart at the bottom.

From the point where the straight line intersects the top

of the salinity correction chart, parallel the closest trend

line to intersect the formation salinity line.

Draw a vertical line to the bottom scale to read the cor-

rected formation sigma TNPH porosity, which is 35 p.u.

Neutron—Wireline



Neu

0 10 20 30 40 50

70

60

70

60

50

40

30

20

10

0

Neutron log porosity index

Sandstone formation

Formation Σ (c.u.)

Fresh water

250,000-ppm water

Limestone formationFormation Σ (c.u.)

Fresh water

250,000-ppm water

70

60

5040

30

20

10

0

Compensated Neutron ToolFormation Σ Correction for Environmentally Corrected TNPH—Open Hole

Neu-6(former Por-16)

Neutron—Wireline



Neu

Compensated Neutron ToolMineral Σ Correction for Environmentally Corrected TNPH—Open Hole

Purpose

This chart is used to further correct the environmentally correctedTNPH porosity from Chart Neu-1 for the effect of the mineral sigma

(Σ). This correction is applied after all environmental corrections

determined with Chart Neu-1 have been applied.

Description

Enter the chart for the formation type with the mineral Σ value along

the y-axis and the Chart Neu-1 corrected TNPH porosity along the

x-axis. Where lines drawn from these points intersect, move parallel to

the closest trend line to intersect the freshwater line to read thecorrected porosity on the scale at the bottom. The choice of chart

depends on the type of mineral in the formation.

Example

Given: Corrected TNPH from Chart Neu-1 = 38 p.u., sandstoneformation Σ = 35 c.u., and formation salinity =

150,000 ppm (indicating a freshwater formation).

Find: TNPH porosity corrected with Chart Neu-1 and for the

mineral Σ.

Answer: At the intersection of theΣ and porosity value lines


freshwater line. Move straight down to intersect the bot-

tom prosity scale to read the TNPH porosity correctedfor mineral Σ, which is 33 p.u.

Neutron—Wireline



Neu

Compensated Neutron ToolMineral Σ Correction for Environmentally Corrected TNPH—Open Hole

0 10 20 30 40 50


Sandstone formationMineral Σ (c.u.)

Fresh water

Fresh water

70

60

50

40

30

20

10

0

Limestone formationMineral Σ (c.u.)

70

60

50

40

30

20

10

0


General

Neutron—Wireline



Neu

Compensated Neutron ToolFluid Σ Correction for Environmentally Corrected TNPH—Open Hole

Purpose

This chart is used to correct the environmentally corrected TNPHporosity from Chart Neu-1 for the effect of the fluid sigma (Σ) in

the formation. This correction is applied after all environmental

corrections determined with Chart Neu-1 have been applied.

Description

Enter the appropriate formation chart with the formation fluid Σ

value on the y-axis and the Chart Neu-1 corrected TNPH porosity on

the x-axis. Where the lines drawn from these points intersect, move

parallel to the closest trend line to intersect the appropriate fresh-or saltwater line. If the borehole salinity correction from Chart Neu-1

has not been applied, from this point extend a line down to intersect

the formation salinity chart at the bottom. Move parallel to the

closest trend line to intersect the formation salinity line. Move

straight down to read the corrected porosity on the scale below

the chart.

Example

Given: Corrected TNPH from Chart Neu-1 = 30 p.u. (withoutborehole salinity correction), fluid Σ = 80 c.u., fluid

salinity = 150,000 ppm, and sandstone formation.

Find: TNPH corrected with Chart Neu-1 and for fluid Σ.

Answer: At the intersection of the fluid Σ and Chart Neu-1

corrected TNPH porosity (30-p.u.) line, move parallel

to the closest trend line to intersect the freshwater line.

From that point go straight down to the formation salinity

correction chart at the bottom.Move parallel to the closest trend line to intersect the

formation salinity line (150,000 ppm), and then draw a

vertical line to the bottom scale to read the corrected

TNPH value (26 p.u.).

Neutron—Wireline



Neu

0 10 20 30 40 50


Sandstone formationFluid Σ (c.u.)

Limestone formationFluidΣ (c.u.)

160

140

120

100

80

60

40

20

160

140

120

100

80

60

40

20

160

Fresh water

250,000-ppm water

Fresh water

250,000-ppm water

Compensated Neutron ToolFluid Σ Correction for Environmentally Corrected TNPH—Open Hole


Neutron—Wireline

C d N T l



Neu

Compensated Neutron ToolEnvironmental Correction—Cased Hole

Purpose

This chart is used to obtain the correct porosity from the neutronporosity index logged with the compensated neutron tool in casing,

where the effects of the borehole size, casing thickness, and cement

sheath thickness influence the true value of formation porosity.

Description

Enter the scale at the top of the chart with a whole-number (not

fractional) porosity value. Draw a straight line vertically through

the three charts representing borehole size, casing thickness, and

cement thickness. Draw a horizontal line on each chart from theappropriate value on the y-axis. At the intersection point of the verti-

cal line and the horizontal line on each chart proceed to the blue

dashed horizontal line by following the slope of the blue solid lines

on each chart. At that point read the change in porosity index. The

cumulative change in porosity is added to the logged porosity to obtain

the corrected value. As can be seen, the major influences to the casing-

derived porosity are the borehole size and the cement thickness. The

same procedure applies to the metric chart.

The blue dashed lines represent the standard conditions from which the charts were developed: 83 ⁄ 4-in. open hole, 51 ⁄ 2-in. 17-lbm

casing, and 1.62-in. annular cement thickness.

The neutron porosity equivalence nomographs at the bottom are

used to convert from the log standard of limestone porosity to poros-

ity for other matrix materials.

The porosity value corrected with Chart Neu-9 is entered into

Chart Neu-1 to provide environmental corrections necessary for

determining the correct cased hole porosity value.

Example

Given: Log porosity index = 27%, borehole diameter = 11 in.,casing thickness = 0.304 in., and cement thickness =

1.62 in.

Cement thickness is defined as the annular space

between the outside wall of the casing and the borehole

wall. The value is determined by subtracting the casing

outside diameter from the borehole diameter and divid-

ing by 2.

Find: Porosity corrected for borehole size, casing thickness,and cement thickness.

Answer: Draw a vertical line (shown in red) though the three

charts at 27 p.u.

Borehole-diameter correction chart: From the intersec-

tion of the vertical line and the 11-in. borehole-diameter

line (shown in red dashes) move upward along the

curved blue line as shown on the chart.

The porosity is reduced to 26% by –1 p.u.

Casing thickness chart: The porosity index is changed

by 0.3 p.u.

Cement thickness chart: The porosity index is changed

by 0.5 p.u.

The resulting corrected porosity for borehole, casing,

and cement is 27 – 1 + 0.3 + 0.5 = 26.8 p.u.

Neutron—Wireline

C d N T l



Neu

Compensated Neutron ToolEnvironmental Correction—Cased Hole

0 10 20 30 40 50

468

10121416

0.2

0.3

0.4

0.5

0

1

2

3

+0.3

+0.5

Borehole, casing, and cement correction = –1.0 + 0.3 + 0.5

–1.0

1.62 in.

0.304 in.

83 ⁄ 4 in.

Neutron log porosity index(p.u.)

Diameter of boreholebefore running casing

(in.)

Cement thickness(in.)

Casing thickness (in.)9.5

11.613.515.1

14

17

20

23

20

26

32

29

40

47

41 ⁄ 2 51 ⁄ 2 7 95 ⁄ 8

OD (in.)

Casingweight(lbm/ft)

Customary

•

•

•

0 10 20 30 40 50

100

200

300222 mm

Neutron log porosity index(p.u.)

Diameter of boreholebefore running casing

(mm)

Metric

•

Neu-9(former Por-14a)

Neutron—Wireline

APS* A l t P it S d



Neu

APS* Accelerator Porosity SondeEnvironmental Correction—Open Hole

Purpose

The Neu-10 charts pair is used to correct the APS Accelerator Porosity Sonde apparent limestone porosity for mud weight and actual bore-

hole size. The charts are for the near-to-array and near-to-far poros-

ity measurements. The design of the APS sonde resulted in a

significant reduction in environmental correction. The answer deter-

mined with this chart is used in conjunction with the correction

from Chart Neu-11.

Description

Enter the appropriate chart pair (mud weight and actual boreholesize) for the APS near-to-array apparent limestone porosity (APLU)

or APS near-to-far apparent limestone porosity (FPLU) with the

uncorrected porosity from the APS log by drawing a straight vertical

line (shown in red) through both of the charts. At the intersection

with the mud weight value, move parallel to the closest trend line to

intersect the standard conditions line. This point represents a change

in porosity resulting from the correction for mud weight. Follow the

same procedure for the borehole size chart to determine that correc-

tion change. Because the borehole size correction has a dependency on mud weight, even with natural muds, there are two sets of curves

on the borehole size chart—solid for light muds (8.345 lbm/gal) and

dashed for heavy muds (16 lbm/gal). Intermediate mud weights are

interpolated. The two differences are summed for the total correc-

tion to the APS log value.

This answer is used in Chart Neu-11 to complete the environ-

mental corrections for corrected APLU or FPLU porosity.

Example

Given: APS neutron APLU uncorrected porosity = 34 p.u.,mud weight = 10 lbm/gal, and borehole size = 12 in.

Find: Corrected APLU porosity.

Answer: Draw a vertical line on the APLU mud weight chart from

34 p.u. on the scale above. At the intersection with the

10-lbm/gal mud weight line, move parallel to the trend

line to intersect the standard conditions line. This point

represents a change in porosity of –0.75 p.u.

On the actual borehole size chart, move parallel to theclosest trend line from the intersection of the 34-p.u.

line and the actual borehole size (12 in.) to intersect

the 8-in. standard conditions line. This point represents

a change in porosity of –1.0 p.u.

The total correction is –0.75 + –1.0 = –1.75 p.u.,

which results in a corrected APLU porosity of

34 – 1.75 = 32.25 p.u.

Neutron—Wireline

APS* A l t P it S d



Neu

APS near-to-far apparent limestone porosity uncorrected, FPLU (p.u.)

Mud weight(lbm/gal)

Actualborehole size

(in.)

18

16

14

12

10

8

16

14

12

10

8

2.01.81.61.41.21.0

400

350

300

250

200

(g/cm3)

(mm)

•

•

APS near-to-array apparent limestone porosity uncorrected, APLU (p.u.)

0 10 20 30 40 50

Mud weight(lbm/gal)

Actualborehole size

(in.)

18

16

1412

10

8

16

14

12

10

8

6

2.01.8

1.61.41.21.0

400

350

300

250

200

(g/cm3)

(mm)

•

•

APS* Accelerator Porosity SondeEnvironmental Correction—Open Hole


Neutron—Wireline

APS* A l t P it S d With t E i t l C ti



Neu

Purpose

This chart is used to complete the environmental correction for APLU and FPLU porosities from the APS log.

Description

Example

Given: APLU or FPLU porosity = 34 p.u., formation tempera-ture = 150°F, formation pressure = 5,000 psi, and for-

mation salinity = 150,000 ppm.

50 100 150 200 250 300 35010 38 66 93 121 149 177

50 150 250

Formation salinity(ppt or g/kg)

Formation porosity(p.u.)

50 30 10 0

Formation temperature

(°F)(°C)

12

11

10

9

8

7

6

5

4

3

2

1

0

–1

Apparentporositycorrection

(p.u.)

(psi) (MPa)

0 0

2,500

5,000 34

7,500

10,000 69

12,500

15,000 103

17,500 20,000 138

Pressure

APS* Accelerator Porosity Sonde Without Environmental CorrectionsEnvironmental Correction—Open Hole

Neu-11(former Por-23b)

*Mark of Schlumberger© Schlumberger

Neutron—LWD

CDN* Compensated Density Neutron adnVISION* Azimuthal Density



Neu

Purpose

This chart is used to determine one of several environmentalcorrections for neutron porosity values recorded with the CDN

Compensated Density Neutron, adnVISION Azimuthal Density

Neutron, and EcoScope Integrated LWD tools. The value of hydrogen

index (Hm) is used in the following porosity correction charts.

Description

To determine the Hm of the drilling mud, the mud weight, tempera-

ture, and hydrostatic mud pressure at the zone of interest must

be known.

Example

Given: Barite mud weight = 14 lbm/gal, mud temperature = 150°F,and hydrostatic mud pressure = 5,000 psi.

Find: Hydrogen index of the drilling mud.

Answer: Enter the bottom chart for mud weight at 14 lbm/gal on

the y-axis. Move horizontally to intersect the barite line.

Move vertically to the bottom of the mud temperature

chart and move upward parallel to the closest trend line

to intersect the formation temperature. From the inter-

section point move vertically to the bottom of the mudpressure chart.

Move parallel to the closest trend line to intersect the

formation pressure. Draw a line vertically to intersect

the mud hydrogen index scale and read the result.

Mud hydrogen index = 0.78.

CDN* Compensated Density Neutron, adnVISION* Azimuthal DensityNeutron, and EcoScope* Integrated LWD ToolsMud Hydrogen Index Determination

Neutron—LWD

CDN* Compensated Density Neutron adnVISION* Azimuthal Density



Neu

CDN* Compensated Density Neutron, adnVISION* Azimuthal DensityNeutron, and EcoScope* Integrated LWD ToolsMud Hydrogen Index Determination


0.70 0.75 0.80 0.85 0.90 0.95 1

25

20

10

0

Mudpressure

(1,000 × psi)

300

200

100

50

Mud temperature

(°F)

Mud hydrogen index, Hm

Neutron—LWD

adnVISION475* Azimuthal Density Neutron 4 75 in Tool and 6 in Borehole



Neu

Purpose

This is one of a series of charts used to correct adnVISION4754.75-in. Azimuthal Density Neutron tool porosity for several environ-

mental effects by using the mud hydrogen index (Hm) determined

from Chart Neu-30 in conjunction with the parameters on the chart.

DescriptionThis chart incorporates the parameters of borehole size, mud tem-

perature, mud hydrogen index (from Chart Neu-30), mud salinity,

and formation salinity for the correction of adnVISION475 porosity.

The following charts are used with the same interpretationprocedure as Chart Neu-31. The charts differ for tool size and

borehole size.

Example

Given: adnVISION475 uncorrected porosity = 34 p.u., boreholesize = 10 in., mud temperature = 150°F, hydrogen

index = 0.78, borehole salinity = 100,000 ppm, and forma-

tion salinity = 100,000 ppm.

Find: Corrected adnVISION475 porosity.

Answer: From the adnVISION475 porosity of 34 p.u. on the top

scale, enter the borehole size chart to intersect the bore-

hole size of 10 in. From the point of intersection move

parallel to the closest trend line to intersect the stan-

dard conditions line.

From this intersection point move straight down to

enter the mud temperature chart and intersect the mud

temperature of 150°F. From the point of intersection


standard conditions line.

Continue this pattern through the charts to read the

corrected porosity from the scale at the bottom of the

charts.The corrected adnVISION475 porosity is 17 p.u.

adnVISION475* Azimuthal Density Neutron—4.75-in. Tool and 6-in. BoreholeEnvironmental Correction—Open Hole

Neutron—LWD

adnVISION475* Azimuthal Density Neutron 4 75 in Tool and 6 in Borehole



Neu

adnVISION475 Azimuthal Density Neutron—4.75-in. Tool and 6-in. BoreholeEnvironmental Correction—Open Hole

Neu-31

Boreholesize(in.)

0 10 20 30 40 50

Mudhydrogenindex, Hm

Mudsalinity

(1,000 × ppm)

Mud temperature

(°F)

•

•

•

•

6

8

10

100

0.7

0.8

0.9

1.0

200

300

0

100

200

adnVISION475 neutron porosity index (apparent limestone porosity) in 6-in. borehole

200

Neutron—LWD

adnVISION475* BIP Neutron 4 75 in Tool and 6 in Borehole



Neu

adnVISION475 BIP Neutron—4.75-in. Tool and 6-in. BoreholeEnvironmental Correction—Open Hole

Neu-32

0 10 20 30 40 50


Mudsalinity

(1,000 × ppm)

Formationsalinity

(1,000 × ppm)

Mud temperature

(°F)


100

0.7

0.8

0.9

1.0

200

300

100

200

0

100

200

Neutron—LWD

adnVISION475* Azimuthal Density Neutron—4 75-in Tool



Neu

adnVISION475 Azimuthal Density Neutron—4.75-in. Tooland 8-in. BoreholeEnvironmental Correction—Open Hole

Neu-33

Boreholesize(in.)

0 10 20 30 40 50


Mudsalinity

(1,000 × ppm)

Mud temperature

(°F)

•

•

•

•

6

8

10

100

0.7

0.8

0.9

1.0

200

300

0

100

200


200

Neutron—LWD

adnVISION475* BIP Neutron—4 75-in Tool and 8-in Borehole



Neu

adnVISION475 BIP Neutron 4.75-in. Tool and 8-in. BoreholeEnvironmental Correction—Open Hole

Neu-34

0 10 20 30 40 50


0 0 20 30 0 0

Mudsalinity

(1,000 × ppm)

Formationsalinity

(1,000 × ppm)

Mud temperature

(°F)


100

0.7

0.8

0.9

1.0

200

300

100

200

0

0

100

200

Neutron—LWD

adnVISION675* Azimuthal Density Neutron—6 75-in Tool and 8-in Borehole



Neu

250

200

300

200

100

50

Mud temperature

(°F)

•

0.7

0.8

0.9

1.0


•

adnVISION675 neutron porosity index (apparent limestone porosity in p.u.)

0 10 20 30 40 50

16

14

12

10

8

Boreholesize(in.)

•

adnVISION675 Azimuthal Density Neutron 6.75 in. Tool and 8 in. BoreholeEnvironmental Correction—Open Hole


adnVISION675* BIP Neutron—6 75-in Tool and 8-in Borehole

Neutron—LWD



adnVISION675 BIP Neutron 6.75 in. Tool and 8 in. BoreholeEnvironmental Correction—Open Hole

0 10 20 30 40 50


0 10 20 30 40 50

Mudsalinity(1,000 × ppm)

Formationsalinity

(1,000 × ppm)

Mud temperature

(°F)


100

0.7

0.8

0.9

1.0

200

300

100

200

0

0

100

200

Neu

Neu-36

Neutron—LWD

adnVISION675* Azimuthal Density Neutron—6 75-in Tool and 10-in Borehole



Neu

adnVISION675 Azimuthal Density Neutron 6.75 in. Tool and 10 in. BoreholeEnvironmental Correction—Open Hole

Neu-37(former Por-26b)

250

200

300

200

100

50

Mud temperature

(°F)

•

0.7

0.8

0.9

1.0


•

adnVISION675 neutron porosity index (apparent limestone porosity in p.u.)

0 10 20 30 40 50

16

14

12

10

8

Boreholesize(in.)

•

Neutron—LWD

adnVISION675* BIP Neutron—6.75-in. Tool and 10-in. Borehole



Neu

adnVISION675 BIP Neutron 6.75 in. Tool and 10 in. BoreholeEnvironmental Correction—Open Hole

0 10 20 30 40 50


0 10 20 30 40 50

Mudsalinity(1,000 × ppm)

Formationsalinity

(1,000 × ppm)

Mud temperature

(°F)


100

0.7

0.8

0.9

1.0

200

300

100

200

0

0

100

200

Neu-38

Neutron—LWD

adnVISION825* Azimuthal Density Neutron—8.25-in. Tool



Neu

adnVISION825 Azimuthal Density Neutron 8.25 in. Tooland 12.25-in. BoreholeEnvironmental Correction—Open Hole

Neu-39

Standoff(in.)

0 10 20 30 40 50

Mud temperature

(°F)


Pressure

Boreholesize(°F)

1.5

0.5

0

1.0

12

10

300

200

100

14

16

1

0.7

0.8

0.9

adnVISION825 neutron porosity index (apparent limestone porosity) in 12.25-in. borehole

Standoff = 0.25 in.

10

20

•

•

•

•

Neutron—LWD

CDN* Compensated Density Neutron and adnVISION825s*



Neu

p s s y sAzimuthal Density Neutron—8-in. Tool and 12-in. BoreholeEnvironmental Correction—Open Hole

Neu-40(former Por-24c)

18

16

14

12

Boreholesize(in.)

Neutron porosity index (apparent limestone porosity) in 12-in. borehole

0 10 20 30 40 50

Mud

•

•

•

250

200

0.7

0.8

0.9

1.0


350

300

200

100

50

Mud temperature

(°F)

Neutron—LWD

CDN* Compensated Density Neutron and adnVISION825s*



Neu

p yAzimuthal Density Neutron—8-in. Tool and 14-in. BoreholeEnvironmental Correction—Open Hole

Neu-41(former Por-24d)

350

300

200

100

50

Mud temperature

(°F)

18

16

14

12

Boreholesize(in.)

Neutron porosity index (apparent limestone porosity) in 14-in. borehole 0 10 20 30 40 50

•

•

•

A

B

C

0.7

0.8

0.9

1 0

Mudhydrogenindex, H

m

D

E

F

Neutron—LWD

CDN* Compensated Density Neutron and adnVISION825s*N 42



Neu

p yAzimuthal Density Neutron—8-in. Tool and 16-in. BoreholeEnvironmental Correction—Open Hole

18

16

14

12

Boreholesize(in.)

0.7

0.8

0.9

1.0


Neutron porosity index (apparent limestone porosity) in 16-in. borehole

0 10 20 30 40 50

•

•

•

350

300

200

100

50

Mud temperature

(°F)

Neu-42(former Por-24e)

Neutron—LWD

EcoScope* Integrated LWD Neutron Porosity—6.75-in. Tool



Purpose

Charts Neu-43 through Neu-46 show the environmental correctionsthat are applied to EcoScope 6.75-in. Integrated LWD Tool neutron

porosity measurements. These charts can be used to estimate the

correction that is normally already applied to the field logs.

Description

The charts incorporate the parameters of borehole size, mud tem-

perature, mud hydrogen index (from Chart Neu-30), mud salinity,

and formation salinity for the correction of EcoScope 6.75-in.

neutron porosity.

Select the appropriate chart based on both the hole size and

the measurement type: thermal neutron porosity (TNPH) or best

thermal neutron porosity (BPHI).

Enter the charts with the uncorrected neutron porosity data.

Charts Neu-43 and Neu-44 are for use with BPHI_UNC, and ChartsNeu-45 and Neu-46 are for use with TNPH_UNC. Because the bore-

hole size correction is applied to the field logs, including the _UNC

channels, do not include the borehole size correction, which is in the

charts for illustrative purposes only.

A correction for eccentricity effects is normally also applied to

the field BPHI measurement. Because this correction is not included

in these charts, there may be a small difference between the correc-

tion estimated from the charts and that actually applied to the field

data, depending on the tool position in the borehole.The charts are used with a similar procedure to that described

for Chart Neu-31.

p g yEnvironmental Correction—Open Hole

Neu

Neutron—LWD

EcoScope* Integrated LWD BPHI Porosity—6.75-in. Tool and 8.5-in. BoreholeN 43



p g yEnvironmental Correction—Open Hole

Neu-43

14

13

12

11

10

9

8

Boreholesize(in.)

0.70

0.75

0.80

0.85

0.90

0.95

1.00


EcoScope uncorrec ted BPHI porosity (apparent limestone porosity in p.u.) in 8.5-in. borehole

0 10 20 30 40 50

Mud

•

•

• 250

200

150

260

210

160

110

60

Temperature(°F)

Neu

Neutron—LWD

EcoScope* Integrated LWD BPHI Porosity—6.75-in. Tool and 9.5-in. BoreholeNeu 44



Environmental Correction—Open Hole Neu-44

14

13

12

11

10

9

8

Boreholesize(in.)

0.70

0.75

0.80

0.85

0.90

0.95

1.00


EcoScope uncorrec ted BPHI porosity (apparent limestone porosity in p.u.) in 9.5-in. borehole

0 10 20 30 40 50

Mud

•

•

• 250

200

150

260

210

160

110

60

Temperature(°F)

Neu

Neutron—LWD

EcoScope* Integrated LWD TNPH Porosity—6.75-in. Tool and 8.5-in. BoreholeNeu 45




14

13

12

11

10

9

8

Boreholesize(in.)

0.70

0.75

0.80

0.85

0.90

0.95

1.00


EcoScope uncorrec ted TNPH porosity (apparent limestone porosity in p.u.) in 8.5-in. borehole

0 10 20 30 40 50

Mud

•

•

• 250

200

150

260

210

160

110

60

Temperature(°F)

Neu

Neutron—LWD

EcoScope* Integrated LWD TNPH Porosity—6.75-in. Tool and 9.5-in. BoreholeNeu 46




14

13

12

11

10

9

8

Boreholesize(in.)

0.70

0.75

0.80

0.85

0.90

0.95

1.00


EcoScope uncorrec ted TNPH porosity (apparent limestone porosity in p.u.) in 9.5-in. borehole

0 10 20 30 40 50

Mud

•

•

• 250

200

150

260

210

160

110

60

Temperature(°F)

Neu

Neutron—LWD

EcoScope* Integrated LWD—6.75-in. Tool



Formation Sigma Environmental Correction—Open Hole

Purpose

This chart is used to environmentally correct the raw sigma (RFSA)measurement for porosity, borehole size, and mud salinity. The fully

corrected sigma (SIFA) measurement is normally presented on the

logs.

Description

Chart Neu-47 includes (from top to bottom) the moments sigma

transform, diffusion correction based on porosity, and borehole

correction.

ExampleGiven: Raw sigma (24 c.u.), porosity (30 p.u.), borehole size

(10 in.), and mud salinity (200,000 ppm).

Find: Corrected sigma (SIFA).

Answer: Enter the chart from the scale at the top with the raw

sigma value of 24 c.u.

Moments Sigma Transform

Move parallel to the closest trend line to intersect the x-axis of the

moments sigma transform chart. The difference between the x-axis value and the raw sigma value is the moments sigma transform

correction (19.8 – 24 = –4.2 c.u.).

Diffusion Correction

Move down vertically from the scale at the top to intersect the30-p.u. line on the porosity chart. At the intersection point, move

parallel to the closest trend line to intersect the x-axis of the

porosity chart.

The difference between the x-axis value and the raw sigma value

is the diffusion correction (25.3 – 24 = +1.3 c.u.).

Borehole Correction

Move down vertically from the scale at the top to intersect the 10-in.

borehole size line. At the intersection point, move parallel to theclosest trend line corresponding to the mud salinity to intersect

the x-axis of the borehole correction chart.

The difference between the x-axis value and the raw sigma value

is the borehole correction (22.8 – 24 = –1.2 c.u.).

Net Correction

The net correction to apply to the raw sigma value is the sum the

three corrections (–4.2 + 1.3 + –1.2 = –4.1 c.u.). The environmentally

corrected sigma is the sum of the net correction and the raw sigma value (24 + –4.1 = 19.9 c.u.).

Neu

EcoScope Sigma Correction Example

Correction

Raw sigma 24 c.u.

Porosity 30 p.u.Borehole size 10 in.

Mud salinity 200,000 ppm

Neutron—LWD

EcoScope* Integrated LWD—6.75-in. ToolNeu-47



Formation Sigma Environmental Correction—Open Hole Neu-47

11

10

9

50

40

30

20

10

0

0 10 20 30 40 50 60

Mud salinity 0 ppm

50 000 ppm

Raw sigma (c

.u.)

Momentssigma

transform

Porosity(p.u.)

Borehole

size (in.)

Neu

General

Nuclear Magnetic Resonance–—Wireline

CMR* ToolCMR-1



NMR

Hydrocarbon Effect on NMR/Density Porosity Ratio CMR 1

1.0

1.0

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

0.8

0.4

0.4

0.2

0.2

0

0

0.6

0.61 – Sxo

1.4

1.6

1.8

2 0Gas Gas

30 p u 30 p u

40 p.u. 40 p.u.

0%

20%40%

60%80%

0%

20%40%

60%80%

Porosity = 50 p.u. Porosi ty = 50 p.u.

1.4

1.6

1.8

2 0

ρma = 2.65, ρf = 1, If = 1, ρgas = 0.25,PT = 4, T1 gas = 4, IH = 0.5

Fresh Mud and Dry Gas at 700 psi Fresh Mud and Dry Gas at 700 psi

ρma = 2.71, ρf = 1, If = 1, ρgas = 0.25,PT = 4, T1 gas = 4, Igas = 0.5

φ tCMR

φD

ρh = 0.8



This page intentionally left blank.

Resistivity Laterolog—Wireline

ARI* Azimuthal Resistivity ImagerE i l C i O H l

RLl-1



Environmental Correction—Open Hole RLl 1

(former Rcor-14)

PurposeThis chart is used to environmentally correct the ARI Azimuthal

Resistivity Imager high-resolution resistivity (LLhr) curve for theeffect of borehole size.

Description

ExampleGiven: ARI LLhr resistivity (Ra ) = 20 ohm-m, mud resistivity

(Rm) = 0.02 ohm-m, and borehole size at the zone of interest = 10 in.

Find: True resistivity (Rt).

1 10 100 1,000 10,000

1.5

1.0

0.5

Ra /Rm

R t /Ra

35 ⁄ 8-in. Tool Centered, Active Mode, Thick Beds

68

10

12

Hole diameter (in.)

RLl*Mark of Schlumberger© Schlumberger


High-Resolution Azimuthal Laterolog Sonde (HALS)HLLD B h l C ti O H l

RLl-2



RLl

HLLD Borehole Correction—Open Hole RLl 2

10–1 100 101 102 103 104 105

0.6

0.7

0.8

0.9

1.0

1.1

1.2

HLLD/Rm

R t /HLLD

HLLD Tool Centered (Rm = 0.1 ohm-m)

1.1

1.3

1.5

Borehole Effect, HLLD Tool Centered (Rm = 0.1 ohm-m)

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

dh

6 in.8 in.10 in.12 in.14 in.16 in.18 in.


High-Resolution Azimuthal Laterolog Sonde (HALS)HLLS B h l C ti O H l

RLl-3



RLl

HLLS Borehole Correction—Open Hole

Borehole Effect, HLLS Tool Centered (Rm = 0.1 ohm-m)

dh

6 in.8 in.10 in.

12 in.14 in.16 in.18 in

10–1 100 101 102 103 104 105

0

0.5

1.0

1.5

2.0

2.5

3.0

HLLS/Rm

R t /HLLS

HLLS Tool Centered (Rm = 0.1 ohm-m)

2.0

2.5

3.0

dh

5 in.6 in.8 in.10 in.12 in.14 in.

16 in.


High-Resolution Azimuthal Laterolog Sonde (HALS)HRLD Borehole Correction Open Hole

RLl-4



RLl

HRLD Borehole Correction—Open Hole

HRLD Tool Centered (R m = 0.1 ohm-m)

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

Borehole Effect, HRLD Tool Centered (Rm = 0.1 ohm-m)

10–1 100 101 102 103 104 105

0.4

0.5

0.6

0.7

0.8

1.0

0.9

1.1

R t /HRLD

HRLD/Rm

1.0

1.2

1.4

dh

6 in.8 in.10 in.

12 in.14 in.16 in.18 in


High-Resolution Azimuthal Laterolog Sonde (HALS)HRLS Borehole Correction Open Hole

RLl-5



RLl

HRLS Borehole Correction—Open Hole

HRLS Tool Centered (Rm = 0.1 ohm-m)

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

Borehole Effect, HRLS Tool Centered (Rm = 0.1 ohm-m)

10–1 100 101 102 103 104 105

0

0.5

1.0

1.5

2.0

2.5

3.0

HRLS/Rm

R t /HRLS

2.0

2.5

3.0

R /HRLS

dh

6 in.8 in.10 in.

12 in.14 in.16 in.18 in.


High-Resolution Azimuthal Laterolog Sonde (HALS)HLLD Borehole Correction Eccentered in Open Hole

RLl-6



RLl

HLLD Borehole Correction—Eccentered in Open Hole

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

HLLD Tool Eccentered at Standoff = 0.5 in. (R m = 0.1 ohm-m)

HLLD Tool Eccentered at Standoff = 1.5 in. (R m = 0.1 ohm-m)

1.0

1.1

1.2

R /HLLD

10–1 100 101 102 103 104 105

0.6

0.7

0.8

0.9

1.0

1.1

1.2

HLLD/Rm

R t /HLLD

dh

8 in.10 in.12 in.

14 in.16 in.


High-Resolution Azimuthal Laterolog Sonde (HALS)HLLS Borehole Correction—Eccentered in Open Hole

RLl-7



RLl

HLLS Borehole Correction—Eccentered in Open Hole

0

0.5

1.0

1.5

2.0

2.5

3.0

R t /HLLS

2.0

2.5

3.0

10–1 100 101 102 103 104 105

HLLS/Rm

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

HLLS Tool Eccentered at Standoff = 0.5 in. (R m = 0.1 ohm-m)

dh

8 in.10 in.12 in.

14 in.16 in.

HLLS Tool Eccentered at Standoff = 1.5 in. (R m = 0.1 ohm-m)


High-Resolution Azimuthal Laterolog Sonde (HALS)HRLD Borehole Correction—Eccentered in Open Hole

RLl-8



RLl

HRLD Borehole Correction Eccentered in Open Hole

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

HRLD Tool Eccentered at Standoff = 0.5 in. (R m = 0.1 ohm-m)

0.9

0.8

1.0

1.1

R /HRLD

10–1 100 101 102 103 104 105

0.4

0.6

0.5

0.7

0.8

0.9

1.0

1.1

HRLD/Rm

R t /HRLD

dh

8 in.10 in.12 in.

14 in.16 in.

HRLD Tool Eccentered at Standoff = 1.5 in. (R m = 0.1 ohm-m)


High-Resolution Azimuthal Laterolog Sonde (HALS)HRLS Borehole Correction—Eccentered in Open Hole

RLl-9



RLl

HRLS Borehole Correction Eccentered in Open Hole

0

0.5

1.0

1.5

2.0

2.5

3.0

R t /HRLS

10–1 100 101 102 103 104 105

HRLS/Rm

2.0

2.5

3.0

R /HRLS

HRLS Tool Eccentered Standoff = 0.5 in. (Rm = 0.1 ohm-m)

HRLS Tool Eccentered Standoff = 1.5 in. (Rm = 0.1 ohm-m)

dh

5 in.6 in.8 in.10 in.12 in.14 in.16 in.

dh

8 in.10 in.12 in.

14 in.16 in.


HRLA* High-Resolution Laterolog ArrayBorehole Correction—Open Hole

RLl-10



RLl

Borehole Correction Open Hole

10–1 100 101 102 103 104 105 106

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA1

Tool Centered

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA1

Standoff = 0.5 in.

RLA1/Rm

General



RLl-11



RLl


dh

5 in.6 in.8 in.9 in.10 in.12 in.14 in.16 in.18 in.20 in.

22 in.

10–1 100 101 102 103 104 105 106

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA2

Tool Centered

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA2

Standoff = 0.5 in.

RLA2/Rm



RLl-12



RLl


dh 5 in.6 in.8 in.9 in.10 in.12 in.14 in.16 in.18 in.20 in.

22 in.

10–1 100 101 102 103 104 105 106

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA3

Tool Centered

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA3

Standoff = 0.5 in.

RLA3/Rm



RLl-13



RLl

p

dh 5 in.6 in.8 in.9 in.10 in.12 in.14 in.16 in.18 in.20 in.

22 in.

10–1 100 101 102 103 104 105 106

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA4

Tool Centered

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA4

Standoff = 0.5 in.

RLA4/Rm



RLl-14



RLl

p

dh

5 in.6 in.8 in.9 in.10 in.12 in.14 in.16 in.18 in.20 in.

22 in.

10–1 100 101 102 103 104 105 106

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA5

Tool Centered

2.0

2.5

3.0

1.5

1.0

0.5

0

R t /RLA5

Standoff = 0.5 in.

RLA5/Rm

Resistivity Laterolog—LWD

GeoSteering* Bit Resistivity—6.75-in. ToolBorehole Correction—Open Hole

RLl-20



RLl

p

0

0.5

0.7

0.8

0.9

1.1

1.2

1.0

10–2 10–1 100 101 102 103 104 105

Ra /Rm

24-in. bit

18-in. bit

12-in. bit

0 9

1.2

1.0

1.1

R t /Ra

Resistivity Galvanic—Drillpipe

Resistivity Laterolog–LWD

GeoSteering* arcVISION675* Resistivity—6.75-in. ToolBorehole Correction—Open Hole

RLl-21



RLl

10–2 10–1 100 101 102 103 104 105

Ra /Rm

0

0.5

0.7

0.8

0.9

1.1

1.2

1.0

0 9

1.2

1.0

1.1

R t /Ra

24-in. bit

18-in. bit

12-in. bit


GeoSteering* Bit Resistivity in Reaming Mode—6.75-in. ToolBorehole Correction—Open Hole

RLl-22



RLl

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

1.5

10–2 10–1 100 101 102 103 104 105

R t /Ra

Ra /Rm

arcVISION* tool

Bit

*Mark of Schlumberger© Schlumberger


geoVISION* Resistivity Sub—6.75-in. ToolBorehole Correction—Open Hole

RLl-23



RLl

2

1

R t /Ra

100 101 102 103 104 105

Ra /Rm

Ring Resistivity (with 81 ⁄ 2-in. bit)2

1

R t /Ra

100 101 102 103 104 105

Ra /Rm

Deep Button Resistivity (with 81 ⁄ 2-in. bit)

2

1

R t /Ra

100 101 102 103 104 105

Medium Button Resistivity (with 81 ⁄ 2-in. bit)2

1

R t /Ra

100 101 102 103 104 105

Shallow Button Resistivity (with 81 ⁄ 2-in. bit)

Borehole diameter (in.)

12

16

18

15

8.510

14

13

8.51011

12

13

14

15

Borehole diameter (in.)

8.5

9.5

10.5

11

12

13

10

9.5

9.25

9

8.5

Borehole diameter (in.)Borehole diameter (in.)


geoVISION* Resistivity Sub—8.25-in. ToolBorehole Correction—Open Hole

RLl-24



RLl

2

1

R t /Ra

100 100

100 100

101 102 103 104 105

Ra /Rm

Ring Resistivity (with 121

⁄ 4

-in. bit) 2

1

R t /Ra

101 102 103 104 105

Ra /Rm

Deep Button Resistivity (with 121

⁄ 4-in. bit)

2

1

R t /Ra

101 102 103 104 105

Medium Button Resistivity (with 121 ⁄ 4-in. bit)2

1

R t /Ra

101 102 103 104 105

Shallow Button Resistivity (with 121 ⁄ 4-in. bit)

22

12.2516

17

18

19

20

12.2514

15

16

17

18

2019

12.25

13.514

15

16

17

12.25

12.75

13

13.5

14

Borehole diameter (in.) Borehole diameter (in.)

Borehole diameter (in.)Borehole diameter (in.)

Resistivity Laterlog—LWD

GeoSteering* Bit Resistivity—6.75-in. ToolDistance Out of Formation—Open Hole

RLl-25



RLl

10 ohm-m/4° BUR

100 ohm-m/4° BUR

10 ohm-m/5° BUR

100 ohm-m/5° BUR

10 ohm-m/10° BUR

600

500

400

300

200

100

0

0 2 4 6 8 10 12

Dip angle (°)

Distance (ft)

*Mark of Schlumberger© Schl mberger

General


CHFR* Cased Hole Formation Resistivity ToolCement Correction—Cased Hole

RLl-50



RLl

No cement

0.5 in.

0.75 in.

1.5 in.

3 in.

5 in.

0.2

0.4

0.6

0.8

1.2

1.4

1.6

1.0

CHFR Cement Correction Chart (4.5-in.-OD casing)

R t /Rchfr

General



RLl-51



RLl

0.2

0.4

0.6

0.8

1.2

1.4

1.6

1.0

CHFR Cement Correction Chart (7-in.-OD casing)

R t /Rchfr

No cement

0.5 in.

0.75 in.

1.5 in.

3 in.

5 in.



RLl-52



RLl

No cement

0.5 in.

0.75 in.

1.5 in.

3 in.

5 in.

0.2

0.4

0.6

0.8

1.2

1.4

1.6

1.0

CHFR Cement Correction Chart (9.625-in.-OD casing)

R t /Rchfr

Resistivity Galvanic—Wireline

Resistivity Induction—Wireline

AIT* Array Induction Imager ToolOperating Range—Open Hole



RInd

PurposeThis chart is used to determine the limit of application for the AIT

Array Induction Imager Tool measurement in a salt-saturated borehole.

Description When the AIT tool logs a large salt-saturated borehole, the 10- and

20-in. induction curves may well be unusable because of the large

conductive borehole. In a borehole with a diameter (dh) of 8 in.,

the 10- and 20-in. curve data are usable if R t < 300Rm. The ratio

of the true resistivity to the mud resistivity (Rt /Rm) is proportional

to (dh /8)2.

A general rule is that a 12-in. borehole must have a ratio of Rt /Rm

≤ 133 to have usable shallow log data. Additional requirements are

that the borehole must be round and the AIT tool standoff is 2.5 in.

The value of Rt /Rm is further reduced if the borehole is irregular or

the standoff requirement is not met.

Chart RInd-1 summarizes these requirements. The expected

values of Rt, Rm, borehole size, and standoff size are entered to

accurately determine the usable resolution in a smooth hole. The

lower chart summarizes which AIT resistivity tools typically provide

the most accurate deep resistivity data.

Example: Salt-Saturated BoreholeGiven: Borehole size = 10 in., Rt = 5 ohm-m, Rm =

0.0135 ohm-m, and standoff (so) = 2.5 in.

Find: Which, if any, of the AIT curves are valid.

Answer: From the x-axis equation:

Enter the chart on the x-axis at 346 and move upward

to intersect Rt = 5 ohm-m on the y-axis. The intersection

point is in an error zone for which the shallow induction

curves are not valid even in a round borehole. The

deeper induction curves are valid only with a 2-ft or

larger vertical resolution.

The limits for the 1-, 2-, and 4-ft curves are integral to the chart.

As illustrated, a 1-ft 90-in. curve is not usable in a large salt-saturated

borehole. Also, under these conditions, the 1-, 2-, and 4-ft curves can-

not have the same resistivity response.

Example: Freshwater Mud BoreholeGiven: Borehole size = 10 in., Rt = 5 ohm-m, Rm = 0.135 ohm-m,

and standoff (so) = 1.5 in.

Find: Which, if any, of the AIT curves are valid.

Answer: Rt /Rm = 37.0, (dh /8)2 = (10/8)2 = 1.5625, and (1.5/so) =

1.5/1.5 = 1. The resulting value from the x-axis equation

is 37.0 × 1.5625 × 1 = 57.9.

Enter the chart at 57.9 on the x-axis and intersect

Rt = 5 ohm-m on the y-axis. The intersection point is within the limit of the 1-ft vertical resolution boundary.

All the AIT induction curves are usable.

RR

dso

t

m

h

=8

1 5

2

.


AIT* Array Induction Imager ToolOperating Range—Open Hole

RInd-1



RInd

1,000

100

10

1

0.01 0.1 1 10 100 1,000 10,000 100,000

Limit of 4-ft logs

Possible large errorson all logs

Limit of 1-ft logs

Possible large errors on shallow logs and 2-ft limit

Recommended AIT operatingrange (compute standoff

method for smooth holes)

RR

dh t

m

81 5

2

.so

R t

(ohm-m)

R t(ohm-m)

Salt-saturatedboreholeexample

Freshwatermud example

10,000

1,000

100

AIT 2-ft limit

AIT 4-ft limit

AIT 1-ft limit


AIT* Array Induction Imager ToolBorehole Correction—Open Hole



RInd

IntroductionThe AIT tools (AIT-B, AIT-C, AIT-H, AIT-M, Slim Array Induction

Imager Tool [SAIT], Hostile Environment Induction Imager Tool

[HIT], and SlimXtreme* Array Induction Imager Tool [QAIT]) do not

have chartbook corrections for environmental effects. The normal

effects that required correction charts in the past (borehole correc-

tion, shoulder effect, and invasion interpretation) are now all made

using real-time algorithms for the AIT tools. In reality, the charts for

the older dual induction tools were inadequate for the complexity of

environmental effects on induction tools. The very large volume of

investigation required to obtain an adequate radial depth of investiga-

tion to overcome invasion makes the resulting set of charts too exten-

sive for a book of this size. The volume that affects the logs can be tens

of feet above and below the tool. To make useful logs, the effects of the

volume above and below the layer of interest must be carefully removed.

This can be done only by either signal processing or inversion-based

processing. This section briefly describes the wellsite processing and

advanced processing available at computing centers.

Wellsite Processing

Borehole Correction

The first step of AIT log processing is to correct the raw data from

all eight arrays for borehole effects. Borehole corrections for the AIT

tools are based on inversion through an iterative forward model to

find the borehole parameters that best reproduce the logs from the

four shortest arrays—the 6-, 9-, 12-, and 15-in. arrays (Grove and

Minerbo, 1991). The borehole forward model is based on a solution

to Maxwell’s equations in a cylindrical borehole of radius r with the

mud resistivity (Rm) surrounded by a homogeneous formation of

resistivity Rf . The tool can be located anywhere in the borehole, but

is parallel to the borehole axis at a certain tool standoff (so). The

Because the AIT borehole model is a circular hole, either axis

from a multiaxis caliper can be used. If the tool standoff is adequate,

the process finds the circular borehole parameters that best match

the input logs. Control of adequate standoff is important because

the changes in the tool reading are very large for small changes in

tool position when the tool is very close to the borehole wall. Near

the center of the hole the changes are very small. A table of rec-

ommended standoff sizes is as follows.

Each type of AIT tool requires a slightly different approach to

the borehole correction method. For example, the AIT-B tool requires

the use of an auxiliary Rm measurement (Environmental

Measurement Sonde [EMS]) to compute Rm or to compute hole

size by using a recalibration of the mud resistivity method internal

to the borehole correction algorithm. The Platform Express*,

SlimAccess*, and Xtreme* AIT tools have integral Rm sensors that

meet the accuracy requirements for the compute standoff mode.

AIT Tool Recommended Standoff

Hole Size (in.) Recommended Standoff (in.)AIT-B, AIT-C, AIT-H, AIT-M, HIT SAIT, QAIT

<5.0 – 0.5

5.0 to 5.5 – 1.0

5.5 to 6.5 0.5 1.5

6.5 to 7.75 1.0 2.0

7.75 to 9.5 1.5 2.5

9.5 to 11.5 2.0 + bowspring† 2.5

>11.5 2.5 + bowspring† 2.5

Note: Do not run AIT tools slick.† Only for AIT-H tool





RInd

ties, with the crossover occurring between 100 and 200 mS/m. The

use of the R-signal at low conductivities overcomes the errors in

the X-signal associated with the normal magnetic susceptibilities

of sedimentary rock layers (Barber et al., 1995).

The weights w in the equation can profit from further refine-

ment. The method used to compute the weights introduces a small

amount of noise in the matrix inversion, so the fit is about ±1% to

±2% to the defined target response. A second refinement filter is

used to correct for this error. The AIT wellsite processing sequence,

from raw, calibrated data to corrected logs, is shown in Fig. 1.

(Freedman and Minerbo, 1991, 1993; Zhang et al., 1994). Maximum-

Entropy Resistivity Log Inversion (MERLIN) processing (Barber et

al., 1999) follows Freedman and Minerbo (1991) closely, and that

paper is the basic reference for the mathematical formulation. The

problem is set up as the simplest parametric model that can fit the

data: a thinly layered formation with each layer the same thickness

(Fig. 2). The inversion problem is to solve for the conductivity of

each layer so that the computed logs from the layered formation

are the closest match to the measured logs.

10 in.

20 in.

30 in.

60 in.90 in.

28 channels(AIT-B, -C, and -D)16 channels

(all others)

Skineffect

correction

Multichannelsignal

processingand 2D

processing

14or8

28or16

Boreholecorrection

Caliper

Rm

Standoff

A(H)IFC

R-signals only

R-signalsX-signals

28or16

Five depths(10 to 90 in.)

Five depths(10 to 90 in.)

Exceptionhandling and

environmentally

compensatedlog processing

Rm

Caliper

Raw BHC signals

+

Figure 1. Block diagram of the real-time log processing chain from raw, calibrated array data to finished logs.





Rxo

Rxo

R t

ri

Formation

resistivity

Distance from wellbore

Step Profile

Slope Profile

r1

RInd

Borehole-correctedR- and X-signals

Model parameters

Sensitivitymatrix

Update model

parameters

No

28 or 16 channels

Computedlog within 1%

of measuredlog?

Computed log

Forward model

Initial guess

ComputeLagrangian

The flow of MERLIN processing is shown in Fig. 3. The borehole-

corrected raw resistive and reactive (R- and X-) signals are used as

a starting point. The conductivity of a set of layers is estimated from

the log values, and the iterative modeling is continued until the logs

converge. The set of formation layer conductivity values is then con-

verted to resistivity and output as logs.

Invasion Processing

The wellsite interpretation for invasion is a one-dimensional (1D)inversion of the processed logs into a four-parameter invasion model

(R xo, Rt, r1, and r2, shown in Fig. 4). The forward model is based on

the Born model of the radial response of the tools and is accurate for

most radial contrasts in which induction logs should be used. The

inversion can be run in real time. The model is also available in the

Invasion Correction module of the GeoFrame* Invasion 2 application,

which also includes the step-invasion model and annulus model (Fig. 4).





RInd

R t0

∞

∞

R t1

R t2

Rxo1

Rxo2

Rm

Rm

Another approach is also used in the Invasion 2 application mod-

ule. If the invaded zone is more conductive than the noninvaded

zone, some 2D effects on the induction response can complicate

the 1D inversion. Invasion 2 conducts a full 2D inversion using a

2D forward model (Fig. 5) to produce a more accurate answer for

situations of conductive invasion and in thin beds.

References Anderson, B., and Barber, T.: Induction Logging, Sugar Land, TX,

USA, Schlumberger SMP-7056 (1995).

Barber, T.D.: “Phasor Processing of Induction Logs Including

Shoulder and Skin Effect Correction,” US Patent No. 4,513,376

(September 11, 1984).

Barber, T., et al.: “Interpretation of Multiarray Induction Logs in

Invaded Formations at High Relative Dip Angles,” The Log Analyst,

(May–June 1999) 40, No. 3, 202–217.

Barber, T., Anderson, B., and Mowat, G.: “Using Induction Tools toIdentify Magnetic Formations and to Determine Relative Magnetic

Susceptibility and Dielectric Constant,” The Log Analyst

(July–August 1995) 36, No. 4, 16–26.

Barber, T., and Rosthal, R.: “Using a Multiarray Induction Tool to

Achieve Logs with Minimum Environmental Effects,” paper SPE 22725

presented at the SPE Annual Technical Conference and Exhibition,

Dallas, Texas, USA (October 6–9, 1991).

Dyos, C.J.: “Inversion of the Induction Log by the Method of MaximumEntropy,” Transactions of the SPWLA 28th Annual Logging

Symposium, London, UK (June 29–July 2, 1987), paper T.

Freedman, R., and Minerbo, G.: “Maximum Entropy Inversion of the

Induction Log,” SPE Formation Evaluation (1991), 259–267; also

paper SPE 19608 presented at the SPE Annual Technical Conference

and Exhibition, San Antonio, TX, USA (October 8–11, 1989).

Freedman, R., and Minerbo, G.: “Method and Apparatus for

Producing a More Accurate Resistivity Log from Data Recorded by anInduction Sonde in a Borehole,” US Patent 5,210,691 (January 1993).

Figure 5. The parametric 2D formation model used in Invasion 2.

arcVISION475* and ImPulse* 43 ⁄ 4-in. ArrayResistivity Compensated Tools—2 MHzB h l C ti O H l

Resistivity Electromagnetic—LWD



Borehole Correction—Open Hole

PurposeThis chart is used to determine the borehole correction applied

by the surface acquisition system to arcVISION475 and ImPulsephase-shift (Rps) and attenuation resistivity (Rad) curves on the

log. The value of Rt is used in the calculation of water saturation.

DescriptionEnter the appropriate chart for the borehole environmental condi-

tions and tool used to measure the various formation resistivities

with the either the uncorrected phase-shift or attenuation resistivity

value (not the resistivity shown on the log) on the x-axis. Move upward

to intersect the appropriate resistivity spacing line, and then movehorizontally left to read the ratio value on the y-axis. Multiply the

ratio value by the resistivity value entered on the x-axis to obtain Rt.

Charts REm-12 through REm-38 are used similarly to Chart

REm-11 for different borehole conditions and arcVISION* and

ImPulse tool combinations.

ExampleGiven: Rps = 400 ohm-m (uncorrected) from arcVISION475

(2-MHz) phase-shift 10-in. resistivity, borehole size =6 in., and mud resistivity (Rm) = 0.02 ohm-m at forma-

tion temperature.

Find: Formation resistivity (Rt).

Answer: Enter the top left chart at 400 ohm-m on the x-axis

and move upward to intersect the 10-in. resistivity

curve (green).

Move left and read approximately 1.075 on the y-axis.

Rt = 1.075 × 400 = 430 ohm-m.

REm


arcVISION475* and ImPulse* 43 ⁄ 4-in. ArrayResistivity Compensated Tools—2 MHzBorehole Correction Open Hole

REm–11



REm


1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

arcVISION475 and ImPulse Borehole Correction for 2 MHz, dh = 6 in., Rm = 0.02 ohm-m

10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


arcVISION475* and ImPulse* 43 ⁄ 4-in. ArrayResistivity Compensated Tools—2 MHzBorehole Correction Open Hole

REm-12





1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


arcVISION475 and ImPulse Borehole Correction for 2 MHz d 7 in R 1 0 ohm m

REm


arcVISION475* and ImPulse* 43 ⁄ 4-in. ArrayResistivity Compensated Tools—2 MHzBorehole Correction—Open Hole

REm-13



REm


1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10 –1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


S


arcVISION475* and ImPulse* 43 ⁄ 4-in. ArrayResistivity Compensated Tools—2 MHzBorehole Correction—Open Hole

REm-14



REm


1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


VISION475 d I P l B h l C ti f 2 MH d 10 i R 1 0 h


arcVISION675* 63 ⁄ 4-in. Array Resistivity Compensated Tool—400 kHzBorehole Correction—Open Hole

REm-15



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

arcVISION675 Borehole Correction for 400 kHz, dh = 8 in., Rm = 0.02 ohm-m

10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


VISION6 B h l C i f 00 kH d 8 i R 0 h



REm-16



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


VISION675 B h l C ti f 400 kH d 10 i R 1 0 h

General



REm-17



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


arcVISION675 Borehole Correction for 400 kHz d 12 in R 1 0 ohm m



REm-18



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad




arcVISION675* 63 ⁄ 4-in. Array Resistivity Compensated Tool—2 MHzBorehole Correction—Open Hole

REm-19



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

arcVISION675 Borehole Correction for 2 MHz, dh = 8 in., Rm = 0.02 ohm-m

10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


arcVISION675 Borehole Correction for 2 MHz d 8 in R 1 0 ohm m


arcVISION675* 63 ⁄ 4-in. Array Resistivity Compensated Tool—2 MHzBed Thickness Correction—Open Hole

REm-20



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


VISION675 B h l C i f 2 MH d 10 i R 1 0 h



REm-21



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad


VISION675 B h l C ti f 2 MH d 12 i R 1 0 h



REm-22



REm

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5

1.0

2.0

1.5

0.5


10–1

10–1 100 101 102 103 10–1 100 101 102 103

100 101 102 103 10–1 100 101 102 103

Rps (ohm-m)

Rps (ohm-m)

Rad (ohm-m)

Rad (ohm-m)

R t /Rps R t /Rad

R t /Rps R t /Rad




REm-23



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

VISION825 B h l C i f 400 kH d 10 i R 1 0 h

10–1 100 101 102 103 10–1 100 101 102 103


arcVISION825* 81 ⁄ 4-in. Array Resistivity Compensated Tool—400 kHzBed Thickness Correction—Open Hole

REm-24



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-25



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-26



REm

arcVISION825 Borehole Correction for 400 kHz, dh = 18 in., R

m = 0.02 ohm-m


10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-27



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

10–1 100 101 102 103 10–1 100 101 102 103



REm-28



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-29



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-30



REm

arcVISION825 Borehole Correction for 2 MHz, dh = 18 in., R

m = 0.02 ohm-m


10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103


arcVISION900* 9-in. Array Resistivity Compensated Tool—400 kHzBorehole Correction—Open Hole

REm-31



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

VISION900 B h l C i f 400 kH d 12 i R 1 0 h

10–1 100 101 102 103 10–1 100 101 102 103



REm-32



REm


m = 0.02 ohm-m


10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-33



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-34



REm


m = 0.02 ohm-m


10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103


arcVISION900* 9-in.Array Resistivity Compensated Tool—2 MHzBorehole Correction—Open Hole

REm-35



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103


arcVISION900* 9-in. Array Resistivity Compensated Tool—2 MHzBorehole Correction—Open Hole

REm-36



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

VISION900 B h l C i f 2 MH d 15 i R 1 0 h

10–1 100 101 102 103 10–1 100 101 102 103



REm-37



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103



REm-38



REm



10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

10–1 100 101 102 103

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)

2.0

1.5

1.0

0.5

R t /Rps

Rps (ohm-m)

2.0

1.5

1.0

0.5

R t /Rad

Rad (ohm-m)


10–1 100 101 102 103 10–1 100 101 102 103


arcVISION675*, arcVISION825*, and arcVISION900*Array Resistivity Compensated Tools—400 kHzBed Thickness Correction—Open Hole



REm

PurposeThis chart is used to determine the correction factor applied by the

surface acquisition system for bed thickness to the phase-shift andattenuation resistivity on the logs of arcVISION675, arcVISION825,

and arcVISION900 tools.

DescriptionThe six bed thickness correction charts on this page are paired for

phase-shift and attenuation resistivity at different values of true (Rt)

and shoulder bed (Rs) resistivity. Only uncorrected resistivity values

are entered on the chart, not the resistivity shown on the log.

Chart REm-56 is also used to find the bed thickness correctionapplied by the surface acquisition system for 2-MHz arcVISION* and

ImPulse* logs.

ExampleGiven: Rt /Rs = 10/1, Rps uncorrected = 20 ohm-m (34 in.), and

bed thickness = 6 ft.Find: Rt.

Answer: The appropriate chart to use is the phase-shift resistivity

chart in the first row, for Rt = 10 ohm-m and Rs = 1 ohm-m.

Enter the chart on the x-axis at 6 ft and move upward

to intersect the 34-in. spacing line. The corresponding

value of Rt /Rps is 1.6; Rt = 20 × 1.6 = 32 ohm-m.

arcVISION675*, arcVISION825*, and arcVISION900*Array Resistivity Compensated Tools—400 kHzBed Thickness Correction—Open Hole

REm-55




Phase-Shift Resistivity Attenuation Resistivity

Attenuation Resistivity

arcVISION675, arcVISION825, and arcVISION900 400-kHzBed Thickness Correction for R t = 10 ohm-m and Rs = 1 ohm-m at Center of Bed

0 2 4 6 8 10 12 14 16

2.0

1.5

1.0

0.5

0

R t /Rps R t /Rad

Bed thickness (ft)

0 2 4 6 8 10 12 14 16

2.0

1.5

1.0

0.5

0

Bed thickness (ft)

Phase-Shift Resistivity

arcVISION675, arcVISION825, and arcVISION900 400-kHzBed Thickness Correction for R t = 1 ohm-m and Rs =10 ohm-m at Center of Bed

2.0

1.5

1.0

0.5

0

R t /Rps R t /Rad

2.0

1.5

1.0

0.5

0

REm


arcVISION* and ImPulse* Array Resistivity Compensated Tools—2 MHzBed Thickness Correction—Open Hole

REm-56



REm

Phase-Shift Resistivity Attenuation Resistivity


arcVISION and ImPulse 2-MHz Bed Thickness Correction forR t = 10 ohm-m and Rs =1 ohm-m at Center of Bed

0 2 4 6 8 10 12 14 16

2.0

1.5

1.0

0.5

0

R t /Rps R t /Rad

Bed thickness (ft)

0 2 4 6 8 10 12 14 16

2.0

1.5

1.0

0.5

0

Bed thickness (ft)


arcVISION and ImPulse 2-MHz Bed Thickness Correction forR t = 1 ohm-m and Rs =10 ohm-m at Center of Bed

2.0

1.5

1.0

0.5

0

R t /Rps R t /Rad

2.0

1.5

1.0

0.5

0


arcVISION675* and ImPulse* Array ResistivityCompensated Tools—2 MHz and 16-in. SpacingDielectric Correction—Open Hole

REm-58



REm

8.20

8.25

8.30

8.35

8.40

8.45

8.50

8.55

8.60

Attenuation(dB)

1

10

20

30

40

50

60

70

80

90

100

125

150

175

200

225

3 0

5 0

7 0

1 0 0

1 5

2 0

1 ,

0 0 0

1 0 ,

0 0 0

R t

o



REm-59



REm

6.5

6.6

6.7

6.8

6.9

Attenuation(dB)

1

10

20

30

40

50

60

70

80

90

100

125

150

3 0

5 0

7 0

1 0 0

1 5

2 0

1 , 0

0 0

1 0 ,

0 0 0

o

R t



REm-60



REm

o

5.1

5.2

5.3

5.4

5.5

Attenuation(dB)

1

10

20

30

40

50

60

70

80

90

100

125

150

175

3 0

5 0

7 0

1 0 0

2 0

1 ,

0 0 0

1 0 ,

0 0 0

R t

o



REm-61



REm4.2

4.3

4.4

4.5

4.6

4.7

Attenuation(dB)

1

10

20

30

40

50

60

70

80

90

100

125

3 0

5 0

7 0

1 0 0

1 5

2 0

1 , 0

0 0

1 0 ,

0 0 0

o

R t



REm-62



REm

3.4

3.5

3.6

3.7

3.8

3.9

4.0

Attenuation(dB)

1

10

20

30

40

50

60

70

80

90

100

125

3 0

5 0

7 0

1 0 0

1 5

2 0

1 ,

0 0 0

1 0 ,

0 0 0

R t

o


arcVISION675* and ImPulse* Array ResistivityCompensated Tools—2 MHz with Dielectric AssumptionDielectric Correction—Open Hole

REm-63



REm

10–1

1.0

1.5

2.0

2.5

3.0

3.5

Dielectric Effects of Standard Processed arcVISION675 or ImPulse Log

at 2 MHz with Dielectric Assumption

100 101 102 103 104

R t /Rps

Rps (ohm-m)

3.5

0.5

16 in.

22 in.

28 in.

34 in.

40 in.

Resistivityspacing

Resistivityspacing

Dielectric assumptionεr = 5 + 108.5R–0.35

ε1 = 2εr

ε2 = 0.5εr

o

General

Formation Resistivity—Wireline

Resistivity GalvanicInvasion Correction—Open Hole

Rt-1(former Rint-1)

Purpose If S A and S R are equal the assumption of a step contact inva



Purpose

The charts in this chapter are used to determine the correction for

invasion effects on the following parameters: diameter of invasion (di) ratio of flushed zone to true resistivity (R xo /Rt) Rt from laterolog resistivity tools.

The R xo /Rt and Rt values are used in the calculation of water

saturation.

DescriptionThe invasion correction charts, also referred to as “tornado” or “but-

terfly” charts, assume a step-contact profile of invasion and that allresistivity measurements have already been corrected as necessary

for borehole effect and bed thickness by using the appropriate chart

from the “Resistivity Laterolog” chapter.

To use any of these charts, enter the y-axis and x-axis with the

required resistivity ratios. The point of intersection defines di,

R xo /Rt, and Rt as a function of one resistivity measurement.

Saturation Determination in Clean Formations

Either of the chart-derived values of Rt and R xo /Rt are used to find values for the water saturation of the formation (S w ). The first of two

approaches is the S w -Archie (S wA ), which is found using the Archie

saturation formula (or Chart SatOH-3) with the derived Rt value and

known values of the formation resistivity factor (FR) and the resistiv-

ity of the water (R w ). The S w -ratio (S wR) is found by using R xo /Rt and

Rmf /R w as in Chart SatOH-4.

If S wA and S wR are equal, the assumption of a step-contact inva-

sion profile is indicated to be correct, and all values determined

(S w , Rt, R xo, and di) are considered good.If S wA > S wR, either invasion is very shallow or a transition-type

invasion profile is indicated, and S wA is considered a good value for S w .

If S wA < S wR, an annulus-type invasion profile may be indicated,

and a more accurate value of water saturation may be estimated

by using

The correction factor of (S wA /S wR)1 ⁄4 is readily determined from

the scale.

For more information, see Reference 9.

SwA /SwR

S SS

S wcor wA wA

wR

=

1

4


High-Resolution Azimuthal Laterolog Sonde (HALS)Formation Resistivity and Diameter of Invasion—Open Hole

Rt-2



0.2

0.5

5

10

20

50

100

200

500

1,000

8 15 18 20 22 24 28 32 3640

45

50

60

80

100

120

di (in.)

2

103

102

101

100

HLLD/Rxo

Thick Beds, 8-in. Hole, Rxo /Rm = 10

R t /Rxo


High-Resolution Azimuthal Laterolog Sonde (HALS)Formation Resistivity and Diameter of Invasion—Open Hole

Rt-3



Thick Beds, 8-in. Hole, Rxo /Rm = 10

HRLD/Rxo

di (in.)

1,000

8 15 18 20 22 24 28 32 3640

45

50

60

80

100

120

0.2

0.5

2

103

102

101

100

500

200

100

50

20

10

5

R t /Rxo

Formation Resistivity—LWD

geoVISION675* ResistivityFormation Resistivit y and Diameter of Invasion—Open Hole

Rt-10



Ring, Deep, and Medium Button Resistivity (6.75-in. tool)

10

1

2

3

5

6

7

8

9

4Rring /Rbm

10070

50

30

20

15

10

7

5

3

2

24

22

20

1817

16

15

14

13

12

di

3.0

2.42.01.81.6

1.5

1.4

1.3

1.2

R t /Rring

R t /Rxo

Rxo /Rm = 50

dh = 8.5 in.


geoVISION675* ResistivityFormation Resistivity and Diameter of Invasion—Open Hole

Rt-11



Deep, Medium, and Shallow Button Resistivity (6.75-in. tool)

30

1

3

5

6

8

7

910

20

4

Rbd /Rbs

2

10070

50

30

20

15

10

7

5

3

18

17

16

151413

12

11

1.6

1.51.41.31.2

1.1

di

2

1

R t /Rbd

R t /Rxo

Rxo /Rm = 50dh = 8.5 in.



Rt-12



Bit, Ring, and Deep Button Resistivity (6.75-in. tool) with ROP to Bit Face = 4 ft

10

1

2

3

5

67

8

9

4Rbit /Rbd

24

10070

50

30

20

15

10

7

5

3

2

1

50

40

34

28

22

20

18

16

4.03.0

2.5

2.0

1.8

1.6

1.4

di

R t /Rbit

R t /Rxo

Rxo /Rm = 50

dh = 8.5 in.



Rt-13



Bit, Ring, and Deep Button Resistivity (6.75-in. tool) with ROP to Bit Face = 35 ft

1

3

5

6

8

7

910

20

4

Rbit /Rbd

2

24

22

1.4

1.3

100

70

50

30

20

15

10

7

5

3

2

1

70

5034

28

20

18

16

2.42.0

1.6

1.2

Rxo /Rm = 50dh = 8.5 in.

di

R t /Rbit

R t /Rxo


geoVISION825* 81 ⁄ 4-in. Resistivity-at-the-Bit ToolFormation Resistivity and Diameter of Invasion—Open Hole

Rt-14



Ring, Deep, and Medium Button Resistivity (81 ⁄ 4-in. tool)

10

1

2

3

5

6

7

8

9

4

Rring /Rbm

1.2

17

10070

50

30

20

15

10

7

5

3

2

1

30

26

242322

21

20

19

18

16

3.0

2.41.8

1.6

1.4

1.3

R t /R

ring

di

R t /Rxo

Rxo /Rm = 50dh = 12.25 in.



Rt-15



Deep, Medium, and Shallow Button Resistivity (81 ⁄ 4-in. tool)

1

3

5

6

8

7

910

20

4

Rbd /Rbs

2

10070

50

30

20

15

10

7

5

3

2

1

24

22

2019

18

17

16

14

2.4

2.0

1.61.41.3

1.2

1.1

di

R t /Rbd

R t

/Rxo

Rxo /Rm = 50

dh = 12.25 in.



Rt-16



10

1

2

3

5

6

7

8

9

4

Rbit /Rbd

Bit, Ring, and Deep Button Resistivity (81 ⁄ 4-in. tool) with ROP to Bit Face = 4 ft

10070

50

30

20

15

10

7

5

3

2

60

50

40

35

30

28

26

24

22

20

5.0

3.02.4

2.0

1.8

1.6

1.5

1.4

1.3

1

di

R t /Rbit

R t /Rxo

Rxo /Rm = 50

dh = 12.25 in.



Rt-17



Bit, Ring, and Deep Button Resistivity (81 ⁄ 4-in. tool) with ROP to Bit Face = 35 ft

1

3

5

6

8

7

910

20

4

Rbit /Rbd

2

R t /Rxo = 50

dh = 12.25 in.

di

R t /Rbit

R t /Rxo

100

70

50

30

20

15

10

7

5

3

2

1

70

5040

35

30

28

26

24

22

20

3.02.0

1.6

1.4

1.3

1.2

arcVISION* Array Resistivity Compensated Tool—400 kHzResistivity Anisotropy Versus Shale Volume—Open Hole

Rt-31

Formation Resist ivity—LWD



101


0 0.2 0.4 0.6 0.8 1.0100

101Phase-Shift Resistivity

Rps (ohm-m)

Vsh

Response Through Sand and Shale Layers at 90° Relative Dip

for Rsh = 1 ohm-m and Rsand = 5 ohm-m

100

Rad

(ohm-m)

0 0 2 0 4 0 6 0 8 1 0



Response Through Sand and Shale Layers at 90° Relative Dip

for Rsh = 1 ohm-m and Rsand = 20 ohm-m

101

100

0

Rps

(ohm-m)

0.2 0.4 0.6 0.8 1.0

Vsh

102

101

100

0

Rad

(ohm-m)

0 2 0 4 0 6 0 8 1 0

102


arcVISION* and ImPulse* Array Resistivity Compensated Tools—2 MHzResistivity Anisotropy Versus Shale Volume—Open Hole

Rt-32




Response Through Sand and Shale Layers at 90° Relative Dipfor Rsh = 1 ohm-m and Rsand = 20 ohm-m

101

100

102

101

100

102Phase-Shift Resistivity

Response Through Sand and Shale Layers at 90° Relative Dipfor Rsh = 1 ohm-m and Rsand = 5 ohm-m

101

100

102

101

100

102

0 0.2 0.4 0.6 0.8 1.0

Vsh

Rps

(ohm-m)

0

Rps

(ohm-m)

0.2 0.4 0.6 0.8 1.0

Vsh

Attenuation ResistivityAttenuation Resistivity

Rad

(ohm-m)

Rad

(ohm-m)

0 6 0 8 0

arcVISION* Array Resistivity Compensated Tool—400 kHzResistivity Anisotropy Versus Dip—Open Hole

Rt-33





Aniostropy Response for Rh = 1 ohm-m and (Rv /Rh) = 5

101

100

0 2010 40 60 80 90

Relative dip angle (°)

103

102

30 50 70 0 2010 40 60 80 90


30 50 70

Attenuation Resistivity Attenuation Resistivity103

101

100

102



100

101

100

101

Rps

(ohm-m)

Rad

(ohm-m)

Rps

(ohm-m)

Rad

(ohm-m)

Formation Resist ivity—LWD

arcVISION* and ImPulse* Array Resistivity Compensated Tools—2 MHzResistivity Anisotropy Versus Dip—Open Hole

Rt-34







101

100

103

102

103

101

102

Rps

(ohm-m)

Rad

(ohm-m)

0 2010 40 60 80 90


30 50 70

100

101

101

Rps

(ohm-m)

Rad

(ohm-m)

0 2010 40 60 80 90


30 50 70

Attenuation Resistivity Attenuation Resistivity


arcVISION* Array Resistivity Compensated Tool—400 kHzResistivity Anisotropy Versus Square Root of Rv /Rh—Open Hole

Rt-35




Aniostropy Response at 85° dip for Rh = 1 ohm-m

101

100

1.0

Rps

(ohm-m)

2.01.5 3.0 4.0 5.0

(Rv /Rh)

103

102

101

100

Rad

(ohm-m)

103

102

2.5 3.5 4.5 1.0 2.01.5 3.0 4.0 5.02.5 3.5 4.5




100

Rps

(ohm-m)

101

101

100

Rad

(ohm-m)

(Rv /Rh)


arcVISION* and ImPulse* Array Resistivity Compensated Tools—2 MHzResistivity Anisotropy Versus Square Root of Rv /Rh—Open Hole

Rt-36







1.0 2.01.5 3.0 4.0 5.02.5 3.5 4.5 1.0 2.01.5 3.0 4.0 5.0

(Rv /Rh)

2.5 3.5 4.5


101

100

Rps

(ohm-m)

103

102

101

100

Rad

(ohm-m)

103

102

100

Rps

(ohm-m)

101

101

100

Rad

(ohm-m)

(Rv /Rh)


arcVISION675* Array Resistivity Compensated Tool—400 kHzConductive Invasion—Open Hole

Rt-37



16-in. Rps /40-in. Rad 0.1

1.0

Rxo and di for R t ~ 10 ohm-m

16

20

2428

32

364044

48

52

56

60

64

0.15

0.2

0.3

0.5

0.7

1

1.5

2

3

5

7

0.95

0.9

0.80.85

0.750.7

0.650.6

0.55

40-in. Rad /R t = 1

di (in.)

Rxo = 0.1 ohm−m


arcVISION675* and ImPulse* Array Resistivity Compensated Tools—2 MHzConductive Invasion—Open Hole

Rt-38



16-in. Rps /40-in. Rad

1.0


0.3

0.5

7

0.7

1

1.5

2

3

5

16

40

44

48 52

d (in )

56

0.2

40-in. Rad /R t = 1

0.9

0.8

0.7

0.6

0.2

0.1


arcVISION* Array Resistivity Compensated Tool—400 kHzResistive Invasion—Open Hole

Rt-39

R d d f R 10 h



40

45

50

55

60

65

70

75

80

90

100

125

200

150

100

70

50di (in.)

Rxo = 300 ohm-m


10


0 95

0.9

0.85

0.8

0.75

0.7

0.65

0.6

0.55


arcVISION* and ImPulse* Array Resistivity Compensated Tools—2 MHzResistive Invasion—Open Hole

Rt-40





1.6

2.0

2.2

2.4

1.8

40

55

60

di (in.)

200

150

100

70

5035

45

0.8

0.75

0.7

0.65

0.55

0.6

50

65

Rxo = 300 ohm-m

arcVISION* Array Resistivity Compensated Tool—400 kHz in Horizontal WellBed Proximity Effect—Open Hole


Purpose

Charts Rt 41 and Rt 42 are used to calculate the correction applied

Example



Charts Rt-41 and Rt-42 are used to calculate the correction applied

to the log presentation of Rt from the arcVISION tool at theapproach to a bed boundary. The value of Rt is used to calculate

water saturation.

Description

There are two sets of charts for differing conditions:

shoulder bed resistivity (Rshoulder) = 10 ohm-m and Rt = 1 ohm-m

Rshoulder = 10 ohm-m and Rt =100 ohm-m.

Given: Rshoulder = 10 ohm-m, Rt = 1 ohm-m, and

16-in. Rps = 1.5 ohm-m.

Find: Bed proximity effect.

Answer: The top set of charts is appropriate for these resistivity

values. The ratio Rps /Rt = 1.5/1 = 1.5.

Enter the y-axis of the left-hand chart at 1.5 and move

horizontally to intersect the 16-in. curve. The corre-

sponding value on the x-axis is 1 ft, which is the distance

of the surrounding bed from the tool. At 2 ft from the

bed boundary, the value of 16-in. Rps = 1 ohm-m.

Formation Resistivity–Drill Pipe


arcVISION* Array Resistivity Compensated Tool—400 kHz in Horizontal WellBed Proximity Effect—Open Hole

Rt-41



0 1 2 3 4 5 6 7 8 9 100

1

2

3

Distance to bed boundary (ft)

0 1 2 3 4 5 6 7 8 9 10

Rps /R t

Bed Proximity Effect for Horizontal Well: Rshoulder = 10 ohm-m and R t = 1 ohm-m

0 1 2 3 4 5 6 7 8 9 100

1

2

3


Rad /R t

0 1 2 3 4 5 6 7 8 9 10

0

1

2

3

Rps /R t

0

1

2

3

Rad /R t

Bed Proximity Effect for Horizontal Well: Rshoulder = 10 ohm-m and R t = 100 ohm-m


arcVISION* and ImPulse* Array Resistivity Compensated Tools—2 MHzin Horizontal WellBed Proximity Effect—Open Hole

Rt-42



Bed Proximity Effect for Horizontal Well: Rshoulder = 10 ohm-m, R t = 1 ohm-m

Bed Proximity Effect for Horizontal Well: Rshoulder = 10 ohm-m, R t = 100 ohm-m

0

1

2

3

Rps /R t

0 1 2 3 4 5 6 7 8 9 10


0

1

2

3

Rps /R t

0 1 2 3 4 5 6 7 8 9 10 0 1 2 3 4 5 6 7 8 9 10

0

1

2

3

Rad /R t

0 1 2 3 4 5 6 7 8 9 10


0

1

2

3

Rad /R t

General

General

Lithology—Wireline

Density and NGS* Natural Gamma Ray Spectrometry ToolMineral Identification—Open Hole

PurposeThis chart is a method for identifying the type of clay in the wellbore.

ExampleGiven: Environmentally corrected thorium concentration



This chart is a method for identifying the type of clay in the wellbore.

The values of the photoelectric factor (Pe) from the Litho-Density*log and the concentration of potassium (K) from the NGS Natural

Gamma Ray Spectrometry tool are entered on the chart.

DescriptionEnter the upper chart with the values of Pe and K to determine the

point of intersection. On the lower chart, plotting Pe and the ratio

of thorium and potassium (Th/K) provides a similar mineral evalua-

tion. The intersection points are not unique but are in general areas

defined by a range of values.

Given: Environmentally corrected thorium concentration

(ThNGScorr) = 10.6 ppm, environmentally correctedpotassium concentration (KNGScorr) = 3.9%, and Pe = 3.2.

Find: Mineral concentration of the logged clay.

Answer: The intersection points from plotting values of Pe and K

on the upper chart and Pe and Th/K ratio = 10.6/3.9 = 2.7

on the lower chart suggest that the clay mineral is illite.


Density and NGS* Natural Gamma Ray Spectrometry ToolMineral Identification—Open Hole

Lith-1(former CP-18)



Potassium concentration, K (%)

Photoelectricfactor, Pe

Glauconite

Chlorite Biotite

Illite

MuscoviteMontmorillonite

Kaolinite

0 2 4 6 8 10

10

8

6

4

2

0

10


NGS* Natural Gamma Ray Spectrometry ToolMineral Identification—Open Hole




0 1 2 3 4 5

Potassium (%)

25

20

15

10

5

0

Thorium(ppm)

M i x e d - l

a y e r c l a y

I l l i t e M i c a

s

G laucon i te

Potassium evaporites, ~30% feldspar

~30% glauconite

~70% illite

100% illite point

~40%mica

M o n t m

o r i l l o n i t e

C h l o r i t

e

Kaolinite

Possible 100% kaolinite,montmorillonite,illite “clay line”

T h / K

= 2 5

T h / K

= 1 2

T h / K =

3. 5

T h/ K = 2. 0

Th /K = 0.6

Th /K = 0.3Feldspar

H e a v y

t h o r i u

m - b e a r i n g

m i n

e r a l s

PurposeThis chart is used to determine the lithology and porosity of a forma-

ExampleGiven: Freshwater drilling mud, Pe = 3.0, and bulk density =


Platform Express* Three-Detector Lithology Density ToolPorosity and Lithology—Open Hole



gy p y

tion. The porosity is used for the water saturation determination andthe lithology helps to determine the makeup of the logged formation.

DescriptionNote that this chart is designed for fresh water (fluid density

[ρf ] = 1.0 g/cm3) in the borehole. Chart Lith-4 is used for saltwater

(ρf = 1.1 g/cm3) formations.

Values of photoelectric factor (Pe) and bulk density (ρb) from the

Platform Express Three-Detector Lithology Density (TLD) tool are

entered into the chart. At the point of intersection, porosity and

lithology values can be determined.

g , , y

2.73 g/cm

3

.Freshwater drilling mud, Pe = 1.6, and bulk density =

2.24 g/cm3.

Find: Porosity and lithology.

Answer: For the first set of conditions, the formation is a

dolomite with 8% porosity.

The second set is for a quartz sandstone formation

with 30% porosity.






1.9

2.0

2.1

2.2

2.3

2.4

2.5

Bulk density, ρb

(g/cm3)

4 0

3 0

2 0

1 0

4 0

3 0

2 0

4 0

3 0

2 0

1 0

0

Q u a r t z s a n d s t o n e

D o l o m i t e

C a l c i t e ( l i m e s t o n e )

S a

l t

Fresh Water (ρf = 1.0 g/cm3), Liquid-Filled Borehole




Salt Water (ρf = 1.1 g/cm3), Liquid-Filled Borehole



1.9

2.0

2.1

2.2

2.3

2.4

2.5

2 6

Bulk density, ρb

(g/cm3)

4 0

3 0

2

0

1 0

4 0

3 0

2 0


D o l o m i t e

4 0

3 0

2 0

1

0

C a l c i t e ( l i m

e s t o n e )

0 S a

l t

General

Lithology—Wireline, Drillpipe

Density ToolApparent Matrix Volumetric Photoelectric Factor—Open Hole


Lithology—Wireline, LWD



6 5 4 3 2 1 4 6 8 10 12 14

3.0

2.5

2.0

0

10

20

30

40

Photoelectric factor, Pe

Bulk density, ρb

(g/cm3)

Apparent totalporosity, φ ta (%)

Apparent matrix

volumetric photoelectric factor, Umaa

Fresh water (0 ppm), ρf = 1.0 g/cm3, Uf = 0.398Salt water (200,000 ppm), ρf = 1.11 g/cm3, Uf = 1.36

General

General

General


PurposeThis chart is used to identify the rock mineralogy through comparison

ExampleGiven: ρmaa = 2.74 g/cm3 (from Chart Lith-9 or Lith-10) and

Density ToolLithology Identification—Open Hole



of the apparent matrix grain density (ρmaa ) and apparent matrix volu-metric photoelectric factor (Umaa ).

DescriptionThe values of ρmaa and Umaa are entered on the y- and x-axis, respec-

tively. The rock mineralogy is identified by the proximity of the point

of intersection of the two values to the labeled points on the plot.

The effect of gas, salt, etc., is to shift data points in the directions

shown by the arrows.

Umaa = 13 (from Chart Lith-5).Find: Matrix composition of the formation.

Answer: Enter the chart with ρmaa = 2.74 g/cm3 on the y-axis and

Umaa = 13 on the x-axis. The intersection point indicates

a matrix mixture of 20% dolomite and 80% calcite.

General

General


Density ToolLithology Identification—Open Hole




Apparent matrixgrain density,ρmaa (g/cm3)

2.2

2.3

2.4

2.5

2.6

2.7

2.8

Salt

K-feldspar

Quartz

Barite

Calcite

G a s d i r e c t i o n

% c al c i t e

e

% q u a r

2 0

608 0

40

6 0

4 0

8 0

4 0

2 0

PurposeThis chart is used to help identify mineral mixtures from sonic,

The lines on the chart are divided into numbered groups by poros-

ity range as follows:


Environmentally Corrected Neutron CurvesM–N Plot for Mineral Identification—Open Hole



density, and neutron logs.DescriptionBecause M and N slope values are practically independent of porosity

except in gas zones, the porosity values they indicate can be corre-

lated with the mineralogy. (See Appendix E for the formulas to calcu-

late M and N from sonic, density, and neutron logs.)

Enter the chart with M on the y-axis and N on the x-axis. The

intersection point indicates the makeup of the formation. Points for

binary mixtures plot along a line connecting the two mineral points.

Ternary mixtures plot within the triangle defined by the three con-stituent minerals. The effect of gas, shaliness, secondary porosity,

etc., is to shift data points in the directions shown by the arrows.

1. φ = 0 (tight formation)2. φ = 0 to 12 p.u.

3. φ = 12 to 27 p.u.

4. φ = 27 to 40 p.u.

ExampleGiven: M = 0.79 and N = 0.51.

Find: Mineral composition of the formation.

Answer: The intersection of the M and N values indicates dolomite

in group 2, which has a porosity between 0 to 12 p.u.


Environmentally Corrected Neutron CurvesM–N Plot for Mineral Identification—Open Hole

Lith-7(former CP-8)



1.1

1.0

0.9

0.8

0.7 Anhydrite

Dolomite

Gypsum

Calcite (limestone)

vma = 5943 m/s

= 19,500 ft/s

vma = 5486 m/s = 18,000 ft/s

Quartz sandstone

324 1

1 2 34

Secondaryporosity

G a s

o r

s a l t

M

Freshwater mudρf = 1.0 Mg/m3, t f = 620 µs/mρf = 1.0 g/cm3, t f = 189 µs/ft

Saltwater mudρf = 1.1 Mg/m3, t f = 607 µs/mρf = 1.1 g/cm3, t f = 185 µs/ft

General

General

General


PurposeThis chart is used to help identify mineral mixtures from APS

A l P i S d l

The lines on the chart are divided into numbered groups by poros-

ity range as follows:

Environmentally Corrected APS* CurvesM–N Plot for Mineral Identification—Open Hole



Accelerator Porosity Sonde neutron logs.

DescriptionBecause M and N values are practically independent of porosity

except in gas zones, the porosity values they indicate can be corre-

lated with the mineralogy. (See Appendix E for the formulas to cal-

culate M and N from sonic, density, and neutron logs.)

Enter the chart with M on the y-axis and N on the x-axis. The

intersection point indicates the makeup of the formation. Points for

binary mixtures plot along a line connecting the two mineral points.

Ternary mixtures plot within the triangle defined by the three con-stituent minerals. The effect of gas, shaliness, secondary porosity,

etc., is to shift data points in the directions shown by the arrows.

1. φ = 0 (tight formation)2. φ = 0 to 12 p.u.

3. φ = 12 to 27 p.u.

4. φ = 27 to 40 p.u.

Because the dolomite spread is negligible, a single dolomite point

is plotted for each mud.

ExampleGiven: M = 0.80 and N = 0.55.

Find: Mineral composition of the formation.

Answer: Dolomite.

General

General


Environmentally Corrected APS* CurvesM–N Plot for Mineral Identification—Open Hole

Lith-8(former CP-8a)



1.1

1.0

0.9

0.8

0.7 Anhydrite

Dolomite

Gypsum

Calcite (limestone)

vma = 5943 m/s

= 19,500 ft/s

vma = 5486 m/s = 18,000 ft/s

Quartz sandstone

12 3,4

Secondaryporosity

G a s

o r

s a l t

M

Freshwater mud

ρf = 1.0 Mg/m3, t f = 620 µs/m

ρf = 1.0 g/cm3, t f = 189 µs/ft

Saltwater mud

ρf = 1.1 Mg/m3, t f = 607 µs/m

ρf = 1.1 g/cm3, t f = 185 µs/ft

PurposeCharts Lith-9 (customary units) and Lith-10 (metric units) provide

l f th t t i i t l t it ti (t ) d

ExampleGiven: Apparent crossplot porosity from density-neutron = 20%,

ρ 2 4 / 3 t l t it f


Bulk Density or Interval Transit Time and Apparent Total PorosityApparent Matrix Parameters—Open Hole



values of the apparent matrix internal transit time (tmaa ) and appar-

ent matrix grain density (ρmaa ) for the matrix identification (MID)

Charts Lith-11 and Lith-12. With these parameters the identification

of rock mineralogy or lithology through a comparison of neutron,

density, and sonic measurements is possible.

DescriptionDetermining the values of tmaa andρmaa to use in the MID Charts

Lith-11 and Lith-12 requires three steps.

First, apparent crossplot porosity is determined using the appro-

priate neutron-density and neutron-sonic crossplot charts in the“Porosity” section of this book. For data that plot above the sand-

stone curve on the charts, the apparent crossplot porosity is defined

by a vertical projection to the sandstone curve.

Second, enter Chart Lith-9 or Lith-10 with the interval transit

time (t) to intersect the previously determined apparent crossplot

porosity. This point defines tmaa .

Third, enter Chart Lith-9 or Lith-10 with the bulk density (ρb)

to again intersect the apparent crossplot porosity and define ρmaa .

The values determined from Charts Lith-9 and Lith-10 for tmaa andρmaa are cross plotted on the appropriate MID plot (Charts Lith-11

and Lith-12) to identify the rock mineralogy by its proximity to the

labeled points on the plot.

ρb = 2.4 g/cm3, apparent crossplot porosity from

neutron-sonic = 30%, and t = 82 µs/ft.

Find: ρmaa and tmaa .

Answer: ρmaa = 2.75 g/cm3 and tmaa = 46 µs/ft.



Lith-9(customary, former CP-14)

Fluid Density = 1 0 g/cm3



130 120 110 100 90 80 70 60 50 40 303.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

130

120

110

100

90

80

70

60

50

Fluid Density = 1.0 g/cm3

Bulk density,ρb (g/cm3)

Interval transit time,

t (µs/ft)

Apparent matrix transit time, tmaa (µs/ft)

40

30

20

10

10

20

30

Apparentcrossplotporosity

D e n s i t y

- n e u

t r o n

N e u t r o n - s o

n i c

General

General

General

Fluid Density 1 0 g/cm3



Lith-10(metric, former CP-14m)



350 325 300 275 250 225 200 175 150 125 1003.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

350

325

300

275

250

225

200

175

150

Fluid Density = 1.0 g/cm3


Interval

transit time,

t (µs/m)

Apparent matrix transit time, tmaa (µs/m)

40

30

20

10

10

20

30

Apparentcrossplotporosity

D e n s i t y

- n e u

t r o n

N e u

t r o n - s o

n i c

General

PurposeCharts Lith-11 and Lith-12 are used to establish the type of mineral

predominant in the formation

General


Density ToolMatrix Identification (MID)—Open Hole

ρf Multiplier

1.00 1.00



predominant in the formation.

DescriptionEnter the appropriate (customary or metric units) chart with

the values established from Charts Lith-9 or Lith-10 to identify the

predominant mineral in the formation. Salt points are defined for

two tools, the sidewall neutron porosity (SNP) and the CNL*

Compensated Neutron Log. The presence of secondary porosity

in the form of vugs or fractures displaces the data points parallel

to the apparent matrix internal transit time (tmaa ) axis. The presence

of gas displaces points to the right on the chart. Plotting some shalepoints to establish the shale trend lines helps in the identification

of shaliness. For fluid density (ρf ) other than 1.0 g/cm3 use the table

to determine the multiplier to correct the apparent total density

porosity before entering Chart Lith-11 or Lith-12.

ExampleGiven: ρmaa = 2.75 g/cm3, tmaa = 56 µs/ft (from Chart Lith-9),

and ρf = 1.0 g/cm3.

Find: The predominant mineral.

Answer: The formation consists of both dolomite and calcite, which indicates a dolomitized limestone. The formation

used in this example is from northwest Florida in the

Jay field. The vugs (secondary porosity) created by the

dolomitization process displace the data point parallel

to the dolomite and calcite points.

1.00 1.00

1.05 0.98

1.10 0.95

1.15 0.93

General

General

General



Lith-11(customary, former CP-15)



2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

ρmaa

(g/cm3)

Calcite

Dolomite

Quartz

G a s d i r

e c t i o

n

Salt(CNL* log)

Salt(SNP)



Lith-12(metric, former CP-15m)



2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

ρmaa

(g/cm3)

Calcite

Dolomite

Quartz

G a s d i r e

c t i o n

Salt(SNP)

Salt(CNL* log)

General

Porosity—Wireline, LWD

Sonic ToolPorosity Evaluation—Open Hole

PurposeThis chart is used to convert sonic log slowness time (∆t) values

into those for porosity (φ)

Example: Consolidated FormationGiven: ∆t = 76 µs/ft in a consolidated formation with

vma = 18 000 ft/s



into those for porosity (φ).

DescriptionThere are two sets of curves on the chart. The blue set for matrix

velocity (v ma ) employs a weighted-average transform. The red set

is based on the empirical observation of lithology (see Reference

20). For both, the saturating fluid is assumed to be water with

a velocity (v f ) of 5,300 ft/s (1,615 m/s).

Enter the chart with the slowness time from the sonic log on the

x-axis. Move vertically to intersect the appropriate matrix velocity

or lithology curve and read the porosity value on the y-axis. For rockmixtures such as limy sandstones or cherty dolomites, intermediate

matrix lines may be interpolated.

To use the weighted-average transform for an unconsolidated sand,

a lack-of-compaction correction (Bcp) must be made. Enter the chart

with the slowness time and intersect the appropriate compaction

correction line to read the porosity on the y-axis. If the compaction

correction is not known, it can be determined by working backward

from a nearby clean water sand for which the porosity is known.

v ma = 18,000 ft/s.

Find: Porosity and the formation lithology (sandstone,

dolomite, or limestone).

Answer: 15% porosity and consolidated sandstone.

Example: Unconsolidated FormationGiven: Unconsolidated formation with ∆t = 100 µs/ft in

a nearby water sand with a porosity of 28%.

Find: Porosity of the formation for ∆t = 110 µs/ft.

Answer: Enter the chart with 100 µs/ft on the x-axis and move

vertically upward to intersect 28-p.u. porosity. This

intersection point indicates the correction factor curve

of 1.2. Use the 1.2 correction value to find the porosity for

the other slowness time. The porosity of an unconsoli-

dated formation with ∆t = 110 µs/ft is 34 p.u.

Lithology vma (ft/s) ∆ tma (µs/ft) vma (m/s) ∆ tma (µs/m)

Sandstone 18,000–19,500 55.5–51.3 5,486–5,944 182–168

Limestone 21,000–23,000 47.6–43.5 6,400–7,010 156–143

Dolomite 23,000–26,000 43.5–38.5 7,010–7,925 143–126



Por-1(customary, former Por-3)



vf = 5,300 ft/s

50

40

30

20

50

40

30

20

Porosity,φ (p.u.)

Porosity,φ (p.u.)

Time average

Field observation

1.1

1.2

1.3

1.4

1.5

1.6

D o l o m

i t e

2 6 , 0 0 0

00

vma(ft/s)

Bcp

23 , 0 0 0

C a l c

i t e ( l i m

e s t o n e )




Por-2(metric, former Por-3m)



vf = 1,615 m/s

50

40

30

20

50

40

30

20

Porosity,φ (p.u.)

Porosity,φ (p.u.)

1.1

1.2

1.3

1.4

1.5

1.6

D o l o

m i t e

8 , 0 0 0

vma(m/s)

Bcp

Time average

Field observation

00 0

C a l c i t e

Q u a r t z s a n d

s t o n e

D o l o m

i t e

C a l c i t e

tz s a n d s t o

n e

e m e n t

e d q u a r t z

s a n d

s t o n

e

Por-3(former Por-5)

Density ToolPorosity Determination—Open Hole




1.0 0.9 0.8

1.1

1.2

Porosity,φ (p.u.)

ρ m a =

2 . 8 7

( d o l o m

i t e )

ρ m a = 2

. 7 1

( c a l c i t e )

ρ m a =

2 . 6 5

( q u a r t z

s a n d

s t o n

e )

ρ m

a =

2 . 8 3

ρ m a =

2 . 6 8

ρma – ρb

ρma – ρf

φ =

ρf (g/cm3)

40

30

20

10

PurposeThis chart is used for the apparent limestone porosity recorded by the

APS Accelerator Porosity Sonde or sidewall neutron porosity (SNP)

The HPLC curve is the high-resolution version of the APLC curve.

The same corrections apply.

APS* Near-to-Array (APLC) and Near-to-Far (FPLC) LogsEpithermal Neutron Porosity Equivalence—Open Hole

Porosity—Wireline



y p y ( )

tool to provide the equivalent porosity in sandstone or dolomite for-

mations. It can also be used to obtain the apparent limestone poros-

ity (used for the various crossplot porosity charts) for a log recorded

in sandstone or dolomite porosity units.

DescriptionEnter the x-axis with the corrected near-to-array apparent limestone

porosity (APLC) or near-to-far apparent limestone porosity (FPLC)

and move vertically to the appropriate lithology curve. Then read the

equivalent porosity on the y-axis. For APS porosity recorded in sand-stone or dolomite porosity units enter that value on the y-axis and

move horizontally to the recorded lithology curve. Then read the

apparent limestone neutron porosity for that point on the x-axis.

The APLC is the epithermal short-spacing apparent limestone

neutron porosity from the near-to-array detectors. The log is auto-

matically corrected for standoff during acquisition. Because it is

epithermal this measurement does not need environmental correc-

tions for temperature or chlorine effect. However, corrections for

mud weight and actual borehole size should be applied (see ChartNeu-10). The short spacing means that the effect of density and

therefore the lithology on this curve is minimal.

The FPLC is the epithermal long-spacing apparent limestone neu-

tron porosity acquired from the near-to-far detectors. Because it is

epithermal this measurement does not need environmental correc-

tions for temperature or chlorine effect. However, corrections for

mud weight and actual borehole size should be applied (see Chart

Neu-10). The long spacing means that the density and therefore

lithology effect on this curve is pronounced, as seen on Charts Por-13and Por 14

Example: Equivalent Porosity

Given: APLC = 25 p.u. and FPLC = 25 p.u.

Find: Porosity for sandstone and for dolomite.

Answer: Sandstone porosity from APLC = 28.5 p.u. and sandstone

porosity from FPLC = 30 p.u.

Dolomite porosity = 24 and 20 p.u., respectively.

Example: Apparent PorosityGiven: Clean sandstone porosity = 20 p.u.

Find: Apparent limestone neutron porosity. Answer: Enter the y-axis at 20 p.u. and move horizontally to

the quartz sandstone matrix curves. Move vertically

from the points of intersection to the x-axis and read

the apparent limestone neutron porosity values.

APLC = 16.8 p.u. and FPLC = 14.5 p.u.

Resolution Short Spacing Long Spacing

Normal APLCFPLCEpithermal neutron porosity (ENPI)†

Enhanced HPLCHFLCHNPI†

† Not formation-salinity corrected.

Porosity—Wireline

APS* Near-to-Array (APLC) and Near-to-Far (FPLC) LogsEpithermal Neutron Porosity Equivalence—Open Hole Por-4

(former Por-13a)



40

30

20

10

0

True porosityfor indicated

matrix material,φ (p.u.)

C a l c i t e

( l i m e s t o

n e )

D o l o m

i t e

APLC

FPLC

SNP

Q u a r t z

s a n d

s t o n

e

Thermal Neutron ToolPorosity Equivalence—Open Hole

General

Porosity—Wireline

Por-5(former Por-13b)



40

30

20

10

00 10 20 30 40



Q u a

r t z

s a n d

s t o n e

C a

l c i t e

( l i m e s t o

n e )

D o l o m

i t e

Formation salinity

TNPH

NPHI

0 ppm

250,000 ppm

Porosity—Wireline

Thermal Neutron Tool—CNT-D and CNT-S 21 ⁄ 2-in. ToolsPorosity Equivalence—Open Hole

Por-6



40

30

20

10

S a n d

s t o n

e

D o l o

m i t e

L i m

e s t o

n e



General

Porosity—LWD

adnVISION475* 4.75-in. Azimuthal Density Neutron ToolPorosity Equivalence—Open Hole

Por-7



–5 0 5 10 15 20 25 30 35 40

40

35

30

25

20

15

10

5

0

Corrected apparent limestone neutron porosity, φADNcor (p.u.)



Q u a r t z

s a n d

s t o n e

C a l c i

t e ( l i m

e s t o n e )

D o l o m

i t e

Porosity—LWD


Por-8



–5 0 5 10 15 20 25 30 35 40

40

35

30

25

20

15

10

5

0

Corrected apparent limestone neutron porosity, φADNcor (p.u.)





D o l o m

i t e

Porosity—LWD


Por-9



–5 0 5 10 15 20 25 30 35 40

40

35

30

25

20

15

10

5

0

Corrected apparent limestone neutron porosity,φADNcor (p.u.)

True porosity(p.u.)

S a n d s t o n e

L i m e s t o n e

D o l o m i t e

Porosity—LWD

EcoScope* 6.75-in. Integrated LWD Tool, BPHI PorosityPorosity Equivalence—Open Hole

Por-10



–5 0 5 10 15 20 25 30 35 40

40

35

30

25

20

15

10

5

0

C t d t li t BPHI it ( )



S a n d s t o n e

L i m e s t o n e

D o l o m

i t e

Porosity—LWD

EcoScope* 6.75-in. Integrated LWD Tool, TNPH PorosityPorosity Equivalence—Open Hole

Por-10a



–5 0 5 10 15 20 25 30 35 40

40

35

30

25

20

15

10

5

0

C d li TNPH i ( )



S a n d

s t o n

e

L i m e s t o n e

D o l o m

i t e

Porosity—Wireline

CNL* Compensated Neutron Log and Litho-Density* Tool(fresh water in invaded zone)Porosity and Lithology—Open Hole

PurposeThis chart is used with the bulk density and apparent limestone

porosity from the CNL Compensated Neutron Log and Litho-Density

t l ti l t i t th lith l d d t i th

ExampleGiven: Corrected apparent neutron limestone porosity =

16.5 p.u. and bulk density = 2.38 g/cm3.



tools, respectively, to approximate the lithology and determine thecrossplot porosity.

DescriptionEnter the chart with the environmentally corrected apparent neu-

tron limestone porosity on the x-axis and bulk density on the y-axis.

The intersection of the two values describes the crossplot porosity

and lithology.

If the point is on a lithology curve, that indicates that the forma-

tion is primarily that lithology. If the point is between the lithology curves, then the formation is a mixture of those lithologies. The posi-

tion of the point in relation to the two lithology curves as composi-

tion endpoints indicates the mineral percentages of the formation.

The porosity for a point between lithology curves is determined

by scaling the crossplot porosity by connecting similar numbers on

the two lithology curves (e.g., 20 on the quartz sandstone curve to

20 on the limestone curve). The scale line closest to the point repre-

sents the crossplot porosity.

Chart Por-12 is used for the same purpose as this chart for saltwater-invaded zones.

Find: Crossplot porosity and lithology.

Answer: Crossplot porosity = 18 p.u. The lithology is approxi-

mately 40% quartz and 60% limestone.

General

Porosity—Wireline

CNL* Compensated Neutron Log and Litho-Density* Tool(fresh water in invaded zone)Porosity and Lithology—Open Hole

Por-11(former CP-1e)



1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

Bulkdensity,ρb (g/cm3)

Densityporosity,φD (p.u.)

(ρma = 2.71 g/cm3,ρf = 1.0 g/cm3)

45

40

35

30

25

20

15

10

5

0

SulfurSalt

A p p r o x i m a t e g a s c o r r e c t i o n P o r o s i t y


0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

4 5


0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

D o l o m i t e

1 0

1 5

2 0

2 5

3 0

3 5

Liquid-Filled Borehole (ρf = 1.000 g/cm3 and Cf = 0 ppm)

General

Porosity—Wireline

CNL* Compensated Neutron Log and Litho-Density* Tool(salt water in invaded zone)Porosity and Lithology—Open Hole

Por-12(former CP-11)

1 9

Liquid-filled borehole (ρf = 1.190 g/cm3 and Cf = 250,000 ppm)



1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

Bulkdensity,ρb (g/cm3)

Densityporosity,φD (p.u.)

(ρma = 2.71 g/cm3,

ρf = 1.19 g/cm3

)

45

40

35

30

25

20

15

10

5

0

–5

–10

0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

4 5

0

5

1 0

1 5

2 0

2 5

3 0

3 5

0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

4 5

A p p r o x i m a t e g a s c o r r e c t i o n

P o r o s i t y


C a l c i

t e ( l i m

e s t o n

e )

SulfurSalt

D o l o m

i t e

General

Porosity—Wireline

APS* and Litho-Density* ToolsPorosity and Lithology—Open Hole

Por-13(former CP-1g)

Liquid Filled Borehole (ρ 1 000 g/cm3 and C 0 ppm)



Liquid-Filled Borehole (ρf = 1.000 g/cm3 and Cf = 0 ppm)


1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

APLC

FPLC

e

D o l o

m i t e

C a l c i

t e ( l i m

e s t o n

e )

Q u a r t z s a

n d s t o

n e

P o r o s i t y


0

5

5

1 0

1 0

1 5

1 5

2 0

2 0

2 5

2 5

3 5

3 5 3 0

3 0

4 0

4 0

4 5

0

5

4 0

3 5

3 0

2 5

2 0

1 5

1 0

0

3 5

3 0

2 5

2 0

1 5 1 5

1 0

5

0

0

1 0

2 0

3 0

3 5

4 0

5

2 5

General

Porosity—Wireline

APS* and Litho-Density* Tools (saltwater formation)Porosity and Lithology—Open Hole

Por-14(former CP-1h)

Liquid Filled Borehole (ρf 1 190 g/cm3 and Cf 250 000 ppm)



Liquid-Filled Borehole (ρf = 1.190 g/cm3 and Cf = 250,000 ppm)


1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9ite

P o r o s

i t y


0

0

5

5

1 0

1 0

1 5

1 5

2 0

2 0

2 5

2 5

3 5

3 5 3 0

3 0

4 0

4 0

4 5

0

5

4 0

3 5

3 0

2 5

2 0

1 5

1 0

0

4 0

3 5

3 0

2 5

2 0

1 5

1 0

5

0

4 5 4 5

APLC

FPLC

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

Q u a r t z

s a n d

s t o n e

D o l o m

i t e C a l c i

t e ( l i m

e s t o n

e )

General

Porosity—LWD

adnVISION475* 4.75-in. Azimuthal Density Neutron ToolPorosity and Lithology—Open Hole

Por-15

Fresh Water Liquid Filled Borehole (ρf 1 0 g/cm3)




1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

Salt

Fresh Water, Liquid-Filled Borehole (ρf = 1.0 g/cm3)

D o l o m i t e

C a l c i

t e ( l i m

e s t o n e )


P o r o s i t y

0

0

5

1 0

1 0

1 5

1 5

2 0

2 0

2 5

2 5

3 5

3 5 3 0

3 0

4 0

4 0

4 0

3 5

3 0

2 5

2 0

1 5

1 0

5

0 5

General

Porosity—LWD


Por-16



Bulk density,

ρb (g/cm3)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8


D o l o

m i t e



0

0

1 0

1 0

1 5

2 0

2 5

5

5

5

1 0

1 5

2 0

0

2 5

3 5

3 0

1 5

2 0

2 5

3 5

3 0

3 0

3 5

4 0

4 0

P o r o s i t y

General

Porosity—LWD


Por-17



Bulk density,

ρb (g/cm3)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8




0

1 0

5

D o l o m i t e

5

1 0

1 5

2 0

0

2 5

3 5

3 0

1 5

2 0

2 5

3 5

3 0

4 0

0

1 0

1 5

2 0

5

3 0

3 5

4 0

2 5

P o r o

s i t y 4 0

Porosity—LWD

EcoScope* 6.75-in. Integrated LWD ToolPorosity and Lithology—Open Hole

Por-18

1 9


5




1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

Salt

0

1 0

1 5

2 0

2 5

3 5

3 0

4 0

5

0

1 0

1 5

2 0

2 5

3 5

3 0

4 0

4 5

5

D o l o m i t e

L i m e s

t o n e

S a n d s t o n e

0

1 0

1 5

2 0

2 5

3 5

3 0

4 0

5

Porosity—LWD

EcoScope* 6.75-in. Integrated LWD ToolPorosity and Lithology—Open Hole

Por-19

1 9


45




1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

0

0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

4 5

Salt

D o l o m i t e

L i m e s

t o n e

S a n d s t o n e

0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

General

Porosity—Wireline

Sonic and Thermal Neutron CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded

PurposeThis chart is used to determine crossplot porosity and an approxi-

mation of lithology for sonic and thermal neutron logs in freshwater

drilling fluid

ExampleGiven: Thermal neutron apparent limestone porosity = 20 p.u.

and sonic slowness time = 89 µs/ft in freshwater

drilling fluid



drilling fluid.

DescriptionEnter the corrected neutron porosity (apparent limestone porosity)

on the x-axis and the sonic slowness time (∆t) on the y-axis to find

their intersection point, which describes the crossplot porosity and

lithology composition of the formation. Two sets of curves are drawn

on the chart. The blue set of curves represents the crossplot porosity

values using the sonic time-average algorithm. The red set of curves

represents the field observation algorithm.

drilling fluid.


Answer: Enter the neutron porosity on the x-axis and the sonic

slowness time on the y-axis. The intersection point is at

about 25 p.u. on the field observation line and 24.5 p.u.

on the time-average line. The matrix is quartz sandstone.



General

General


Density and Sonic CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded

PurposeThis chart is used to determine porosity and lithology for sonic and

density logs in freshwater-invaded zones.

D i ti

ExampleGiven: Bulk density = 2.3 g/cm3 and sonic slowness

time = 82 µs/ft.

Find: Crossplot porosity and lithology



DescriptionEnter the chart with the bulk density on the y-axis and sonic slow-

ness time on the x-axis. The point of intersection indicates the type

of formation and its porosity.


Answer: Limestone with a crossplot porosity = 24 p.u.

General



Por-22(customary, former CP-7)

1.8

tf = 189 µs/ft and ρf = 1.0 g/cm3



1.9

2.0

2.1

2.2

2.3

2.4

2.5


Gypsum

Trona

Salt

Sylvite

Sulfur

1 010

2 0

3 0

4 0

4 0 4 0 4 0

4 0

3 0 3 0

2 0

P

o r o s i t y

Time average

Field observation

3 0

3 0 3 0

2 0 2 0

2 0

1 0

2 00

General

General



Por-23(metric, former CP-7m)

1.8

tf = 620 µs/m and ρf = 1.0 g/cm3

Time average



1.9

2.0

2.1

2.2

2.3

2.4

2.5


Gypsum

Trona

Salt

Sylvite

Sulfur

1 0

1 0 2 0

2 0

2 0 3 0

4 0

3 0

4 0 4 0

4 0

3 0 3 0

2 0

P o r o s i t

y

3 0

1 0

g

Field observation

3 0

1 0

2 0

2 0

4 0

General


Density and Neutron ToolPorosity Identification—Gas-Bearing Formation

PurposeThis chart is used to determine the porosity and average water satu-

ration in the flushed zone (S xo) for freshwater invasion and gas com-

position of C1.1H4.2 (natural gas).

ExampleGiven: φD = 25 p.u. and φN = 10 p.u. in a low-pressure, shallow

(4,000-ft) reservoir.

Find: Porosity and Sxo.



p ( g )

DescriptionEnter the chart with the neutron- and density-derived porosity values

(φN and φD, respectively). On the basis of the table, use the blue curves

for shallow reservoirs and the red curves for deep reservoirs.

y xo

Answer: Enter the chart at 25 p.u. on the y-axis and 10 p.u. on the

x-axis. The point of intersection identifies (on the blue

curves for a shallow reservoir) φ = 20 p.u. and S xo = 62%.

Depth Pressure Temperature ρw (g/cm3) IHw ρg (g/cm3) IHg

Shallow reservoir ~2,000 psi [~14,000 kPa] ~120°F [~50°C] 1.00 1.00 0 0Deep reservoir ~7,000 psi [~48,000 kPa] ~240°F [~120°C] 1.00 1.00 0.25 0.54

ρw = density of water, ρg = density of gas, IHw = hydrogen index of water, and IHg = hydrogen index of gas

General

General

General


Density and Neutron ToolPorosity Identification—Gas-Bearing Formation

Por-24(former CP-5)

50



Density-derived porosity,φD (p.u.)

50

40

30

20

Sxo

Sxo

15

20

Porosity

30

80

35

025

40

15

10

20

100

30

25

60

40

60

20

100

80

35

40

20

0

10

General

PurposeThis chart is used to determine the porosity and average water satu-

ration in the flushed zone (S xo) for freshwater invasion and gas com-

position of CH4 (methane).

ExampleGiven: φD = 15 p.u. and APS φN = 8 p.u. in a normally pressured

deep (14,000-ft) reservoir.

Find: Porosity and S xo.

Porosity—Wireline

Density and APS* Epithermal Neutron ToolPorosity Identification—Gas-Bearing Formation



( )

DescriptionEnter the chart with the APS Accelerator Porosity Sonde neutron- and

density-derived porosity values (φN and φD, respectively). On the basis

of the table, use the blue curves for shallow reservoirs and the red

curves for deep reservoirs.

y

Answer: φ= 11 p.u. and S xo = 39%.

Depth Pressure Temperature ρw IHw ρg IHg

Shallow reservoir ~2,000 psi [~14,000 kPa] ~120°F [~50°C] 1.00 1.00 0.10 0.23

Deep reservoir ~7,000 psi [~48,000 kPa] ~240°F [~120°C] 1.00 1.00 0.25 0.54

ρw = density of water, ρg = density of gas, IHw = hydrogen index of water, and IHg = hydrogen index of gas

General

General

General

Porosity—Wireline

Density and APS* Epithermal Neutron ToolPorosity Identification—Gas-Bearing Formation

Por-25(former CP-5a)

50



Density-derived porosity,φD (p.u.)

50

40

30

20

1515

2020

40

3030

40

80

35

35

25

25

40

20

0

100Sxo

Sxo

80

100

20

0

60

40

60

Porosity

1010

General

PurposeThis nomograph is used to estimate porosity in hydrocarbon-bearing

formations by using density, neutron, and resistivity in the flushed

zone (R xo) logs. The density and neutron logs must be corrected fori t l ff t d lith l b f t t th h

ExampleGiven: Corrected CNL apparent neutron porosity = 12 p.u.,

corrected apparent density porosity = 38 p.u., and

Shr = 50%.

General

General

Porosity—Wireline

Density, Neutron, and Rxo LogsPorosity Identification in Hydrocarbon-Bearing Formation—Open Hole



environmental effects and lithology before entry to the nomograph.

The chart includes an approximate correction for excavation effect,

but if hydrocarbon density (ρh) is <0.25 g/cm3 (gas), the chart may

not be accurate in some extreme cases:

very high values of porosity (>35 p.u.) coupled with medium

to high values of hydrocarbon saturation (Shr) Shr = 100% for medium to high values of porosity.

DescriptionConnect the apparent neutron porosity value on the appropriate

neutron porosity scale (CNL* Compensated Neutron Log or sidewall

neutron porosity [SNP] log) with the corrected apparent density

porosity on the density scale with a straight line. The intersection

point on the φ1 scale indicates the value of φ1.

Draw a line from the φ1 value to the origin (lower right corner)

of the chart for ∆φ versus Shr.

Enter the chart with Shr from (Shr = 1 – S xo) and move vertically

upward to determine the porosity correction factor (∆φ) at the inter-

section with the line from the φ1 scale.

This correction factor algebraically added to the porosity φ1 gives

the corrected porosity.

Find: Hydrocarbon-corrected porosity.

Answer: Enter the 12-p.u. φcor value on the CNL scale. A line from

this value to 38 p.u. on the φDcor scale intersects the φ1

scale at 32.2 p.u. The intersection of a line from this

value to the graph origin and Shr = 50% is ∆φ = –1.6 p.u.

Hydrocarbon-corrected porosity: 32.2 – 1.6 = 30.6 p.u.

General

General

General

Porosity—Wireline

Density, Neutron, and Rxo LogsPorosity Identification in Hydrocarbon-Bearing Formation—Open Hole

Por-26(former CP-9)

φDcorφ1φcor

(SNP)

φcor

(CNL*)



–5

–4

50

40

30

20

50

40

30

20

50

40

30

20

50

40

30

20

(p.u.)

General

Porosity—Wireline

Hydrocarbon Density EstimationPor-27

(former CP-10)

1.0

0.8

ρh



1.0

0.8

0.6

φCNLcor

φ

0.8

ρh

0.7

0.6

0.8

0.6

0.4

0.2

0 0 20 40 60 80 100

0.7

0.6

0.5

0.4

0.3

0.20.1

0

Shr (%)

φSNPcor

φDcor

General

Saturation—Wireline, LWD

Porosity Versus Formation Resistivity FactorOpen Hole

SatOH-1(former Por-1)

2.5 5 10 20 50 100 200 500 1,000 2,000 5,000 10,00050



40

30

25

20

15

10987

6

5

4

3

2

1

Porosity,φ (p.u.)

1.4

1.6

1.82.0

2.2

2.5

2.8

FR =0.81

φ2

FR =1φ2

FR =0.62φ2.15

FR =1

φmm

Fractures

Vugs orspherical pores


Spherical and Fracture PorosityOpen Hole

SatOH-2(former Por-1a)



0.5 0.8 1 2 4 6 8 10 20 30 40 50

Porosity, φ (p.u.)

3.0

2.5

2.0

1.5

1.0

Cementationexponent, m

Fractures

φ f r = 0

. 1

0. 2

2. 5

1 0 . 0

0. 5

1. 0

1. 5 2. 0

5. 0

φiso = 0.5

1.0

1.5

2.55.0

7.510.0

12.5

2.0 Isolatedpores


Saturation DeterminationOpen Hole

Purpose

This nomograph is used to solve the Archie water saturation

equation:

Description

If Ro is known, a straight line from the known Ro value through the

measured Rt value indicates the value of S w . If Ro is unknown, it may

be determined by connecting R w with FR or porosity (φ).R F R



where

S w = water saturation

Ro = resistivity of clean-water formation

Rt = true resistivity of the formation

FR = formation resistivity factorR w = formation water resistivity.

It should be used in clean (nonshaly) formations only.

ExampleGiven: R w = 0.05 ohm-m at formation temperature, φ = 20 p.u.

(FR = 25), and Rt = 10 ohm-m.

Find: Water saturation.

Answer: Enter the nomograph on the R w scale at R w = 0.05 ohm-m.

Draw a straight line from 0.05 through the porosity scale

at 20 p.u. to intersect the Ro scale.

From the intersection point of Ro = 1, draw a straight line

through Rt = 10 ohm-m to intersect the S w scale.

S w = 31.5%.

SR

R

F R

R w o

t

R w

t

= = ,



SatOH-3(former Sw-1)

Ro

(ohm-m)R t

(ohm-m)

Sw

(%)

5

Clean Formations, m = 2



Rw

(ohm-m)

( ) ( )

φ(%)

FR

2,000

1,000800600

400300200

1008060504030

20

108654

2.5

3

4

567

89

10

15

20

25

3035404550

FR =1

φ2.0

m = 2.0

0.01

0.02

0.03

0.04

0.05

0.060.070.080.090.1

0.2

0.3

0.4

0.5

0.60.7

6

7

8

9

10

111213141516

18

20

25

30

40

50

60

10,0008,0006,0005,0004,0003,000

2,000

1,000

800600500400300

200

1008060504030

20

1086543

2

1.00.8

30

20181614

1210

987

6

5

4

3

21.8

1.61.41.2

1.00.90.80.70.6

0.5

0.4

0.3



Purpose

This chart is used to determine water saturation (S w ) in shaly or

clean formations when knowledge of the porosity is unavailable. It

may also be used to verify the water saturation determination fromanother interpretation method The large chart assumes that the

Example

Given: R xo = 12 ohm-m, Rt = 2 ohm-m, Rmf /R w = 20, and

Sor = 20%.

Find: S w (after correction for ROS).



another interpretation method. The large chart assumes that the

mud filtrate saturation is

The small chart provides an S xo correction when S xo is known.

However, water activity correction is not provided for the SP portion

of the chart (see Chart SP-2).

Description

Clean Sands Enter the large chart with the ratio of the resistivity of the flushed

zone to the true formation resistivity (R xo /Rt) on the y-axis and the

ratio of the resistivity of the mud filtrate to the resistivity of the for-

mation water (Rmf /R w ) on the x-axis to find the water saturation at

average residual oil saturation (S wa ). If Rmf /R w is unknown, the chart

may be entered with the spontaneous potential (SP) value and the

formation temperature. If S xo is known, move diagonally upward,parallel to the constant-S wa curves, to the right edge of the chart.

Then, move horizontally to the known S xo (or residual oil saturation

[ROS], Sor) value to obtain the corrected value of S w .

Answer: Enter the large chart at R xo /Rt = 12/2 = 6 on the

y-axis and Rmf /R w = 20 on the x-axis. From the point of

intersection (labeled A), move diagonally to the right to

intersect the chart edge and directly across to enter the

small chart and intersect Sor = 20%.

S w = 43%.

DescriptionShaly Sands

Enter the chart with R xo /Rt and the SP in the shaly sand (EPSP). The

point of intersection gives the S wa value. Draw a line from the chart’s

origin (the small circle located at R xo /Rt = Rmf /Rm = 1) through this

point to intersect with the value of static spontaneous potential (ESSP)

to obtain a value of R xo /Rt corrected for shaliness. This value of R xo /Rt

versus Rmf /R w is plotted to find S w if Rmf /R w is unknown because the

point defined by R xo /Rt and ESSP is a reasonable approximation of S w .

The small chart to the right can be used to further refine S w if Sor isknown.

ExampleGiven: R xo /Rt = 2.8, Rmf /R w = 25, EPSP = –75 mV, ESSP = –120 mV,

and electrochemical SP coefficient (K c) = 80 (formation

temperature = 150ºF).

Find: S w and corrected value for Sor = 10%.

Answer: Enter the large chart at R xo /Rt = 2.8 and the intersection

of EPSP = –75 mV at K c = 80 from the chart below. A linef h i i h h h i i i (l b l d B)

S S XO W = 5 .




0 10 20 30 40Rmf /Rw

Sor (%)



50

40

30

20

10

8

6

5

4

3

2

1

0.8

0.6

0.80.6 1.0 1.5 2.52 3 4 5 6 8 10 15 20 25 30 40 50 60

1.0 0.9 0.8 0.7 0.6

80

70

60

50

40

30

25

20

15

10

6 0

5 0

4 0

2 5

3 0

2 0

1 5

Rxo

R t

S w ( % )

A

B

C

D

%

2 5 %

3 0 %

4 0 %

5 0 %

6 0 %

7 0 %

S w a = 1 0 0 %

EPSP = –Kc log – 2Kc logRxo

R t

Sxo

Sw

Sxo = S w

5

Sxo = Sw

5


Graphical Determination of Sw from Swt and Swb

Open Hole SatOH-5

(former Sw-14)

100



90

80

70

60

50

40

30

20

10

Swt (%)

Swb

70%

60%

50%

40%

30%

20%

10%

0


Porosity and Gas Saturation in Empty HoleOpen Hole


0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

Porosity, φ (p.u.)

Density and Hydrogen Index of Gas Assumed ZeroUse if noshale present

Use if nooil present

100 10 000



2.65

2.70

2.75

2 80

2

4

6

8

10

1214

16

18

20

22

24

26

28

30

Neutronporosity

index(corrected

for lithology)

Matrix density,ρma (g/cm3)

2.6 2.5 2.4 2.3 2.2 2.1 2.0 1.9 1.8SandstoneLimy sandstoneLimestone

100

90

80

70

60

50

40

30

20

10

0

G a s s a t u

r a t i o

n , S g ( %

)

10,0004,0002,0001,000

400300

200150

100

70

6050

40

30

20

151413

1211

R t

Rw

Saturation—Wireline

EPT* Propagation TimeOpen Hole

SatOH-7(former Sxo-1)

7 8 9 10

tpma (ns/m)

21

7 8 9 10

tpma (ns/m)

Sxo



21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

Sxo

(%)

5 0 4 5

4 0 3 5

3 0 2 5

2 0

1 5

1 0

5

tpl (ns/m)

10.9

100

90

80

70

60

50

40

30

20

10

0

53%

t p w ( n s /

m )

2 1

2 5

3 0

3 5

4 0

5 0 6 0

7 0 8 0 9 0

G a s O

i l

F o r m

a t i o

n p o

r o s i t y

( % )


EPT* AttenuationOpen Hole

SatOH-8(former Sxo-2)

Sxo

(%)

5



Aw

(dB/m)

AEPTcor

(dB/m)

φ(p.u.)

6,000

5,000

4,000

3,000

2,000

1,000900800

700600

500

400

300

200

2

3

4

6

8

1

10

20

30

40

60

80100

200

300

6

7

8

910

20

30

40

50

60

70

80

90

100

1

2

3

45

10

15

20

30

40

Purpose

This chart is used to determine water saturation (S w ) from capture

cross section, or sigma (Σ), measurements from the TDT* Thermal

Decay Time pulsed neutron log.

D i ti

Procedure

Shaly Formation

The S w determination in a shaly formation requires additional infor-

mation: sigma shale (Σsh) read from the TDT log in adjacent shale,Vsh from porosity-log crossplot or gamma ray shale porosity (φsh) read


Capture Cross Section ToolCased Hole



DescriptionThis chart uses sigma water (Σ w ), matrix capture cross section (Σma ),

and porosity (φ) to determine water saturation in clean formations.

The chart may be used in shaly formations if sigma shale (Σsh), the

volume fraction of shale in the formation (V sh), and the porosity cor-

rected for shale are known.

Thermal decay time (t and tsh in shale) is also shown on some

of the chart scales because it is related to Σ.Procedure

Clean Formation

The S w determination for a clean formation requires values known

for Σma (based on lithology), φ, Σ w from the NaCl salinity (see Chart

Gen-12 or Gen-13), and sigma hydrocarbon (Σh) (see Chart Gen-14).

Enter the value of Σma on Scale B and draw a line to Pivot Point B.

Enter Σlog on Scale B and draw Line b through the intersection of

Line a and the value of φ to intersect the sigma of the formationfluid (Σf ) on Scale C. Draw Line 5 from Σf through the intersection

of Σh and Σ w to determine the value of S w on Scale D.

Example: Clean FormationGiven: Σlog = 20 c.u., Σma = 8 c.u. (sandstone) from TDT tool,

Σh = 18 c.u., Σ w = 80 c.u. (150,000 ppm or mg/kg), andφ = 30 p.u.

Find: S w .

Answer: Following the procedure for a clean formation, S w = 43%.

V sh from porosity log crossplot or gamma ray, shale porosity (φsh) read

from a porosity log in adjacent shale, and the porosity corrected for

shaliness (φshcor) with the relation for neutron and density logs

in liquid-filled formations of φshcor = φlog – V shφsh.

Enter the value of Σma on Scale B and draw Line 1 to intersect

with Pivot Point A. From the value of Σsh on Scale A, draw Line 2

through the intersection of Line 1 and V sh to determine the shale-

corrected Σcor on Scale B. Draw Line 3 from Σcor to the value of Σma

on the scale to the left of Scale C. Enter Σlog on Scale B and draw Line 4 through the intersection of Line 3 and the value of φ to deter-

mine Σf on Scale C. From Σf on Scale C, draw Line 5 through the

intersection of Σh and Σ w to determine S w on Scale D.

Example

Given: Σlog = 25 c.u.

Σma = 8 c.u.

Σh = 18 c.u.

Σ w = 80 c.u.

Σsh = 45 c.u.

φlog = 33 p.u.

φsh = 45 p.u.

V sh = 0.2.

Find: φshcor and S w .

Answer: First find the porosity corrected for shaliness,

φshcor = 33 p.u. – (0.2 × 45 p.u.) = 24 p.u. This value



SatCH-1(former Sw-12)

20 30 40 50 60sh

sh (c.u.)

A



2

4

50 40 30 20 10 0

100 120 140 160 200 300 400

200 150 120 100 90 80

510

15

2025

3035

4045

0.1

0.5

Pivot point A

0.40.3

0.2

tsh ( s)

macor(c.u.)

t ( s)

p.u.

ab

A

B

Pivot point B

1

3

Purpose

This chart is used to graphically interpret the TDT* Thermal Decay

Time log. In one technique, applicable in shaly as well as clean

sands, the apparent water capture cross section (Σ wa ) is plotted versus bound-water saturation (S wb) on a specially constructed grid to



90

85

80Bound-water

point

wb = 76



determine the total water saturation (S wt).

DescriptionTo construct the grid, refer to the example chart on this page. Three

fluid points must be located: free-water point (Σ wf ), hydrocarbon

point (Σh), and a bound-water point (Σ wb). The free- (or connate for-

mation) water point is located on the left y-axis and can be obtained

from measurement of a formation water sample, from Charts Gen-12and Gen-13 if the water salinity is known, or from the TDT log in

a clean water-bearing sand by using the following equation:

The hydrocarbon point is also located on the left y-axis of the grid.

It can be determined from Chart Gen-14 based on the known or

expected hydrocarbon type.The bound-water point (S wb) can be obtained from the TDT log

in shale intervals also by using the Σ wa equation. It is located on the

right y-axis of the grid.

The distance between the free-water and hydrocarbon points is

linearly divided into lines of constant water saturation drawn parallel

to a straight line connecting the free-water and bound-water points.

The S wt = 0% line originates from the hydrocarbon point, and the

S wt = 100% line originates from the free-water point.

The value of Σwa from the equation is plotted versus Swb to give

0 20 40 60 80 100

Swb (%)

40 44 48 52 56 60 64 68 72 76 80

Gamma Ray(gAPI)

wa

(c.u.)

75

70

65

60

55

50

45

40

35

30

25

20

15

10

5

Free-waterpoint

wf = 61

wb

100% water line

Hydrocarbonpoint

h = 21

86 5

4

3

2

1

7

S w t = S w b

8 0

7 0

6 0

5 0

4 0

3 0

2 0

0

1 0

9 0 %

∑ =∑ − ∑

+ ∑ wa ma

ma log

.φ

(1)




SatCH-2(former Sw-17)



log

or

wa


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.Carbon/Oxygen Ratio—Open Hole

Purpose

Charts SatCH-3 through SatCH-8 are presented for illustrative

purposes only. They are used to ensure that the measured near- and

far-detector carbon/oxygen (C/O) ratio data are consistent with theinterpretation model. These example charts are drawn for specific

consistently outside the trapezoid, the interpretation model may

require revision.

The rectangle within each chart is constructed from four distinct

points determined by the intersection of the near- and far-detectorC/O ratios:



cased and open holes and tool sizes to provide trapezoids for the

to determination of oil saturation (So) and oil holdup (y o).

Description

Known formation and borehole data define the expected C/O ratio

values, which are determined in water saturation and borehole

holdup values ranging from 0 to 1. All log data for formations with

porosity (φ) greater than 10 p.u. should be within the trapezoidalarea bounded by the limits of the So and y o values. If data plot

WW = water/water point

WO = water/oil point

OW = oil/water point

OO = oil/oil point.

RST Reservoir Saturation Tool processing then determines the water

saturation (S w ) of the formation.


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.in 6.125-in. BoreholeCarbon/Oxygen Ratio—Open Hole

φ = 30%, 6.125-in. Open Hole

SatCH-3(former RST-3)



Near-detector carbon/oxygen ratio

Far-detectorcarbon/oxygen

ratio

φ = 20%, 6.125-in. Open Hole

RST-A and RST-C, limestoneRST A q art sandstone

0.8

0.6

0.4

0.2

0

0 0.5 1.0

RST-A and RST-C, limestoneRST-A, quartz sandstoneRST-B and RST-D, limestoneRST-B, quartz sandstone

OO

OW

WO

WW

OO

OW

WO

OO

OW

WO

WO

OW

OO

WW

WWWW


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.in 9.875-in. BoreholeCarbon/Oxygen Ratio—Open Hole

SatCH-4

φ = 30%, 9.875-in. Open Hole

1.5



φ = 20%, 9.875-in. Open Hole

1.5

RST-A and RST-C, limestone

1.5

1.0

0.5

0

0 1.5




ratio

0.5 1.0

OW

WO

WW

WO

WW

OWWO

WW

OW

OO

OO

OW

WW


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.in 8.125-in. Borehole with 4.5-in. Casing at 11.6 lbm/ftCarbon/Oxygen Ratio—Cased Hole


φ = 30%, 6.125-in. Borehole, 4.5-in. Casing at 11.6 lbm/ft





ratio

φ = 20%, 6.125-in. Borehole, 4.5-in. Casing at 11.6 lbm/ft


0.8

0.6

0.4

0.2

0

0 0.5 1.0


OO

O W

WO

W W

O W

O W

O W

WO

WO

WO W W

W W

OO

OO

OO


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.in 7.875-in. Borehole with 5.5-in. Casing at 17 lbm/ftCarbon/Oxygen Ratio—Cased Hole

SatCH-6

φ = 30%, 7.875-in. Borehole, 5.5-in. Casing at 17 lbm/ft





ratio

φ = 20%, 7.875-in. Borehole, 5.5-in. Casing at 17 lbm/ft


0.8

0.6

0.4

0.2

0

0 0.5 1.0


WO

OO

O W

OO

O W

WO

WW

WW

OW

OO

WO

WW

WW

WO

OW

OO


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.in 8.5-in. Borehole with 7-in. Casing at 29 lbm/ftCarbon/Oxygen Ratio—Cased Hole


φ = 30%, 8.5-in. Borehole, 7-in. Casing at 29 lbm/ft





ratio



0.8

0.6

0.4

0.2

0

0 0.5 1.0

WO

WW

OW

OO


OW

OO

WO

WO

OO

OW

WW

WW

OO

OW


RST* Reservoir Saturation Tool—1.6875 in. and 2.5 in.in 9.875-in. Borehole with 7-in. Casing at 29 lbm/ftCarbon/Oxygen Ratio—Cased Hole







ratio



0.8

0.6

0.4

0.2

0

0 0.5 1.0


OO

OWWO

WW

OO

OWWO

WW

OO

OW

WO

WW

OO

OW

WW

WO

General

General

Permeability

Permeability from Porosity and Water SaturationOpen Hole

PurposeCharts Perm-1 and Perm-2 are used to estimate the permeability of

shales, shaly sands, or other hydrocarbon-saturated intergranular

rocks at irreducible water saturation (S wi).

Description

ExampleGiven: φ = 23 p.u., S wi = 30%, gas saturation with ρh = 0.3 g/cm3

and ρ w = 1.1 g/cm3, and h = 120 ft.

Find: Correction factor and k. Answer: First, find pc to determine the correction factor if the



esc pt oThe charts are based on empirical observations and are similar in

form to a general expression proposed by Wyllie and Rose (1950)

(see Reference 49):

Chart Perm-1 presents the results of one study for which the

observed relation was

Chart Perm-2 presents the results of another study:

The charts are valid only for zones at irreducible water saturation.

Enter porosity (φ) and S wi on a chart. Their intersection defines

the intrinsic (absolute) rock permeability (k). Medium-gravity oil is

assumed. If the saturating hydrocarbon is other than medium-gravity

oil, a correction factor (C′) based on the fluid densities of water and

hydrocarbons (ρ w and ρh, respectively) and elevation above the free-

water level (h) should be applied to the S wi value before it is enteredon the chart The chart on this page provides the correction factor

zone of interest is not at irreducible water saturation:

Enter the correction factor chart with S wi = 30% to inter-

sect the curve for pc = 40 (nearest to 42), for which thecorrection factor is 1.08. The corrected S wi value is S´ wi =

1.08 × 30% = 32.4%.

Chart Perm-1: φS´ wi = 0.072% and k = 130 mD.

Chart Perm-2: φS´ wi = 0.072% and k = 65 mD.

kC

SC

wi

1 2 / .=

+ ′φ

kS wi

1 22 25100 / .

.=

φ

kS

Se wi

wi

1 2 2701

/ .φ = −

ph

c w h=

−( )=

−( )=

ρ ρ

2 3

120 1 1 0 3

2 342

.

. .

..

2.0

1.8

1.6

pc = 200

pc =h(ρw – ρo)

2.3

(1)

(2)

(3)

General


General

Permeability

Perm-1(former K-3)

60



50

40

30

20

10

0

Irreduciblewater

saturationabove

transitionzone,

Swi (%)

φSwi

0.12

0.10

0.08

0.06

0.04

0.02

0.01

5,000

2,0001,000

500

200

100

50

20

10

5

2

1.0

0.5

0.2

0.10.01

P e r m e a b i l i t y , k ( m D )

General

Permeability


Perm-2(former K-4)

40



35

30

25

20

15

10

5

0

Porosity,φ (p.u.)

φSwi

P e r m

e a b i l i t y , k ( m

D )

5,000

1,000

2,000

500

200

50

20

10

100

5

1

0.01

0.02

0.04

0.06

0.08

0.10

0.12

0.10

0.01

General

Permeability

Fluid Mobility Effect on Stoneley SlownessOpen Hole

Perm-3

10,000

Fresh Mud at 600 Hz



0.1

10

100

1,000 50 10 5 1

Membrane impedance

0 GPa/cm(no mudcake)

Mobility

(mD/cp)

General

Cement Bond Log—Casing StrengthInterpretation—Cased Hole

P

urpose

This chart is used to determine the decibel attenuation of casing

from the measured cement bond log (CBL) amplitude and convert

it to the compressive strength of bonded cement (either standardor foamed).

Example

Given: Log amplitude reading = 3.5 mV in zone of interest

and 1.0 mV in a well-bonded section (usually the lowest

millivolt value on the log), casing size = 7 in. at29 lbm/ft, casing thickness = 0.41 in., and neat cement

(not foamed).

Cement Evaluation—Wireline



Description

The amplitude of the first casing arrival is recorded by an acoustic

signal-measuring device such as a sonic or cement bond tool. This

amplitude value is a measure of decibel attenuation that can be

translated into a bond index (an indication of the percent of casing

cement bonding) and the compressive strength (psi) of the cement

at the time of logging.

Enter the chart on the y-axis with the log value of CBL amplitude

and move upward parallel to the 45° lines to intersect the appropri-

ate casing size. At that point, move horizontally right to the attenua-

tion scale on the right-hand y-axis. From this point, draw a line

through the appropriate casing thickness value to intersect the com-

pressive strength scale. The casing wall thickness is calculated by

subtracting the nominal inside diameter (ID) from the outside

diameter (OD) listed on the table for threaded nonupset casing

and dividing the difference by 2.

(not foamed).

Find: Compressive strength and bond index of the cement at

the time of logging.

Answer: Enter the 3.5-mV reading on the left y-axis of Chart

Cem-1 and proceed to the 7-in. casing line.

Move horizontally to intersect the right-hand y-axis at

8.9 dB/ft.

Determine the casing thickness as (7 – 6.184)/2 = 0.816/2

= 0.41 in. Draw a line from 8.9 dB/ft through the 0.41-in.

casing thickness point to the compressive strength scale.

Cement compressive strength = 2,100 psi.

To find the bond index, determine the decibel attenuation of the

lowest recorded log value by entering 1.0 mV on the left-hand y-axis

and proceeding to the 7-in. casing line. Move horizontally to intersect

the right-hand y-axis at 12.3 dB/ft.

Divide the precisely determined decibel attenuation for the CBL

amplitude in the zone of interest by this value for the lowest millivolt

value: 8.9/12.3 = 72% bond index.

A 72% bond index means that 72% of the casing is bonded. This

is not a well-bonded zone because a value of 80% bonding over a 10-ft

interval is historically considered well bonded. Although the logging

scale is a linear millivolts scale, the decibel attenuation scale is loga-

rithmic. The millivolts log scale for the CBL value cannot rescaled

in percent of bonding. If it were, the apparent percent bonding

would be 65% because most bond log scales are from 0 to 100 mV

OD Weight Nominal Drift

(in.) per ft† ID Diameter‡

(lbm) (in.) (in.)

10 33.00 9.384 9.228





(lbm) (in.) (in.)

4 11.60 3.428 3.303



(lbm) (in.) (in.)

7 17.00 6.538 6.413

Threaded Nonupset Casing



103 ⁄ 4 32.75 10.192 10.036

40.00 10.054 9.898

40.50 10.050 9.894

45.00 9.960 9.804

45.50 9.950 9.794

48.00 9.902 9.746

51.00 9.850 9.69454.00 9.784 9.628

55.50 9.760 9.604

113 ⁄ 4 38.00 11.150 10.994

42.00 11.084 10.928

47.00 11.000 10.844

54.00 10.880 10.724

60.00 10.772 10.616

12 40.00 11.384 11.228

13 40.00 12.438 12.282

133 ⁄ 8 48.00 12.715 12.559

16 55.00 15.375 15.187

185 ⁄ 8 78.00 17.855 17.667

20 90.00 19.190 19.002

211⁄2 92 50 20 710 20 522

41 ⁄ 2 9.50 4.090 3.965

11.60 4.000 3.875

13.50 3.920 3.795

43 ⁄ 4 16.00 4.082 3.957

5 11.50 4.560 4.435

13.00 4.494 4.369

15.00 4.408 4.283

17.70 4.300 4.175

18.00 4.276 4.151

21.00 4.154 4.029

51 ⁄ 2 13.00 5.044 4.919

14.00 5.012 4.887

15.00 4.974 4.849

15.50 4.950 4.825

17.00 4.892 4.767

20.00 4.778 4.653

23.00 4.670 4.545

53 ⁄ 4 14.00 5.290 5.165

17.00 5.190 5.065

19.50 5.090 4.965

22.50 4.990 4.865

6 15.00 5.524 5.399

16 00 5 500 5 37518 00 5 424 5 299

20.00 6.456 6.331

22.00 6.398 6.273

23.00 6.366 6.241

24.00 6.336 6.211

26.00 6.276 6.151

28.00 6.214 6.089

29.00 6.184 6.059

30.00 6.154 6.02932.00 6.094 5.969

35.00 6.004 5.879

38.00 5.920 5.795

40.00 5.836 5.711

75 ⁄ 8 20.00 7.125 7.000

24.00 7.025 6.900

26.40 6.969 6.844

29.70 6.875 6.750

33.70 6.765 6.640

39.00 6.625 6.500

85 ⁄ 8 24.00 8.097 7.972

28.00 8.017 7.892

32.00 7.921 7.796

36.00 7.825 7.700

38.00 7.775 7.650

40.00 7.725 7.600

43 00 7 651 7 526

General


Cem-1(former M-1)


Casing size (mm) Centered tool only, 3-ft [0.914-m] spacing

Att ti

115140

194

176273

340



Casing thickness(mm) (in.)

CBL amplitude(mV)

Attenuation(dB/m)

15

10

1

2

3

4

5

6

7

8

9

10

4

8

12

16

20

24

28

32

70

50

40

30

20

15

10987

6

5

4

3

8

7

0.3

0.4

0.5

0.6

7 i n. a t 2 9 l b

m

Compressive strength(psi)

(mPa)

Standardcement1 000

30

25

20

15

10

4,000

3,000

2,000

1,000

Appendix A Linear Grid



Appendix A

Appendix A

9

8

7

6

5

Log-Linear Grid



4

3

2

1

9

8

7

6

Appendix A

Appendix A

0.20

0.25

5,000

4,000

Resistivity scale may bemultiplied by 10 for usein a higher range

For FR =0.62

φ2.15

Water Saturation Grid for Resistivity Versus Porosity



0.30

0.35

0.40

0.45

0.50

0.60

0.70

0.80

0.90

1.0

1.2

1.4

1.6

1.82.0

3,000

2,500

2,000

1,500

1,000

500

Conductivity(mmho/m)

Resistivity(ohm-m)

Appendix A

Appendix A

2

2.5

500

400

Resistivity scale may bemultiplied by 10 for usein a higher range

For FR =1

φ2

Water Saturation Grid for Resistivity Versus Porosity



3

3.5

4

4.5

5

6

7

8

9

10

12

14

16

20

300

250

200

150

100

50

Conductivity(mmho/m)

Resistivity(ohm-m)

Appendix B Logging Tool Response in Sedimentary Minerals

Name Formula ρlog φSNP φCNL φAPS† ∆ tc ∆ ts Pe U ε tp Gamma Ray Σ

(g/cm3) (p.u.) (p.u.) (p.u.) (µs/ft) (µs/ft) (farad/m) (ns/m) (gAPI Units) (c.u.)

Silicates

Quartz SiO2 2.64 –1 –2 –1 56.0 88.0 1.8 4.8 4.65 7.2 4.3

β-cr is tobali te S iO2 2.15 –2 –3 1.8 3.9 3.5

Opal (3.5% H2O) SiO2 (H2O)0.1209 2.13 4 2 58 1.8 3.7 5.0

Garnet‡ Fe3Al2(SiO4)3 4.31 3 7 11 48 45

Hornblende‡ Ca2NaMg2Fe2

AlSi8O22(O OH)23.20 4 8 43.8 81.5 6.0 19 18



AlSi8O22(O,OH)2

Tourmaline NaMg3Al6B3Si6O2(OH)4 3.02 16 22 2.1 6.5 7450

Zircon ZrSiO4 4.50 –1 –3 69 311 6.9

Carbonates

Calcite CaCO3 2.71 0 0 0 49.0 88.4 5.1 13.8 7.5 9.1 7.1

Dolomite CaCO3MgCO3 2.85 2 1 1 44.0 72 3.1 9.0 6.8 8.7 4.7

Ankerite Ca(Mg,Fe)(CO3)2 2.86 0 1 9.3 27 22

Siderite FeCO3 3.89 5 12 3 47 15 57 6.8–7.5 8.8–9.1 52

Oxidates

Hematite Fe2O3 5.18 4 11 42.9 79.3 21 111 101

Magnetite Fe3O4 5.08 3 9 73 22 113 103

Goethite FeO(OH) 4.34 50+ 60+ 19 83 85

Limonite‡ FeO(OH)(H2O)2.05 3.59 50+ 60+ 56.9 102.6 13 47 9.9–10.9 10.5–11.0 71

Gibbsite Al(OH)3 2.49 50+ 60+ 1.1 23

Phosphates

Hydroxyapatite Ca5(PO4)3OH 3.17 5 8 42 5.8 18 9.6

Chlorapatite Ca5(PO4)3Cl 3.18 –1 –1 42 6.1 19 130

Fluorapatite Ca5(PO4)3F 3.21 –1 –2 42 5.8 19 8.5

Carbonapati te (Ca5(PO4)3)2CO3H2O 3.13 5 8 5.6 17 9.1

F ld Alk li‡

Appendix B Logging Tool Response in Sedimentary Minerals

Name Formula ρlog φSNP φCNL φAPS† ∆ tc ∆ ts Pe U ε tp Gamma Ray Σ

(g/cm3) (p.u.) (p.u.) (p.u.) (µs/ft) (µs/ft) (farad/m) (ns/m) (gAPI Units) (c.u.)

Clays‡

Kaolinite Al4Si4O10(OH)8 2.41 34 ~37 ~34 1.8 4.4 ~5.8 ~8.0 80–130 14

Chlorite(Mg,Fe,Al)6(Si,Al)4

2.76 37 ~52 ~35 6.3 17 ~5.8 ~8.0 180–250 25O10(OH)8

Illite

K1–1.5Al4(Si7–6.5,Al1–1.5)

2.52 20 ~30 ~17 3.5 8.7 ~5.8 ~8.0 250–300 18O20(OH)4

Montmorillonite(Ca,Na)7(Al,Mg,Fe)4

2 12 ~60 ~60 2 0 4 0 ~5 8 ~8 0 150–200 14(Si Al) O (OH) (H O)



Montmorillonite 2.12 60 60 2.0 4.0 5.8 8.0 150 200 14(Si,Al)8O20(OH)4(H2O)n

Evaporites

Halite NaCl 2.04 –2 –3 21 67.0 120 4.7 9.5 5.6–6.3 7.9–8.4 754

Anhydrite CaSO4 2.98 –1 –2 2 50 5.1 15 6.3 8.4 12

Gypsum CaSO4(H2O)2 2.35 50+ 60+ 60 52 4.0 9.4 4.1 6.8 19

Trona Na2CO3NaHCO3H2O 2.08 24 35 65 0.71 1.5 16

Tachhydrite CaCl2(MgCl2)2(H2O)12 1.66 50+ 60+ 92 3.8 6.4 406

Sylvite KCl 1.86 –2 –3 8.5 16 4.6–4.8 7.2–7.3 500+ 565

Carnalite KClMgCl2(H2O)6 1.57 41 60+ 4.1 6.4 ~220 369

Langbeinite K2SO4(MgSO4)2 2.82 –1 –2 3.6 10 ~290 24

PolyhaliteK2SO4Mg

2.79 14 25 4.3 12 ~200 24SO4(CaSO4)2(H2O)2

Kainite MgSO4KCl(H2O)3 2.12 40 60+ 3.5 7.4 ~245 195

Kieserite MgSO4(H2O) 2.59 38 43 1.8 4.7 14

Epsomite MgSO4(H2O)7 1.71 50+ 60+ 1.2 2.0 21

Bischofite MgCl2(H2O)6 1.54 50+ 60+ 100 2.6 4.0 323

Barite BaSO4 4.09 –1 –2 267 1090 6.8

Celestite SrSO4 3.79 –1 –1 55 209 7.9

Sulfides

Pyrite FeS 4 99 2 3 39 2 62 1 17 85 90

Appendix C

Appendix C Acoustic Characteristics of Common Formations and Fluids

Nonporous Solids

Material ∆ t Sound Velocity Acoustic Impedance

(µs/ft) (ft/s) (m/s) (MRayl)

Casing 57.0 17,500 5,334 41.60

Dolomite 43.5 23,000 7,010 20.19

Anhydrite 50.0 20,000 6,096 18.17

Limestone 47.6 21,000 6,400 17.34

Calcite 49.7 20,100 6,126 16.60



Calcite 49.7 20,100 6,126 16.60

Quartz 52.9 18,900 5,760 15.21

Gypsum 52.6 19,000 5,791 13.61

Halite 66.6 15,000 4,572 9.33

Water-Saturated Porous Rock

Material Porosity ∆ t Sound Velocity Acoustic Impedance

(%) (µs/ft) (ft/s) (m/s) (MRayl)

Dolomite 5–20 50.0–66.6 20,000–15,000 6,096–4,572 16.95–11.52

Limestone 5–20 54.0–76.9 18,500–13,000 5,639–3,962 14.83–9.43

Sandstone 5–20 62.5–86.9 16,000–11,500 4,877–3,505 12.58–8.20

Sand 20–35 86.9–111.1 11,500–9,000 3,505–2,743 8.20–6.0

Shale 58.8–143.0 17,000–7,000 5,181–2,133 12.0–4.3

Nonporous Solids

Material ∆ t Sound Velocity Acoustic Impedance

(µs/ft) (ft/s) (m/s) (MRayl)

Water 208 4 800 1 463 1 46

Appendix D Conversions

Length

Multiply Centimeters Feet Inches Kilometers Nautical Meters Mils Miles Millimeters YardsNumber Miles

of toObtain by

Centimeters 1 30.48 2.540 105 1.853 × 105 100 2.540 × 10–3 1.609 × 105 0.1 91.44

Feet 3.281×

10–2

1 8.333×

10–2

3281 6080.27 3.281 8.333×

10–5

5280 3.281×

10–3

3

Inches 0.3937 12 1 3.937 × 104 7.296 × 104 39.37 0.001 6.336 ×104 3.937 × 10–2 36

5 4 5 8 6 4



Kilometers 10–5 3.048 × 10–4 2.540 × 10–5 1 1.853 0.001 2.540 × 10–8 1.609 10–6 9.144 × 10–4

Nautical miles 1.645 × 10–4 0.5396 1 5.396 ×10–4 0.8684 4.934 ×10–4

Meters 0.01 0.3048 2.540 × 10–2 1000 1853 1 1609 0.001 0.9144

Mils 393.7 1.2 × 104 1000 3.937 × 107 3.937 × 104 1 39.37 3.6 × 104

Miles 6.214 × 10–6 1.894 × 10–4 1.578 × 10–5 0.6214 1.1516 6.214 × 10–4 1 6.214 × 10–7 5.682 × 10–4

Millimeters 10 304.8 25.40 105 1000 2.540 × 10–2 1 914.4

Yards 1.094 × 10–2 0.3333 2.778 × 10–2 1094 2027 1.094 2.778 × 10–5 1760 1.094 × 10–3 1

Area

Multiply Acres Circular Square Square Square Square Square Square Square SquareNumber Mils Centimeters Feet Inches Kilometers Meters Miles Millimeters Yards

of

toObtain by

Acres 1 2.296 × 10–5 247.1 2.471 × 10–4 640 2.066 × 10–4

Circular mils 1 1.973 × 105 1.833 × 108 1.273 × 106 1.973 ×109 1973

Squarecentimeters 5.067 × 10–6 1 929.0 6.452 1010 104 2.590 × 1010 0.01 8361

Square feet 4.356 × 104 1.076 × 10–3 1 6.944 × 10–3 1.076 × 107 10.76 2.788 × 107 1.076 × 10–5 9

Square inches 6,272,640 7.854 × 10–7 0.1550 144 1 1.550 × 109 1550 4.015 × 109 1.550 × 10–3 1296

Appendix D Conversions

Volume

Multiply Bushels Cubic Cubic Cubic Cubic Cubic Gallons Liters Pints QuartsNumber (Dry) Centimeters Feet Inches Meters Yards (Liquid) (Liquid) (Liquid)

of toObtain by

Bushels (dry) 1 0.8036 4.651 × 10–4 28.38 2.838 × 10–2

Cubiccentimeters 3.524 × 104 1 2.832 × 104 16.39 106 7.646 × 105 3785 1000 473.2 946.4

Cubic feet 1.2445 3.531 × 10–5 1 5.787 × 10–4 35.31 27 0.1337 3.531 × 10–2 1.671 × 10–2 3.342 × 10–2



Cubic inches 2150.4 6.102 × 10–2 1728 1 6.102 × 104 46,656 231 61.02 28.87 57.75

Cubic meters 3.524 × 10–2 10–6 2.832 × 10–2 1.639 × 10–5 1 0.7646 3.785 × 10–3 0.001 4.732 × 10–4 9.464 × 10–4

Cubic yards 1.308 × 10–6 3.704 × 10–2 2.143 × 10–5 1.308 1 4.951 × 10–3 1.308 × 10–3 6.189 × 10–4 1.238 × 10–3

Gallons(liquid) 2.642 × 10–4 7.481 4.329 × 10–3 264.2 202.0 1 0.2642 0.125 0.25

Liters 35.24 0.001 28.32 1.639 × 10–2 1000 764.6 3.785 1 0.4732 0.9464

Pints (liquid) 2.113 × 10–3 59.84 3.463 × 10–2 2113 1616 8 2.113 1 2

Quarts (liquid) 1.057 × 10–3 29.92 1.732 × 10–2 1057 807.9 4 1.057 0.5 1

Mass and Weight

Multiply Grains Grams Kilograms Milligrams Ounces† Pounds† Tons Tons Tons

Number (Long) (Metric) (Short)of toObtain by

Grains 1 15.43 1.543 × 104 1.543 × 10–2 437.5 7000

Grams 6.481 × 10–2 1 1000 0.001 28.35 453.6 1.016 × 106 106 9.072 × 105

Kilograms 6.481 × 10–5 0.001 1 10–6 2.835 × 10–2 0.4536 1016 1000 907.2

Milligrams 64.81 1000 106 1 2.835 × 104 4.536 × 105 1.016 × 109 109 9.072 × 108

Ounces† 2 286 × 10–3 3 527 × 10–2 35 27 3 527 × 10–5 1 16 3 584 × 104 3 527 × 104 3 2 × 104



Appendix E Symbols

Traditional Standard Standard Description Customary Unit or Relation StandardSymbol SPE Computer Reserve

and Symbol† Symbol‡

SPWLA†

a a ACT electrochemical activity equivalents/liter, moles/liter

a KR COER coefficient in FR – φ relation FR = KR /φm MR, a, C

A A AWT atomic weight amu

C C ECN conductivity (electrical logging) millimho per meter (mmho/m) σCp Bcp CORCP sonic compaction correction factor φSVcor = BcpφSV Ccp

D D DPH d th ft H



D D DPH depth ft, m y, H

d d DIA diameter in. D

E E EMF electromotive force mV V

F FR FACHR formation resistivity factor FR = KR /φm

G G GMF geometrical factor (multiplier) fG

H IH HYX hydrogen index iH

h h THK bed thickness, individual ft, m, in. d, e

I I –X index i

FFI IFf FFX free fluid index iFf

SI Isl SLX silt index Islt, isl, islt

Iφ PRX porosity index iφ

SPI Iφ2 PRXSE secondary porosity index iφ2

J Gp GMFP pseudogeometrical factor fGp

K Kc COEC electrochemical SP coefficient Ec = Kclog(aw /amf) Mc, Kec

k k PRM permeability, absolute (fluid flow) mD K

L L LTH length, path length ft, m, in. s, l

M M SAD slope, sonic interval transit time versus M = [(τf – τLOG)/(ρb – ρf)] × 0.01 mθD

density × 0.01, in M–N plot

m m MXP porosity (cementation) exponent FR = KR /φm

Appendix E Symbols

Traditional Standard Standard Description Customary Unit or Relation StandardSymbol SPE Computer Reserve

and Symbol† Symbol‡

SPWLA†

Qv shaliness (CEC per mL water) meq/mL

q fφ shd FIMSHD dispersed-shale volume fraction of φ imfshd, q

intermatrix porosity

R R RES resistivity (electrical) ohm-m ρ, r

r r RAD radial distance from hole axis in. R

S S SAT saturation fraction or percent ρ, s



p ρ,

of pore volume

T T TEM temperature °F, °C, K θ

BHT, Tbh Tbh TEMBH bottomhole temperature °F, °C, K θBH

FT, Tfm Tf TEMF formation temperature °F, °C, K

t t TIM time µs, s, min t

t t TAC interval transit time ∆ t

U volumetric cross section barns/cm3

v v VAC velocity (acoustic) ft /s, m/s V, u

V V VOL volume cm3, ft3, etc. v

V V VLF volume fraction fv, Fv

Z Z ANM atomic number

α αSP REDSP SP reduction factorγ γ SPG specific gravity (ρ /ρw or ρg /ρair) s, Fs

φ φ POR porosity fraction or percentage f, ε

of bulk volume, p.u.

φ1 PORPR primary porosity fraction or percentage f1, e1


φ2 PORSE secondary porosity fraction or percentage f2, e2


φi PORIG intergranular porosity φi = (Vb V )/Vb fi εi

Appendix E

Appendix F Subscripts

Traditional Standard Standard Explanation Example StandardSubscript SPE Computer Reserve

and Subscript† Subscript‡

SPWLA†

a LOG L apparent from log reading RLOG, RLL log

(or use tool description subscript)

a a A apparent (general) Ra ap

abs cap C absorption, capture Σcap

anh anh AH anhydrite

b b B bulk ρb B, t



ρb

bh bh BH bottomhole Tbh w, BH

clay cl CL clay Vcl cla

cor, c cor COR corrected tcor

c c C electrochemical Ec ec

cp cp CP compaction Bcp

D D D density log d

dis shd SHD dispersed shale Vshd

dol dol DL dolomite tdol

e, eq eq EV equivalent Rweq, Rmfeq EV

f, fluid f F fluid ρf fl

fm f F formation (rock) Tf fm

g, gas g G gas Sg G

gr GR grain ρgr

gxo gxo GXO gas in flushed zone Sgxo GXO

gyp gyp GY gypsum ρgyp

h h H hole dh H

h h H hydrocarbon ρh H

hr hr HR residual hydrocarbon Shr

Appendix E

Appendix F Subscripts

Traditional Standard Standard Explanation Example StandardSubscript SPE Computer Reserve

and Subscript† Subscript‡

SPWLA†

log LOG L log values tLOG log

ls ls LS limestone t ls lst

m m M mud Rm

max max MX maximum φmax

ma ma MA matrix tma

mc mc MC mudcake R



mc mc MC mudcake Rmc

mf mf MF mud filtrate Rmf

mfa mfa MFA mud filtrate, apparent Rmfa

min min MN minimum value

ni noninvaded zone Rni

o o O oil (except with resistivity) So N

or or OR residual oil Sor

o, 0 (zero) 0 (zero) ZR 100-percent water saturated F0 zr

p propagation tpw

PSP pSP PSP pseudostatic SP EpSP

pri 1 (one) PR primary φ1 p, pri

r r R relative kr o, krw R

r r R residual Sor, Shr R

s s S adjacent (surrounding) formation Rs

sd sd SD sand sa

ss ss SS sandstone sst

sec 2 SE secondary φ2 s, sec

sh sh SH shale Vsh sha

silt sl SL silt Isl slt



Appendix F

Appendix G Unit Abbreviations

These unit abbreviations, which are based on those adopted by the

Society of Petroleum Engineers (SPE), are appropriate for most publi-

cations. However, an accepted industry standard may be used instead.

For instance, in the drilling field, ppg may be more common than

lbm/gal when referring to pounds per gallon.

In some instances, two abbreviations are given: customary and

metric. When using the International System of Units (SI), or metric,

abbreviations, use the one designated for metric (e.g., m3 /h instead of

m3 /hr). The use of SI prefix symbols and prefix names with customary unit abbreviations and names, although common, is not preferred

(e.g., 1,000 lbf instead of klbf).

curie . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ci

dalton. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Da

darcy, darcies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D

day (customary) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D

day (metric). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . d

dead-weight ton. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DWT

decibel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . dB

degree (American Petroleum Institute). . . . . . . . . . . . . . . . . . . . . . . . . . . °API

degree Celsius . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . °C

degree Fahrenheit °F



( g , , )

Unit abbreviations are followed by a period only when the abbrevia-

tion forms a word (for example, in. for inch).

acre . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Spell out

acre-foot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . acre-ft

ampere . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A

ampere-hour. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-hr

angstrom unit (10–8 cm). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A

atmosphere . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . atm

atomic mass unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . amu

barrel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . bbl

barrels of fluid per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BFPD

barrels of liquid per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BLPD

barrels of oil per day. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BOPDbarrels of water per day. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BWPD

barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B/D

barrels per minute. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . bbl/min

billion cubic feet (billion = 109) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bcf

billion cubic feet per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bcf/D

billion standard cubic feet per day . . . . . . . . . . . Use Bcf/D instead of Bscf/D

(see “standard cubic foot”)

bits per inch bpi

degree Fahrenheit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . °F

degree Kelvin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . See “kelvin”

degree Rankine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . °R

dots per inch. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . dpi

electromotive force. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . emf

electron volt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . eV farad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F

feet per minute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft/min

feet per second. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft/s

foot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft

foot-pound . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft-lbf

gallon. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gal

gallons per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gal/D

gallons per minute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gal/mingigabyte . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gbyte

gigahertz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GHz

gigapascal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GPa

gigawatt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GW

gram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . g

hertz . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hz

horsepower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . hp

h h h h

Appendix G

lines per inch. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lpi

lines per minute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lpm

lines per second . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lps

liter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . L

megabyte . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MB

megagram (metric ton). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mg

megahertz. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MHz

megajoule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MJ

meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . m

metric ton (tonne) t or Mg

pounds of proppant added . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ppa

pounds per square inch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . psi

pounds per square inch absolute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . psia

pounds per square inch gauge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . psig

pounds per thousand barrels (salt content). . . . . . . . . . . . . . . . . . . . . . . . . ptb

quart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . qt

reservoir barrel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . res bbl

reservoir barrel per day. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RB/D

revolutions per minute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . rpm

saturation unit s u

Appendix G Unit Abbreviations



metric ton (tonne) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . t or Mg

mho per meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ω /m

microsecond. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . µs

mile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Spell out

miles per hour . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mph

milliamperes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mA millicurie. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mCi

millidarcy, millidarcies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mD

milliequivalent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . meq

milligram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mg

milliliter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mL

millimeter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mm

millimho . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mmho

million cubic feet (million = 106) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MMcf million cubic feet per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MMcf/D

million electron volts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MeV

million standard cubic feet per day . . . . . . . Use MMcf/D instead of MMscf/D

(see “standard cubic foot”)

milliPascal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mPa

millisecond . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ms

millisiemens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mS

millivolt mV

saturation unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s.u.

second. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s

shots per foot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . spf

specific gravity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . sg

square . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . sq

square centimeter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cm

2

square foot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft2

square inch. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . in. 2

square meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . m2

square mile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . sq mile

square millimeter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . mm2

standard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . std

standard cubic feet per day. . . . . . . . . . . . . . . . . . . . Use ft 3 /D instead of scf/D

(see “standard cubic foot”)standard cubic foot . . . . . . . . . . . . . . . . . Use ft3 or cf as specified on this list.

Do not use scf unless the standard

conditions at which the measurement

was made are specified.

The straight volumetric conversion factor

is 1 ft3 = 0.02831685 m3

stock-tank barrel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . STB

stock-tank barrels per day. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . STB/D

stoke St

Ω

Appendix G

Appendix H References

1. Overton HL and Lipson LB: “A Correlation of the Electrical

Properties of Drilling Fluids with Solids Content,” Transactions,

AIME (1958)

2. Desai KP and Moore EJ: “Equivalent NaCl Concentrations from

Ionic Concentrations,” The Log Analyst (May–June 1969).

3. Gondouin M, Tixier MP, and Simard GL: “An Experimental Study

on the Influence of the Chemical Composition of Electrolytes on

the SP Curve,” JPT (February 1957).4. Segesman FF: “New SP Correction Charts,” Geophysics

(December 1962)

No. 6, PI.

18. Wyllie MRJ, Gregory AR, and Gardner GHF: “Elastic Wave

Velocities in Heterogeneous and Porous Media,” Geophysics

(January 1956) No. 1.

19. Tixier MP, Alger RP, and Doh CA: “Sonic Logging,” JPT (May

1959) No. 5.

20. Raymer LL, Hunt ER, and Gardner JS: “An Improved Sonic

Transit Time-to-Porosity Transform,” Transactions of the

SPWLA 21st Annual Logging Symposium (1980).21. Coates GR and Dumanoir JR: “A New Approach to Improved

Log-Derived Permeability,” The Log Analyst (January–February

1974)



5. Alger RP, Locke S, Nagel WA, and Sherman H: “The Dual Spacing

Neutron Log–CNL,” paper SPE 3565, presented at the 46th SPE

Annual Meeting, New Orleans, Louisiana, USA (1971).

6. Segesman FF and Liu OYH: “The Excavation Effect,”

Transactions of the SPWLA 12th Annual Logging Symposium

(1971).

7. Burke JA, Campbell RL Jr, and Schmidt AW: “The Litho-Porosity

Crossplot,” Transactions of the SPWLA 10th Annual Logging

Symposium (1969), paper Y.

8. Clavier C and Rust DH: “MID-PLOT: A New Lithology

Technique,” The Log Analyst (November–December 1976).

9. Tixier MP, Alger RP, Biggs WP, and Carpenter BN: “Dual

Induction-Laterolog: A New Tool for Resistivity Analysis,” paper

713, presented at the 38th SPE Annual Meeting, New Orleans,

Louisiana, USA (1963).

10. Wahl JS, Nelligan WB, Frentrop AH, Johnstone CW, and

Schwartz RJ: “The Thermal Neutron Decay Time Log,” SPEJ

(December 1970).

11. Clavier C, Hoyle WR, and Meunier D: “Quantitative

Interpretation of Thermal Neutron Decay Time Logs, Part I and

II,” JPT (June 1971).

12. Poupon A, Loy ME, and Tixier MP: “A Contribution to Electrical

Log Interpretation in Shaly Sands ” JPT (June 1954)

1974).

22. Raymer LL: “Elevation and Hydrocarbon Density Correction for

Log-Derived Permeability Relationships,” The Log Analyst

(May–June 1981).

23. Westaway P, Hertzog R, and Plasic RE: “The Gamma

Spectrometer Tool, Inelastic and Capture Gamma Ray

Spectroscopy for Reservoir Analysis,” paper SPE 9461,

presented at the 55th SPE Annual Technical Conference

and Exhibition, Dallas, Texas, USA (1980).

24. Quirein JA, Gardner JS, and Watson JT: “Combined Natural

Gamma Ray Spectral/Litho-Density Measurements Applied to

Complex Lithologies,” paper SPE 11143, presented at the 57th

SPE Annual Technical Conference and Exhibition, New Orleans,


25. Harton RP, Hazen GA, Rau RN, and Best DL: “ElectromagneticPropagation Logging: Advances in Technique and

Interpretation,” paper SPE 9267, presented at the 55th SPE

Annual Technical Conference and Exhibition, Dallas, Texas,

USA (1980).

26. Serra O, Baldwin JL, and Quirein JA: “Theory and Practical

Application of Natural Gamma Ray Spectrometry,” Transactions

of the SPWLA 21st Annual Logging Symposium (1980).

27 Gardner JS and Dumanoir JL “Litho Density Log

Appendix H

31. Freedman R and Grove G: “Interpretation of EPT-G Logs in the

Presence of Mudcakes,” paper presented at the 63rd SPE

Annual Technical Conference and Exhibition, Houston, Texas,

USA (1988).

32. Gilchrist WA Jr, Galford JE, Flaum C, Soran PD, and Gardner JS:

“Improved Environmental Corrections for Compensated

Neutron Logs,” paper SPE 15540, presented at the 61st SPE

Annual Technical Conference and Exhibition, New Orleans,


33. Tabanou JR, Glowinski R, and Rouault GF: “SP Deconvolution

and Quantitative Interpretation in Shaly Sands ” Transactions

40. Brie A, Johnson DL, and Nurmi RD: “Effect of Spherical Pores

on Sonic and Resistivity Measurements,” Transactions of the

SPWLA 26th Annual Logging Symposium (1985).

41. Serra O: Element Mineral Rock Catalog, Schlumberger (1990).

42. Grove GP and Minerbo GN: “An Adaptive Borehole Correction

Scheme for Array Induction Tools,” Transactions of the SPWLA

32nd Annual Logging Symposium, Midland, Texas, USA, June

16–19, 1991, paper F.43. Barber T and Rosthal R: “Using a Multiarray Induction Tool to

Achieve Logs with Minimum Environmental Effects,” paper SPE

22725 t d t SPE A l T h i l C f d

Appendix H References



and Quantitative Interpretation in Shaly Sands, Transactions

of the SPWLA 28th Annual Logging Symposium (1987).

34. Kienitz C, Flaum C, Olesen J-R, and Barber T: “Accurate Logging

in Large Boreholes,” Transactions of the SPWLA 27th Annual

Logging Symposium (1986).

35. Galford JE, Flaum C, Gilchrist WA Jr, and Duckett SW:

“Enhanced Resolution Processing of Compensated NeutronLogs, paper SPE 15541, presented at the 61st SPE Annual

Technical Conference and Exhibition, New Orleans, Louisiana,

USA (1986).

36. Lowe TA and Dunlap HF: “Estimation of Mud Filtrate Resistivity

in Fresh Water Drilling Muds,” The Log Analyst (March–April

1986).

37. Clark B, Luling MG, Jundt J, Ross M, and Best D: “A Dual Depth

Resistivity for FEWD,” Transactions of the SPWLA 29th Annual Logging Symposium (1988).

38. Ellis DV, Flaum C, Galford JE, and Scott HD: “The Effect of

Formation Absorption on the Thermal Neutron Porosity

Measurement,” paper presented at the 62nd SPE Annual

Technical Conference and Exhibition, Dallas, Texas, USA (1987).

39. Watfa M and Nurmi R: “Calculation of Saturation, Secondary

Porosity and Producibility in Complex Middle East Carbonate

Reservoirs,” Transactions of the SPWLA 28th Annual Logging

Symposium (1987)

22725, presented at SPE Annual Technical Conference and

Exhibition, Dallas, Texas, USA, October 6–9, 1991.

44. Moran JH: “Induction Method and Apparatus for Investigating

Earth Formations Utilizing Two Quadrature Phase Components of

a Detected Signal,” US Patent No. 3,147,429 (September 1, 1964).

45. Barber TD: “Phasor Processing of Induction Logs Including

Shoulder and Skin Effect Correction,” US Patent No. 4,513,376

(September 11, 1984).

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Log InterpretationCharts2009 Edition


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The Schlumberger chartbook was initially developed tocorrect raw measurements to account for environmentaleffects and to interpret the corrected measurements.

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serves two primary functions, for training and sensitivityanalysis.

Entering the chartbook will take you to the contents, fromwhere you can access any chart by clicking its entry.

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Enter the chartbook HERE.u

The Schlumberger chartbook was initially developed tocorrect raw measurements to account for environmentaleffects and to interpret the corrected measurements.

Although software may be more effective in deriving results,especially in complex well situations, the chartbook still

serves two primary functions, for training and sensitivityanalysis.

Entering the chartbook will take you to the contents, fromwhere you can access any chart by clicking its entry.

You can also browse the PDF normally.

Enter the chartbook HERE. u



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