03 Porosity Measurement

Schlumberger

(05/96)

Contents

C1.0 POROSITY MEASUREMENTS ....................................................................................................1

C2.0 POROSITY MEASUREMENTS FROM THE BHC SONIC TOOL...................................................3C2.1 INTRODUCTION .....................................................................................................................3C2.2 POROSITY DETERMINATION................................................................................................4C2.3 FACTORS AFFECTING SONIC INTERPRETATION:................................................................7

C3.0 POROSITY MEASUREMENTS FROM THE LITHO-DENSITY TOOL...........................................11C3.1 INTRODUCTION ...................................................................................................................11C3.2 PRINCIPLE...........................................................................................................................11C3.3 POROSITY FROM A DENSITY LOG.....................................................................................13C3.4 LITHOLOGY FROM THE PE MEASUREMENT......................................................................17C3.5 FACTORS AFFECTING DENSITY LOG:................................................................................20

C4.0 POROSITY MEASUREMENTS FROM THE COMPENSATED NEUTRON TOOL.........................21C4.1 INTRODUCTION....................................................................................................................21C4.2 PRINCIPLE ...........................................................................................................................21C4.3 FACTORS AFFECTING CNL LOGS.......................................................................................23

C5.0 TOTAL POROSITY DETERMINATION .......................................................................................29

C6.0 GR LOG.....................................................................................................................................31C6.1 INTRODUCTION ...................................................................................................................31C6.2 PROPERTIES OF GAMMA RAYS ........................................................................................31C6.3 NATURAL GAMMA RAY SPECTROMETRY TOOL...............................................................34

C7.0 BOREHOLE GEOMETRY BY CALIPER MEASUREMENT .........................................................37C7.1 PHYSICAL PROPERTIES.....................................................................................................37

Single-Arm Caliper Configuration................................................................................................40Two-Arm Caliper Configurations .................................................................................................40Three-Arm Caliper Configurations...............................................................................................41Four-Arm Caliper Configuration ..................................................................................................41

C8.0 WORK SESSION.......................................................................................................................43

Introduction to Openhole Logging

(05/96)

Schlumberger

(05/96) C-1

C1.0 Porosity Measurements

C1.1 INTRODUCTIONTotal porosity may consist of primary and

secondary porosity. Effective porosity is thetotal porosity after the shale correction is ap-plied. Rock porosity can be obtained from thesonic log, density log or neutron log. For allthese devices, the tool response is affected bythe formation porosity, fluid and matrix. If thefluid and matrix effects are known or can bedetermined, the tool response can be deter-mined and related to porosity. Therefore, thesedevices are usually referred to as porosity logs.

All three logging techniques respond to thecharacteristics of the rock immediately adjacentto the borehole. Their depth of investigation isshallow—only a few centimeters or less—andtherefore generally within the flushed zone.

As well as porosity, the logs are affected by- volume and nature (lithology) of ma-

trix material- amount and nature of pore space con-

tents (pore geometry, water, hydrocar-bons)

- volume and nature of shales.

For example, the formula for a density logmeasurement including all these variables canbe written as

ρb = φ

e × S

w × ρ

f + φ

e(1 – S

w) ρ

hy + V

shρ

sh +

(1 – φe – V

sh) ρ

ma.

Solving for porosity in this case would notbe easy because there are several unknownsand only one measurement. However, whenwe compare other porosity and log measure-ments, we can solve for these unknowns.


(05/96) C-2

Schlumberger

(05/96) C-3

C2.0 Porosity Measurementsfrom the BHC Sonic Tool

C2.1 INTRODUCTIONIn its simplest form, a sonic tool consists of

a transmitter that emits a sound pulse and areceiver that picks up and records the pulse asit passes the receiver.

The sound emanated from the transmitterimpinges on the borehole wall. This estab-lishes compressional and shear waves withinthe formation, surface waves along the bore-hole wall and guided waves within the fluidcolumn.

The sonic log is simply a recording versusdepth of the time, t

comp, required for a compres-

sional sound wave to traverse 1 m of forma-tion. Known as the interval transit time, transittime, ∆t or slowness, t

comp is the reciprocal of

the velocity of the sound wave. (For the re-mainder of this document, t

comp is known as

∆t.) The interval transit time for a given for-mation depends upon its lithology and poros-ity. This dependence upon porosity, when thelithology is known, makes the sonic log usefulas a porosity log. Integrated sonic transit timesare also helpful in interpreting seismic records.The sonic log can be run simultaneously withmany other services.

The borehole-compensated (BHC) tool trans-mitters are pulsed alternately, and ∆t values areread on alternate pairs of receivers. The ∆t val-ues from the two sets of receivers are averagedautomatically by a computer at the surface forborehole compensation.

The computer also integrates the transit timereadings to obtain total traveltimes (see FiguresC1 and C2).

Figure C1: Schematic of BHC sonde, showingray paths for the two transmitter-receiver sets.

Averaging the two ∆t measurements cancels er-rors from the sonde tilt and hole-size charges.


(05/96) C-4

Sometimes the first arrival, although strongenough to trigger the receiver nearer the trans-mitter, may be too weak by the time it reachesthe far receiver to trigger it. Instead, the far re-ceiver may be triggered by a different, laterarrival in the sonic wave train, and the traveltime measured on this pulse cycle will then betoo large. When this occurs, the sonic curveshows an abrupt, large excursion towards ahigher ∆t value; this is known as cycle skip-ping. Such skipping is more likely to occurwhen the signal is strongly attenuated by un-consolidated formations, formation fractures,gas saturation, aerated muds or rugose or en-larged borehole sections.

9.8 m

2.25 m

Figure C2: BHC Sonic—GR tool distances

The sonic log is run with ∆t presented on alinear scale in tracks 2 and 3 with a choice oftwo scales:

500–100 and 300–100 µsec/m.

A three-arm caliper curve representing theaverage borehole diameter and a gamma ray(GR) curve are recorded simultaneously intrack 1 (See Figure C3).

The gamma ray curve measures the naturalradioactivity of potassium, uranium and tho-rium in the formation and is usually represen-tative of the amount of shale present. This isbecause radioactive elements tend to concen-trate in clays and shales. Later, we will use theGR to compute volume of shale (V

sh).

C2.2 POROSITY DETERMINATIONa) Wyllie Time-Average Equation

After numerous laboratory determinations,M.R.J. Wyllie proposed, for clean and con-solidated formations with uniformly distrib-uted small pores, a linear time-average orweighted-average relationship between poros-ity and transit time (see Figure C4):

tLOG

= φtf + (1 – φ)t

ma(C1)

tLOG

– t

ma

or φ = (C2) t

f –

t

ma

wheret

LOG is the reading on the sonic log in

µsec/mt

ma is the transit time of the matrix mate-

rial

Schlumberger

(05/96) C-5

600

GR

150.00000.0000 (GAPI)

CALI

375.0000125.0000 (MM)

BS

375.0000125.0000 (MM)

DT

100.0000500.0000 (US/M)

FILE 2

BS

BOREHOLE COMPENSATED SONIC

Figure C3 : Borehole-Compensated Sonic Log


(05/96) C-6

tf is the transit time of the saturating fluid

(about 620 µsec/m for freshwater mud sys-tems)

φ is the porosity or volume occupied bypores

1 − φ is the volume of the matrix.

Typical Values:

Sand ∆tmatrix

= 182 µsec/mLime ∆t

matrix = 156 µsec/m

Dolomite ∆tmatrix

= 143 µsec/mAnydrite ∆t

matrix = 164 µsec/m

When the formations are not sufficientlycompacted, the observed ∆t

values are greater

than those that correspond to the porosity ac-cording to the time-average formula, but the φversus t relationship is still approximately lin-ear. In these cases, an empirical correctionfactor, C

p, is applied to Equation 2 to give a

corrected porosity, φSVcor

(Equation 3):

Figure C4: Components of the Wyllie Time-Average Equation

t - t

ma 1

φSVcor

= × (C3)tf -

t

ma C

P

The value of Cp is given approximately by

dividing the sonic velocity in nearby shale bedsby 328. However, the compaction correctionfactor is best determined by comparing φ

SV, as

obtained from Equations 1 and 2, with the trueporosity obtained from another source.

b) Raymer-HuntOver the 25 years since acoustic velocity

well logging was introduced, deficiencies havebeen noted in the transform of transit time ∆tto porosity φ.

Based on extensive field observations oftransit times versus porosity, the new empiri-cal Raymer-Hunt transform was derived. Thenew transform equation is too complicated tobe presented in this course. An approximationof the transform is given in Equation C4 andthe exact transform is presented in the chartbooks as the red lines on all sonic charts.

tLOG

- t

ma

φsv = C (C4)

tLOG

The value of the constant C has a range of0.625 to 0.7 depending upon the investigator.Chart Por-3m (Figure C6) uses 0.7 for C: thiswas the value originally proposed. However,more recent transit time-to-porosity compari-sons indicate that a value of 0.67 is more ap-propriate.

Schlumberger

(05/96) C-7

For the case of a gas-saturated reservoir rock,C becomes 0.6. It should be used when therock investigated by the sonic tool contains anappreciable amount of hydrocarbon in thegassy (vapor) phase. Because of the shallowdepth of investigation, this condition normallyexists only in higher porosity sandstones(greater than 30%).

From the example sonic log (Figure C3) at593 m we read 352 µsec/m. Given ∆t

ma =182

µsec/m we can solve for φ:

Wyllie:

352 - 182 φ = ≅ 39%

620 - 182

Vma

(m/sec)

∆tma

(µ sec/m)

Vma

(m/sec)Range ofValues

Sandstone

Limestone

Dolomites

Anhydrite

Salt

Casing (iron)

5486

6400

7010

6096

4572

5334

182

156

143

164

219

187

5486–5944

6400–7010

7010–7925

6100

4566

5348

Fluid Transit Time: V1 = 1615 m/sec

∆tf = 620 microsec/m for fresh muds = microsec/m for salt muds

Figure C5: Chart showing values used for commonreservoir rocks

Raymer-Hunt (approximation):

5(352 - 182) φ = ≅ 30%

8(352)

Chart Por-3m (Figure C6) solves this equa-tion graphically. Enter t

log of 352 µsec/m on

abscissa and project upward until the appropri-ate ∆t

ma line is reached (V

ma= 5500 m/sec). If

different values of Vma

are used, we get differ-ent values of φ.

With a ∆tlog

= 250µsec/m we would get

Raymer-Wyllie Hunt

Vma F F

Sandstone (5500 m/sec) 16% 18.5%Limestone (6400 m/sec) 21% 24%Dolomite (7010 m/sec) 26% 28.5%

C 2.3 FACTORS AFFECTING SONICINTERPRETATION

LithologyLithology must be known to obtain the cor-

rect Vma

. An incorrect choice of Vma

will pro-duce erroneous calculations.

ShaleShale content generally causes ∆t to read too

high for a porosity calculation because of thebound water in the shale. The sonic reads pri-mary porosity, which may be affected byshale.


(05/96) C-8

Porosity Evaluation from SonicSvf = 1615 m/s

100 150 200 250 300 350 400

t, interval transit time (µsec/m)

vf = 1615 m/sec50

40

30

20

10

0

50

40

30

20

10

0

φ, p

oros

ity (

p.u.

)

φ, p

oros

ity (

p.u.

)

Time average Field observation

1.1

1.2

1.3

1.4

1.5

1.6

Dolomite

Calcite

Quartz

sandsto

ne

8000

7000

6400

5500

5950

vma(ft/sec)

Bcp

Dol

omite

Cal

cite

Qua

rtzsa

ndst

one

Cem

ente

dqu

artz

sand

ston

e

EXAMPLE: t = 76 µs/ft (249 µs/m)SVma = 19,500 ft/s (5950 m/s) - SandstoneThus, φ = 18% (by either weighted average or empirical transform)

SVma (ft/S) tma (µs/ft) SVma (m/s) tma (µs/m)SandstonesLimestonesDolomites

18,000 - 19,50021,000 - 23,00023,000 - 26,000

55.5 - 51.347.6 - 43.543.5 - 38.5

5486 - 59446400 - 70107010 - 7925

182 - 168156 - 143143 - 126

Por-3m

Figure C6

Schlumberger

(05/96) C-9

Fluid TypeThe depth of investigation of the sonic is

shallow; therefore, most of the fluid seen bythe sonic will be mud filtrate.

OilOil usually has no effect.

WaterThere is usually no effect from water except

where the drilling fluid is salt saturated, andthen a different V

f should be used, usually 607

µsec/m.

GasResidual gas causes ∆tlog to read too high

when the formation is uncompacted. The gasbetween the sand grains slows down the com-pressional wave resulting in a long ∆t. Incompacted sands, the wave will travel fromone sand grain to another and the gas effectwill be reduced.

CompactionThe value of ∆t

log will read too high in un-

compacted sand formations. Compaction cor-rections can be made if the compaction factor(B

cp) is known.

An approximate Bcp

is obtained from the sur-rounding shales (B

cp = ∆

tsh/328). B

cp can also

be obtained by comparing the porosity ob-tained from another source (core, density log,neutron log, computed log porosity) to thatobtained from the sonic log in a clean waterzone. (For example, if the neutron log in aclean water zone reads 20% and the sonic logreads 25%, then B

cp = 25%/20% = 1.25.)

Secondary PorosityThe sonic generally ignores secondary po-

rosity. For example, in vugular porosity, thetraveltime through the formation matrix isfaster than the time through fluid in the vugs,because ∆t

f is about 3 to 4 times the value of

∆tma

.

Borehole EffectThe compensated sonic is unaffected by

changing hole size except in the case of ex-tremely rough, large holes where the formationsignal is severely affected by the noise of themud signal and formation damage.

MudcakeMudcake has no effect on the BHC sonic be-

cause the traveltime through the mudcake iscompensated.


(05/96) C-10

Schlumberger

(05/96) C-11

C3.0 Porosity Measurements from theLitho-Density Tool

C3.1 INTRODUCTIONLitho-Density logs are primarily used for po-

rosity and lithology measurements. Other usesinclude the identification of minerals inevaporite deposits, detection of gas, determi-nation of hydrocarbon density, evaluation ofshaly sands and complex lithologies, determi-nation of oil-shale yield and calculation ofoverburden pressure and rock mechanicalproperties.

C3.2 PRINCIPLEA radioactive source, applied to the borehole

wall in a shielded sidewall skid (Figure C7),emits medium-energy gamma rays (662 keV)into the formation.

Figure C7: Schematic Drawing of the Dual SpacingLitho-Density Logging Device

Classical GR interactions by energy level areshown in Figure C8. Because of the medium-energy GR emission, only points 2 and 3 oc-cur with respect to Litho-Density operation.

These gamma rays may be thought of as high-velocity particles that collide with the electronsin the formation. At each collision, a gammaray loses some, but not all, of its energy to theelectron and then continues with diminishedenergy. This type of interaction is known asCompton scattering. The scattered gamma raysreaching the detector, at a fixed distance fromthe source, are counted as an indication offormation density.

The number of Compton-scattering colli-sions is related directly to the number of elec-trons in the formation. Consequently, the re-sponse of the density tool is determinedessentially by the electron density (number ofelectrons per cubic centimeter) of the forma-tion. Electron density is related to the true bulkdensity ρ

b, which, in turn, depends on the den-

sity of the rock matrix material, formation po-rosity and density of the fluids filling thepores.

(GR energy > 1.02 MeV)

(over entire GR energy range)

(ρe)

(low-energy GR)

(Z)

Figure C8: Classical GR— Matter Interactions by Energy Level


(05/96) C-12

In addition to the bulk density measurement,the tool also measures the photoelectric ab-sorption index of the formation, P

e. Photelec-

tric absorption can be related to lithology;whereas the ρ

b measurement responds primar-

ily to porosity and secondarily to rock matrixand pore fluid, the P

e measurement responds

primarily to rock matrix (lithology) and secon-darily to porosity and pore fluid.

At a finite distance from the source, such asthe far detector, the energy spectrum may lookas illustrated in Figure C9. The number ofgamma rays in the higher energy region(region of Compton scattering) is inverselyrelated only to the electron density of the for-mation (i.e., an increase in the formation den-sity decreases the number of gamma rays).The number of gamma rays in the lower en-ergy region (region of photoelectric effect) isinversely related to both the electron densityand the photoelectric absorption. By compar-ing the counts in these two regions, the pho-toelectric absorption index can be determined.

E (keV)

Figure C9: Variations in Spectrum forFormation with Constant Density but Different Z

The gamma ray spectrum at the near detectoris used only to correct the density measure-ment from the far detector for the effects ofmudcake and borehole rugosity.

7 m

4.5 m

Figure C10: Basic SGT- CNT- LDTTool Configuration

Schlumberger

(05/96) C-13

ρma ρf

(1 – φ) φ

ρbFigure C11: Components of Density

Porosity Calculation

C 3.3 POROSITY FROM A DENSITYLOG

For a clean formation of known matrix den-sity ρ

ma, with a porosity φ that contains a fluid

of average density ρf,, the formation bulk den-

sity ρb, will be (Figure C11):

ρb = φρ

f + (1 – φ) ρ

ma (clean wet zone)

where:ρ

b is the measured bulk density (from

Litho-Density tool)ρ

ma is the density of the matrix

ρf is the density of the fluid

φ is the percent volume of pore space(1 – φ) is the percent volume of matrix.

This can be written as

ρma

– ρb

φD =

ρma

– ρfl

where:ρ

ma depends on lithology

ρb is measured by the density log

ρfl depends on fluid type in pore

volumes.

The equation for ρb can be proven mathe-

matically, unlike the sonic equation, which isan empirical relationship. Values of ρ

b are used

for common reservoir rocks (zero porosity)(Figure C12).

From the example Litho-Density log (FigureC13) at 593 m we read ρ

b = 2180 kg/m3.

Given ρf = 1000 kg/m3, ρ

ma = 2650 kg/m3, we

can solve for φD:

2650 − 2180φ

D = = 28.5%

2650 − 1000

Chart Por-5 (Figure C14) solves this equa-tion graphically. For ρ

b = 2180 kg/m3 solving

for porosity using other matrix values gives:

ρma

= 2710 kg/m3 φD = 31%

ρma

= 2870 kg/m3 φD = 36.9%


(05/96) C-14

ρb Values for Common Reservoir Rocks and Fluids

Compound FormulaActualDensity

ρ

ρa

(as seen bytool)

QuartzCalciteDolomiteAnhydriteSylviteHalite

SiO2

CaCO3

CaCO3MgCO3

CaSO4

KCINaCI

265427102870296019842165

264827102876297718632032

Compound FormulaActualDensity

ρ

ρa

(as seen bytool)

Fresh WaterSalt WaterOilGas

H2O200,00ppm

n(CH2)C1.1 H4.2

10001146850ρg

10001135850

1.325 ρg-0188

Figure C12

Schlumberger

(05/96) C-15

600

GR

150.00000.0000 (GAPI)

CALI

375.0000125.0000 (MM)

BS

375.0000125.0000 (MM)

RHOB

3000.00002000.0000 (K/M3)

DRHO

250.0000-250.0000 (K/M3)

FILE 2

BS

LITHOLOGY DENSITY

Figure C13


(05/96) C-16

Formation Density Log Determination of Porosity

40

30

20

10

0

2.8 2.6 2.4 2.2 2.02.31

1.0 0.9 0.8

1.1

1.2

φ, p

oros

ity, (

p.u.

)

ρb, bulk density (g/cm3)

ρ ma

=2.

87(d

olom

ite)

ρ ma

=2.

71(c

alcite

)

ρ ma

=2.

65(q

uartz

sand

ston

e)

ρ ma

=2.

83ρ m

a=

2.68

ρma – ρb

ρma – ρfφ =

ρf

Bulk density, ρb, as recorded with the FDC* or LDT density logs, is converted to porosity with this chart. Touse, bulk density, corrected for borehole size, is entered in abscissa; go to the appropriate reservoir rock typeand read porosity on the appropriate fluid density, ρf. scale in ordinate. (ρf is the density of the fluid saturat-ing the rock immediately surrounding the borehole - usually mud filtrate.)

EXAMPLE:ρb = 2.31 Mg/m3 in limestone lithologyρma = 2.71 (limestone)ρf = 1.1 (salt mud)

Therefore φD = 25 puPor-5

Figure C14

Schlumberger

(05/96) C-17

C3.4 LITHOLOGY FROM Pe

MEASUREMENTThe P

e curve is a good matrix indicator. It is

slightly influenced by formation porosity andthe presence of gas, but responds mainly tolithology (Figure C15). Hence, a safe interpre-tation of matrix lithology can be made forsimple lithologies (one-mineral matrix). Inconjunction with other log data, more complexmineral combinations can be analyzed.

Typical Litho-Density responses for com-mon minerals are presented in Figure C16.

The Pe

measurement is used

1. alone as a matrix indicator (the lithol-ogy curve)

2. in combination with density ρb to ana-

lyze two-mineral matrices and deter-mine porosity

Pe φt

0.5 0.4 0.3 0.2 0.1 0

Figure C15: Photoelectric Absorption Index as a Function of Porosity and Fluid Content


(05/96) C-18

3. In combination with the density andneutron to analyse more complexlithologies (solutions to three-mineralmatrices and porosity).

A direct benefit from the more accurate de-scription of the matrix is a more reliable dis-tinction between gas and oil.

In this section of the course, we use the Pe

curve as a matrix indicator in simple litholo-gies. Using P

e for more advanced applications

(complex lithology identification and heavymineral-detection) is covered in Section H,Porosity in Complex Lithologies.

Examples of the direct use of the Pe curve

for lithology identification are shown in FigureC17. In the case of an anhydrite, P

e is equal to

that of limestone. Anhydrite is positively iden-tified by the bulk density or density porosityvalues.

Pe ρb ρe

0 0

00

0

Figure C16: Typical Litho-Density Responses for Common Sedimentary Rocks

Schlumberger

(05/96) C-19

Figure C17: Lithology Identification with the CNT, Litho-Density and Pe


(05/96) C-20

C3.5 FACTORS AFFECTING THEDENSITY LOG

LithologyThe correct ρ

ma must be known to get correct

porosity.

ShaleThe density of shale in sands can range from

2200 to 2650 but is usually close to 2650, thesame as sandstone. In shaly sands, the densityusually gives a good value of effective porosityregardless of the shale content. The shale ap-pears as matrix to the density tool.

ρb = ρ

f φ

e + ρ

ma (1 – φ

e – V

sh) + ρ

shV

sh

collecting terms:

ρb = ρ

f (φ

e) + ρ

ma(1 – φ

e) + V

sh (ρ

sh – ρ

ma)

if ρsh

= ρma

, the last term is zero.

Fluid TypeThe depth of investigation is quite shallow:

usually most of the formation fluid is flushedaway from the wellbore and the density toolsees drilling fluid or filtrate in the pore space.Hence, the values of ρ

f to use is that of the

drilling mud filtrate rather than the formationwater density.

OilResidual oil will make density porosities

slightly high, because oil is lighter than drillingmud filtrate.

WaterWater density is proportional to the amount

of salt content. The value of ρf is selected in the

computer for porosity determination.

GasThe ρ

f of gas is 100–300 kg/m3. Porosity

determination in gas zones may be high ifthere is residual gas near the borehole. Usuallymost of the gas is flushed and little effect isseen on the density log.

CompactionThe density tool is unaffected by lack of

compaction.

Secondary PorosityThe density reads intercrystalline, vugular

and fractured porosity. The porosity measuredis therefore total porosity.

Borehole EffectDensity gives good values for smooth holes

up to 381 mm in diameter. The tool compen-sates for minor borehole rugosity, but a roughhole causes the density to read too low densi-ties (high porosities) because the skid-to-for-mation contact is poor.

MudcakeFor normal mudcake thickness, there will be

no effect because the tool automatically com-pensates for mudcake.

However for a ∆ρ correction of 100 kg/m3

and greater (i.e., ∆ρ > 100 kg/m3), the toolcompensation may be insufficient and the ρ

b

no longer representative of the formation den-sity. In this case, the density should obviouslynot be used for porosity calculations.

Schlumberger

(05/96) C-21

C4.0 Porosity Measurements from theCompensated Neutron Tool

C4.1 INTRODUCTIONNeutron logs are used principally for the de-

lineation of porous formations and determina-tion of their porosity. They respond primarilyto the amount of hydrogen in the formation.Thus, in clean formations that have pores filledwith water or oil, the neutron log reflects theamount of liquid-filled porosity.

Gas zones can often be identified by com-paring the neutron log with another porositylog or a core analysis. A combination of theneutron log with one or more other porositylogs yields even more accurate porosity valuesand lithology identification—even an evalua-tion of shale content.

3 3/8-in. DIAMETER

Figure C18: Schematic Drawing of the Dual Spacing Compensated Neutron Tool

C4.2 PRINCIPLENeutrons are electrically neutral particles,

each with a mass almost identical to the massof a hydrogen atom. High-energy (fast) neu-trons are continuously emitted from a radioac-tive source in the sonde. These neutrons collidewith the nuclei of the formation materials inwhat may be thought of as elastic billiard-ballcollisions. With each collision, the neutronloses some of its energy.

The amount of energy lost per collision de-pends on the relative mass of the nucleus withwhich the neutron collides. A greater energyloss occurs when the neutron strikes a nucleusof practically equal mass (i.e., a hydrogen nu-cleus). Collisions with heavy nuclei do notslow the neutron much. Thus, the slowing ofneutrons depends largely on the amount of hy-drogen in the formation.

Within a few microseconds, the neutronshave been slowed by successive collisions tothermal velocities, corresponding to energiesof about 0.025 eV. They then diffuse ran-domly, without losing more energy, until theyare captured by the nuclei of atoms such aschlorine, hydrogen or silicon.

The capturing nucleus becomes intensely ex-cited and emits a high-energy gamma ray ofcapture.


(05/96) C-22

When the hydrogen concentration of thematerial surrounding the neutron source islarge, most of the neutrons are slowed andcaptured within a short distance of the source.On the contrary, if the hydrogen concentrationis small, the neutrons travel farther from thesource before being captured. Accordingly, thecounting rate at the detector increases for de-creased hydrogen concentrations and viceversa. Thus, the neutron tool responds to thehydrogen index of the formation. The hydro-gen index is a measurement of the amount ofhydrogen per unit volume of formation (HI ofwater = 1).

Neutron logging tools include the GNT(Figure C19) tools series (no longer in use),

sidewall neutron porosity (SNP) tools (in lim-ited use) and the CNL tool series, which in-cludes the compensated neutron and DNL*Dual-Energy Neutron Log. The current toolsuse americium-beryllium (AmBe) sources toprovide neutrons with initial energies of sev-eral million electron volts.

1) SNP- detects epithermal neutrons- utilizes a skid mounted single detector- can be run in open hole only, either liq-

uid-filled or empty- most corrections are automatically ap-

plied during logging- limited availability.

0

Figure C19: Neutron Energy Travel History

Schlumberger

(05/96) C-23

2) CNL tooldetects thermal neutrons- The CNL tool uses a two-detector sys-

tem that depth and resolution matcheseach count rate before the ratio is com-puted. The ratio value is then convertedto porosity on a linear scale (FigureC20), based on the matrix selected forthe computation (limestone, sandstoneor dolomite).

- Conversion from one porosity assump-tion to another can be done using ChartPor-13b (Figure C22). Por-13b con-verts curves labelled "NPHI" that arenot environmentally corrected and alsoconverts for curves labelled "TNPH"and "NPOR," which are environmen-tally corrected.

- The CNL tool is especially designed foruse in combination with other devices.

- The CNL tool can be run in liquid-filledholes, either open or cased, but notempty holes (i.e., air- or gas-filledholes.)

3) DNL tooldetects thermal and epithermal neutrons- The DNL tool incorporates two

epithermal neutron detectors in additionto the two thermal neutron detectors.Two separate porosity measurementsare obtained, one from each pair of de-tectors.

- Improves the response to gas and en-hances interpretation in the presence ofthermal neutron absorbers.

- In shaly formations containing a largenumber of thermal neutron absorbers,the porosity measured by the epithermal

detectors reads lower and agrees moreclosely with density-derived porosity.

- As with the CNL tool, the DNL tool isespecially designed for use in combina-tion with other devices. In addition, theDNL tool can be run in liquid-filledholes, air/gas-filled holes (epithermalporosity only) and open or cased holes.

C4.3 FACTORS AFFECTING CNL LOGS

LithologyA single known matrix must be present to

accurately determine porosities. Large errorscan occur if the matrix selection is incorrect.

ShaleThe presence of hydrogen in chemically

bound water causes the CNL/DNL tool to readhigh porosities in shales or shaly formations.

Fluid TypeWater: Fresh water has no effects. Saline

water has a reduced hydrogen content and theCNL/DNL tool will read low porosity; thecorrection is in the chart book.

Liquid Hydrocarbons: If the hydrogen con-tent is close to that of water, there is little or noeffect.

Gas: If the hydrogen concentration is low,the CNL/DNL tool reads low porosity.

CompactionAll neutron logs are unaffected by compac-

tion.


(05/96) C-24

600

GR

150.00000.0000 (GAPI)

CALI

375.0000125.0000 (MM)

BS

375.0000125.0000 (MM)

NPHI

0.0000(V/V)

(K/M3)

0.6000

DPHI

0.6000 0.0000

FILE 2

BS

COMPENSATED NEUTRON LITHODENSITY (NO PEF CURVE)

Figure: C20

Schlumberger

(05/96) C-25

Secondary PorosityAll neutron equipment measures total poros-

ity (including primary and secondary).

Borehole EffectThe effects of rough hole are minimized by a

large depth of investigation obtained by the useof a high-yield source and the two-detectorsystem.

When run in combination with the densitytool, an automatic caliper correction system isaccurate to [356 mm]. Normally there is zerostandoff correction.

MudcakeCorrections for mudcake, fluid (mud and

formation) salinity, mud weight, pressure andtemperature are in Charts Por-14(a) and 14(b),in the Log Interpretation Chart Book, but arenot discussed in this course.

The average net correction is usually betweenone and three porosity units. Hence, for calcu-lations by hand, the correction is usually notdone.


(05/96) C-26

Neutron Porosity Equivalence CurvesSidewall Neutron Porosity (SNP), Compensated Neutron Log (CNL*)

Sands

tone

Limes

tone

Dolomite

40

30

20

10

00 10 20 30 40

φSNPcor, Apparent Limestone Neutron Porosity (p.u.) φCNLcor, Apparent Limestone Neutron Porosity (p.u.)

φ, T

rue

Por

osity

for

Indi

cate

d M

atrix

Mat

eria

l

SNP

CNL

©Schlumberger

When the SNP or CNL log is recorded in limestone porosity units, this chart is used to find porosity in sandstonesor dolomites. For the SNP log, first correct for mudcake thickness. (Chart Por-15 is used for SNP mudcakecorrections.)

For the CNL log, simply enter the chart in abscissa with the apparent limestone neutron porosity; go to the ap-propriate matrix line, and read true porosity on the ordinate. (Chart Por-14 is used for CNL environmentalcorrections.)

EXAMPLE: Sandstone bed Giving, hmc = 1/4 in.øSNP = 13 pu (apparent limestone porosity) øSNP = 11 pu (corrected for mudcake)Bit Size = 77/8 in. And, øSNP (sandstone) = 14 puSNP caliper = 75/8 in.

This chart can also be used to find apparent limestone porosity (needed for entering the various CP-crossplotcharts) if the SNP or CNL recording is in sandstone or dolomite porosity units. This chart should be used for CNLvalues labeled NPHI—it should not be used for CNL values labeled TNPH or NPOR.

Por-13a

Figure C21

Schlumberger

(05/96) C-27

Neutron Porosity Equivalence CurvesCompensated Neutron Log (CNL*)

40

30

20

10

00 10 20 30 40

φCNLcor, apparent limestone neutron porosity (p.u.)

φ, tr

ue p

oros

ity fo

r in

dica

ted

mat

rix m

ater

ial

Qua

rtzsa

ndst

one

Calcite

(limes

tone

)

Dolomite

Formation salinity

TNPH NPHI

0 kppm

250 kppm

*Mark of Schlumberger

Por-13b

Figure C22


(05/96) C-28

Schlumberger

(05/96) C-29

C5.0 Total Porosity Determination

We have seen that porosity measurementsare inferred from measurements of bulk den-sity, hydrogen index and acoustic traveltimes.We have also seen that each measurementprovides the necessary input to calculate po-rosity under the following conditions:

– Porosity type is intergranular, not frac-tured or secondary (vuggy, moldic,etc.).

– Matrix type is known and constant.– Rock is clean, (i.e., no shale present).– Porosity is filled with fluid.

Violations of any of these conditions willcause the different porosity measurements todisagree in one fashion or another. This can beused to determine lithology, primary and sec-ondary porosity and gas vs. liquid content. Thequestion to be answered here is: Which poros-ity measurement should be used?

In a sand-shale sequence, for initial compu-tations,

a) if φD is available, use φ

TOTAL = φ

D

b) if φN and ∆t are available, use φ

TOTAL

= φS with compaction corrections

applied.

In a carbonate, for initial computations(limestone matrix),

a) if φN and φ

D are available in sandstone

and limestone units, then use φTOTAL

:

φN

+ φD

φT =

2b) if only ∆t is available, use φ

TOTAL:

φT = φ

S + estimate φ

VUGS.

If gas is present in the reservoir, additional cor-rections to φ

N and φ

D must be applied, as dis-

cussed in Section F.

Porosity calculations in complex lithologies shallare discussed in Section H.


(05/96) C-30

Figure C23: Porosity Comparison between the LDT, CNT and SLT

Schlumberger

(05/96) C-31

C6.0 GR Log

6.1 INTRODUCTIONThe GR log is a measurement of the natural

radioactivity of the formations. In sedimentaryformations the log normally reflects the shalecontent of the formations. This is because theradioactive elements tend to concentrate inclays and shales. Clean formations usuallyhave a very low level of radioactivity, unlessradioactive contaminant such as volcanic ashor granite wash is present or the formationwaters contain dissolved radioactive salts.

"Clean" Formation GR Reading Sands 15 to 30 APILimestones 10 to 20 APIDolomites 8 to 15 API

The GR log can be recorded in cased wells,which makes it very useful as a correlationcurve in completion and workover operations.It is frequently used to complement the SP logand as a substitute for the SP curve in wellsdrilled with salt mud, air or oil-base muds. Ineach case, it is useful for the location of shalesand nonshaly beds and, most importantly, forgeneral correlation.

6.2 PROPERTIES OF GAMMA RAYSGamma rays are bursts of high-energy elec-

tromagnetic waves that are emitted spontane-ously by some radioactive elements. Nearly allthe gamma radiation that occurs in the earth isemitted by the radioactive potassium isotope ofatomic weight 40 (K40) and by the radioactiveelements of the uranium and thorium series.

Each of these elements emits gamma rays,the number and energies of which are distinc-tive for each element. Figure C24 shows theenergies of the emitted gamma rays: potas-sium (K40) emits gamma rays of a single en-ergy at 1.46 MeV, whereas the uranium andthorium series emit gamma rays of variousenergies.

Figure C24: Gamma Ray Emission Spectraof Radioactive Minerals


(05/96) C-32

In passing through matter, gamma rays ex-perience successive Compton-scattering colli-sions with atoms of the formation material,losing energy with each collision. After thegamma ray has lost enough energy, it is ab-sorbed, by means of the photoelectric effect,by an atom of the formation. Thus, naturalgamma rays are gradually absorbed and theirenergies degraded (reduced) as they passthrough the formation. The rate of absorptionvaries with formation density. Two formationswith the same amount of radioactive material

per unit volume, but with different densities,will show different radioactivity levels; the lessdense formations will appear slightly moreradioactive. (Figure C25).

GR uses:1. definition of shale beds2. indicator of shale content3. detection of radioactive and non-

radioactive minerals4. identification of formation tops.

Schlumberger

(05/96) C-33

Figure C25: Relative GR Response for Various Rocks/Formations


(05/96) C-34

6.3 NGS NATURAL GAMMA RAYSPECTROMETRY TOOL

Like the GR log, the NGS Natural GammaRay Spectrometry tool measures the naturalradioactivity of the formations. Unlike the GRlog, which measures only the total radioactiv-ity, this log measures both the number ofgamma rays and the energy level of each andpermits the determination of the concentrationsof radioactive potassium, thorium and uraniumin the formation rocks (Figure C27).

Physical PrincipleMost of the gamma ray radiation in the earth

originates from the decay of three radioactiveisotopes: potassium (K40), uranium 238 (U238)and thorium 232 (Th232).

Potassium-40 decays directly to the stableargon-40 with the emission of a 1.46-MeVgamma ray. However, uranium-238 and tho-

rium-232 decay sequentially through a longsequence of various daughter isotopes beforearriving at stable lead isotopes. As a result,gamma rays of many different energies areemitted and fairly complex energy spectra areobtained, as Figure C26 shows. The charac-teristic peaks in the thorium series at 2.62MeV are caused by the decay of thallium-208and bismuth-214 respectively.

It is generally assumed that formations are insecular equilibrium; that is, the daughter iso-topes decay at the same rate as they are pro-duced from the parent isotope. This means thatthe relative proportions of parent and daughterelements in a particular series remain fairlyconstant; so, by looking at the gamma raypopulation in a particular part of the spectrumit is possible to infer the population at anyother point. In this way, the amount of parentisotope present can be determined.

Figure C26: Potassium, Thorium and Uranium Response Curves (NAl Crystal Detector)

Schlumberger

(05/96) C-35

2025

CGR

TENS---

---SGR

---URAN

---THOR

---POTA

---POTA

2000

1/240

61 02-JUN-1992 15:15 INPUT FILE(S) CREATION DATE

CP 32.6 FILE 3 00- -1941 00:39

---CGR

-10.00 30.000

URAN(PPM )

0.0 .10000

POTA

0.0 40.000

THOR(PPM )

0.0 150.00

CGR(GAPI)

0.0 .09370

POTA

0.0 150.00

SGR(GAPI)

50000. 0.0

TENS(N )

POTASSIUM

THORIUM

NATURAL GAMMA SPECTROMETRY

ACCUMULATED INTEGRATION VALUES SUMMARY:

Integrated Hole Volume: 2.07418 M3 FROM 209.87 M TO 1995.07 M

Figure C27


(05/96) C-36

Once the parent isotope population is known,the amount of nonradioactive isotope can alsobe found. The ratio of potassium-40 to totalpotassium is stable and constant on the earth,whereas, apart from thorium-232, the thoriumisotopes are rare and so can be neglected. Therelative proportions of the uranium isotopesdepend somewhat on their environment, andthere is also a gradual change because of theirdifferent half-lives; at present, the ratio of ura-nium-238 to uranium-235 is about 137.

Applications:- identification of radioactive sands that

may be misinterpreted as shales- identification of different types of

shales/clays (see Figure C28)- depth correlation (same as GR)- complex lithology analysis.

Figure C28: Classification of Radioactive Minerals as a Function of the Th and K Values

Schlumberger

(05/96) C-37

C7.0 Borehole Geometryby Caliper Measure

C7.1 PHYSICAL PROPERTIESThe hole diameter is usually recorded in

conjunction with the following surveys:

- Sonic logs (BHC versions, ASI ArraySeismic Imager, DSI Dipole ShearSonic Imager)

- Microresistivity logs (microlog, Micro-SFL, EPT Electromagnetic Propagationlogs)

- Litho-Density logs- Dipmeter logs (Dual Dipmeter Forma-

tion MicroScanner, FMI FormationMicroImager tools)

- Borehole geometry log

The readings given by different calipers inthe same hole may be different depending onthe caliper design and the hole cross section.

Figure C29 shows the characteristics of thedifferent calipers:

Caliper toolNo. ofArms

Phasing of theArms (Degrees) Maximum Diameter Remarks

Sonic tool 3 120 16 in. [406 mm]3 arms coupled1 reading

Microlog tool 1 0 20 in. [508 mm]1 arm1 reading

Micro-SFL tool(option A)

1 0 16 in. [406 mm]1 arm1 reading

Micro-SFL tool(option B)

4 90 22 in. [558 mm]4 arms coupled 2 × 22 paired readings

Density tool 1 0Short Arm 16 in. [406 mm]Long Arm 21 in. [533 mm]

1 arm1 reading

Dipmeters 4 90 FMS/FMI 22 in. [558 mm]4 arms coupled 2 × 22 independent readings

Borehole Geometrytool

4 90Standard 30 in. [762 mm]Special 40 in. [1016 mm]

4 arms coupled 2 × 22 independent readings

Dual Axis 2 180 16 in. [406 mm]2 arms coupled1 reading

Figure C29: Caliper Specifications for Different Devices Statedon the Logs


(05/96) C-38

1) Mudcake is a good reason to have dif-ferent calipers reading different values:- If the arm of the caliper is the blade

type, it will cut into the cake andthis arm will ignore the thicknessof the mudcake.

- If the arm is of the pad type, it willskid over the cake and the mudcakethickness will be taken into account.

2. Assuming no mudcake, the readings ofdifferent calipers in a perfectly roundhole will be identical.

But holes are not always round. Inclearly ovalized holes, two- three- andfour-arm calipers will read differenthole diameter values, mostly because ofthe way these arms are coupled to-gether.

If the logging tool is fairly free to rotateinside the hole:- Two-arm calipers will ride using

the larger diameter of the hole.- Four-arm calipers will ride with

one pair of coupled arms using thelarger diameter of the hole.

3) In deviated wells, calipers may par-tially collapse under their own weightand give readings that are too low.

The following example (Figure C30)shows different calipers in an ovalizedhole:

- The sonic caliper (three arms linkedtogether) shows an average hole di-ameter.

- The density caliper (one arm) is ap-plied on the wall with strength. Itsback-up arm will cut into the mud-cake. If no small-axis hardware isused, it will orient itself to read thelargest diameter. If small-axishardware is used, the Litho-Densitytool tracks the smoother, short axisof the hole (if ovality exists).

- The microlog caliper (one arm) willprobably orient itself to read thelarger diameter. Its pad will skid onany mudcake. This is the case in theupper part and lower part of thissection.

- Most calipers are designed to rec-ord accurate hole diameters in cy-lindrical boreholes. When bore-holes are noncylindrical anddepending on caliper configura-tions, a tool string will orient itselfin some preferential direction. Thiscan effect both caliper readings andlog responses.

Using Figure C31, consider the caliperresponses in a 200- × 400-mm ovalborehole for the various caliper types,configurations and preferred tool orien-tations. 100 m of 200- × 400-mm holehas a volume of 6.28m3.

Schlumberger

(05/96) C-39

Figure C30: Comparison of Various Caliper Responses


(05/96) C-40

Single-Arm Caliper Configuration:• records one borehole diameter = 400

mm• calculated 100 m hole volume = 12.57

m3 (+100% error)• tool examples:

- Litho-Density log(No short-axis hardware)

- MicroSFL tool (option A)- EPT Electromagnetic Propa-

gation tool.

Two-Arm Caliper Configurations:a. Unidirectional

• records one borehole diameter = 400mm

• calculated 100 m hole volume = 12.57m3 (+100% error)

• tool example:- MicroSFL tool (option B).

b. Bidirectional Long Axis• records one borehole diameter = 195

mm• records a second diameter = 195 mm• calculated 100 m hole volume = 2.9 m3

( −53%).

c. Bi-directional Short Axis• Records one borehole diameter = 273

mm• Records a second diameter = 273 mm• Calculated 100m hole volume = 5.85m3

(−7%).

Figure C31: Caliper Responses Under Various Hole Conditions

Schlumberger

(05/96) C-41

Three-Arm Caliper Configurations:a. Centered

• records one borehole diameter = 260mm

• calculated 100 m hole volume = 5.31m3

(−15%)• tool example:

- sonic log.

b. 90- Degree Offset• records one axis diameter = 200 mm• records a second diameter = 382 mm• calculated 100m hole volume = 6.00 m3

(−4%)• tool examples:

- CNL Compensated Neutronlog

- Litho-Density log (short-axishardware applied).

Four-Arm Caliper Configuration:• records one-axis diameter = 200 mm• records a second diameter = 400 mm• calculated 100-m hole volume = 6.28

m3 (0%)• tool examples:

- borehole geometry log- Dual-Dipmeter tool- Formation MicroScanner- FMI Formation MicroImager.

Figure C31 (Continued)


(05/96) C-42

Schlumberger

(05/96) C-43

C8.0 Work Session

1a. For the example logs of Figures C32 – C34, calculate the following:

(Formation = Sandstone) 581 m 600 m

a. RILD

b.Rt

c. ∆t

d.φS

e. φD

f. φN

2. Using the sonic log of Figure C34, calculate the sonic porosity at 586 m.

∆tf = 620 µsec/m

∆tma

= 182 µsec/m

∆t - ∆tma

φs = =

∆tf - ∆t

ma

5(∆t - ∆tma

)φ

s = =

8∆t

b. Using Chart Por-3m (Figure C6)

φs Wyllie Time-Average =

φs Field Observation =


(05/96) C-44

3a. On the CNT–Litho-Density log of Figure C35, what effect is seen at 1941 to 1946 m?

b. Using the Pe, what is the lithology in this zone?

c. Convert the log readings (φN and φ

D) to equivalent sandstone values.

d. Explain the effect identified in question 3a.

Schlumberger

(05/96) C-45

600

SP

0.0000-150.0000 (MV)

SFLU

2000.00000.2000 (OHMM)

ILD

2000.00000.2000 (OHMM)

ILM

2000.00000.2000 (OHMM)

FILE 2

ILM

DUAL INDUCTION - SP/SFL

Figure C32


(05/96) C-46

600

GR

150.00000.0000 (GAPI)

CALI

375.0000125.0000 (MM)

BS

375.0000125.0000 (MM)

NPHI

0.0000(V/V)

(V/V)

0.6000

DPHI

0.6000 0.0000

FILE 2

BS

COMPENSATED NEUTRON LITHODENSITY (NO PEF CURVE)

SANDSTONE

Figure C33

Schlumberger

(05/96) C-47

600

GR

150.00000.0000 (GAPI)

CALI

375.0000125.0000 (MM)

BS

375.0000125.0000 (MM)

DT

100.0000500.0000 (US/M)

FILE 2

BS

BOREHOLE COMPENSATED SONIC

Figure C34


(05/96) C-48

NPHI---

---PEF

DRHO---

1925

1/240

1 05-JUN-1992 08:58 INPUT FILE(S) CREATION DATE

CP 32.6 FILE 4 05-JUN-1992 11:42

.45000 -.1500

DPHI(V/V )

.45000 -.1500

NPHI(V/V )

0.0 10.000

PEF

-250.0 250.00

DRHO(K/M3)

0.0 150.00

GR(GAPI)

125.00 375.00

CALI(MM )

125.00 375.00

BS1

125.00 375.00

C2(MM )

CP 32.6 FILE 4 05-JUN-1992 11:42

LIMESTONE

COMPENSATED NEUTRON - LITHO DENSITY (WITH PE)

1950

DPHI---

---BS1

---CALI

---GR

Figure C35

03 Porosity Measurement

Documents

Transcript of 03 Porosity Measurement