Fundamentals of Log Interpretation - I

SPONTANEOUS POTENTIAL LOGS

GAMMA RAY LOGS

Log Characteristics

• The difference between the electric potential of a moveable electrode

in the borehole and the electric potential of a fixed surface electrode

is measured as a function of depth

• Opposite shales, the SP curve is usually a more-or-less straight line –

called a shale baseline

• Opposite permeable formations (sands), excursions from the shale

base line are observed. Opposite thick permeable beds, the

excursions reach a constant value – called a sand line

• The deflections on a SP log may be either to the left (negative) or to

the right (positive), depending on the relative salinity of the mud

filtrate and the formation waters.

if, water salinity > mud filtrate salinity, deflection to left

if, water salinity < mud filtrate salinity, right deflection

• SP log cannot be recorded in holes filled with non-conductive (oil

based) muds. If resistivities of mud filtrate and formation water is

similar, SP deflections will be minimal and featureless

Sand line Shale line

Basic Principle

• SP currents caused by electromotive forces in the formations:

− Electrochemical component

− Electrokinetic component

• Two electrochemical effects

I )

Layered clay structure and charges on the layers favor the transport

of Na+ ions from the filtrate. Movement of charged ions electric

current

The electrical potential that induces the flow of cations through shale

is called membrane potential

II) At the edge of the invaded zone:

Since formation water is more saline than mud filtrate, transport of

Cl- ions from formation water to mud filtrate, current in opposite

direction to flow of anions

Electric potential driving this current is liquid junction potential

SHALE

SAND

Saline mud

filtrate

Electric current

SHALE

SAND

Saline mud

filtrate

Electric current

More saline formation water

Basic Principles

• Electrochemical forces:

− Membrane Potential >> Liquid junction potential

− If permeable zone contains some shales or dispersed clay, total

electrochemical emf reduced since these shales/clays produce an

electrochemical membrane of opposite polarity to that of the

adjacent shale bed

• Electrokinetic Potential: Induced when an electrolyte flows through a

permeable, non-metallic porous medium

− Magnitude of electrokinetic potential depends on the differential

pressure producing the flow and the resistivity of the electrolyte

− Electrokinetic potential (Eek) is produced by the flow of mud

filtrate through the mudcake found opposite the permeable zones.

Low permeability of mudcake high differential pressure

higher Eek

− Electrokinetic potential also produced across the shale (low

permeability)

− Net electrokinetic potential contribution to the SP reading is the

difference between the contributions of the mudcake and that of

the shale

SHALE

SAND

Direction of electrokinetic current

Mud cake

SP Principles

Current direction in above figure corresponds to formation water being

more saline than mud filtrate

Potential adjacent to permeable sand bed negative compared to potential

adjacent the shale – Negative (left) deflection of SP curve

If formation water is fresh (less saline), opposite direction of current

flow – SP deflection to the right opposite permeable bed

SP currents flow through four different zones/media:

− borehole

− invaded zone

− uninvaded portion of the permeable zone

− shales

SP measurements are of the potential drop in the borehole only – a small

portion of the total potential drop

If the current loop could be prevented from being complete – potential

drop in the borehole (mud) will be equal to the total emf

SP under such idealized condition is called static SP (SSP)

SP characteristics

• Small cross-sectional area of the borehole available to flow of current

compared to the formation implies that maximum potential drop

occurs across the borehole

SP deflection opposite thick permeable sands do approach SSP

value

• SSP value can be determined from SP curve if there exist clean, thick,

water bearing beds in the given horizon. A line is drawn through the

negative maxima opposite the permeable bed. Another line is drawn

through the SP opposite intervening shale beds. The difference in mV

is the SSP

Shape of the SP curve

If formation resistivity and the mud resistivity are comparable , then the

resultant SP curves yield a much crisper definition of the bed boundaries

than when Rt = 21 * Rm. Why?

SP Baseline Shift

Baseline shift occurs whenever formation waters of different salinity are

separated by a shale bed that is not a perfect cationic membrane.

Shale base line does

not return to the

earlier base line

Gamma Ray Logs

• Measure of natural radioactivity of the formations

• Gamma rays are bursts of high-energy electromagnetic

waves spontaneously emitted by radioactive material

(potassium, uranium and thorium) in rocks

• Radioactive material predominantly in shales. Why?

o The lattice structure of clay materials has holes (gaps)

that are occupied by radioactive material

o Shales have very low permeabilities – little possibility

of radioactive material getting washed out

o Clays have igneous origin – more likely to be

radioactive

o Sandstones have quartz origin that have very tight

lattice and cannot accommodate radioactive material

• What comprises a gamma-ray logging device?

o A detector to measure gamma ray radiation emanating

from near the borehole

o Gamma ray propagation through porous media is a

statistical phenomena - measurement may fluctuate

over time

o Average gamma ray intensity over a time window

(‘time constant’ of the tool) is recorded

• The propagation of γ-rays through reservoir rocks is

controlled by the density of the rock – higher the density of

rock, lower will be the measured γ-ray count

Gamma Ray Characteristics

• Resolution of the gamma-ray tool is generally:

o 6 inches to 2 ft. vertically

o 6 inches to 1 ft. horizontally

• Resolution is governed by:

o the time constant of the tool : if time constant is too

large, the γ-ray emitted by thinner shale features in the

reservoir will be averaged out

o Logging speed : slower speed more time to establish

meaningful statistical counts – good record

• Gamma-ray useful for establishing shale beds:

o Can be used in cased/uncased holes

o Can be used in holes with any type of drilling fluid

• Bed boundary picked midway between maximum and

minimum deflection opposite a shale feature

• Gamma-ray can also be used to compute volume proportion

of shale at any vertical location along the well:

o Calculate γ-ray index: sandcleanshale

sandclean

GRGR

GRGRGRI

−

−=

o Read volume of shale Vsh from chart

o 3 curves in the chart: 45o line – upper bound regardless

of formation,

line 2 – older (pre-tertiary rocks – more dense), line 3 –

younger (tertiary rocks – less dense)

Vsh correlation (empirical – Dresser Atlas)

POROSITY LOGS

Neutron Log

• Delineates porous formation and determines their porosity

• Respond primarily to the amount of hydrogen in the

formation (predominantly in water and liquid

hydrocarbons) reflects the amount of liquid-filled φ

Tool cannot distinguish between oil and water

• Gas zones are primarily detected by comparing neutron

logs to other logs e.g. density logs

• Neutrons (neutral particles – mass nearly equal to

Hydrogen atom) emitted into formation collide with

nuclei of formation material reduction in energy

• Maximum reduction in energy when neutron collides with

particle of same mass (hydrogen nucleus)

• After few collisions, velocity of neutrons slow sufficiently

to diffuse randomly in the media and are captured by nuclei

of atoms such as Cl, H or Si

• Capturing nucleus is excited and emits a burst of high-

energy γ-ray of capture : tool measures γ-ray and/or counts

the neutrons impinging a detector

• When H-conc. in area around well bore is high (high

hydrogen index), most neutrons captured in immediate

vicinity of well neutron count rate decreases

Neutron Logging Tools

• SNP – Sidewall Neutron Porosity Log

� Neutron source and detector mounted on a skid that is

pressed against the hole wall

� Detector is shielded - only electrons with energies above

certain (epithermal) threshold are detected

� minimizes spurious effects due to strong thermal neutron

absorbers (e.g. Cl and Bo) in formation waters

� Provides good measurement in open holes – liquid-filled or

empty

• CNL – Compensated neutron Log

� Mandrel-type tool – tool in conjunction with other types of

logging tools

� Dual- thermal neutron detectors – ratio of recordings at the

two detectors used to compute neutron porosity index

� Long source-detectors spacing gives greater depth of

investigation

� Effect of borehole parameters reduced by taking ratio of

two readings

� Can be used in liquid –filled cased or uncased holes but not

air-filled holes

� Since thermal-neutrons are captured – tools affected by

presence of elements having thermal neutron capture

properties such as shales

� Neutron tools tend to read high porosity in shales – due to

bonded-water in clay. If gas present in shale, neutron count

is high – offset by low count due to shale neutron capture effect of gas is masked on the log readings

Neutron-Log Corrections

• Correction for varying borehole radius

• Salinity effects (mud and formation fluid) : Chlorine an

excellent neutron absorber – reduction in neutron count –

higher φ

• High apparent porosity in shale due to bonded water

• Mud and mudcake have high hydrogen count – apparent high

neutron porosity

• Porosity reading affected by lithology – SNP/CNL scaled for

limestone matrix – correction for other matrix using figure

Density Log

• Gamma rays emitted by a source in the tool. These

γ-rays interact with atoms in formation material and

dislodge an electron – Compton scattering

• G-ray diminishes to lower energy level and is

recorded by a detector

• Extent of Compton-scattering (hence of energy of

impinging g-ray) related to electron density in

formation

• Electron density is directly related to material bulk

density (i.e. combined density of rock matrix, fluids

in pore spaces)

Skid-mounted tool

Density tool corrections

1. Mud cake correction – Ideally count rate in both short

and long-spaced detectors should be same in absence

of mud-cake - however mud-cake invariably

present

formation density constant, but

thicknessmud cake varied

Density log corrections

Mud-cake correction charts

mud cake density constant

but thicknessmudcake and

formation density varied

mud-cake density and

thickness varied, formation

density constant

2. Lost pad contact: Results in density reading to be

affected by borehole fluids. If problem is severe:

significant deviations from average readings in a zone.

Porosity from Density Logs

• Reading from density log affected by matrix + fluids

(volume of pore spaces)

i.e. ρdensity=ρfluid * φ + ρmatrix * (1-φ)

or fluidmatrix

densitymatrix

ρρ

ρρφ

−

−=

ρmatrix commonly:

2.65 - for sands and limestones

2.68 - “limey” sands or “sandy limes”

2.71 - limestones

2.87 – dolomites

ρfluid commonly:

1.1 gm/cc – highly saline water

1.0 gm/cc – fresh water

>1.0 gm/cc – oil based mud

<1.0 gm/cc – in flushed oil/gas zones

• Shaly formations

o If laminated shale present:

shaleshaledensitycorr V*φφφ −=

where: fluidmatrix

shalematrixshale

ρρ

ρρφ

−

−= in nearby shale

bed

Vshale is proportion of shale (a fraction)

o Dispersed shale:

shaledensitycorr V−= φφ

φcorr due to dispersed shale < φcorr laminated shale

Density logs

• ρshale formation specific and depends on overburden

stress etc. – best read from log adjacent to a shale bed

When shale forms the structural framework of the rock

i.e. is the matrix material:

densitycorr φφ =

• When residual fluid saturations are high: low recorded

density φdensity> φtrue

Empirical corrections:

Oil zones : densitycorr φφ ×= 9.0

Gas zones : densitycorr φφ ×= 7.0

POROSITY CROSSPLOTS

Presence of Gas

• ρb (bulk density) read to be too low φdens too high

• φneutron reads low (provided no shale present)

“Football” effect seen on the log

Detection of gas zone difficult in shale zones

Lithology determination

Neutron- density cross plot for freshwater mud/formation

water (ρwater = 1.0 gm/cc)

Note: The porosity on both axes is limestone porosity. If

φdensity is computed in sandstone, calculate:

( )fluidmatrixsanddensitymatrixsandbulk ρρφρρ −⋅−= −−

Calculate: fluidmatrix

bulkmatrix

ρρ

ρρφ

−

−=

−

−−

lime

limedensitylime

Lithology determination

Lithology Determination

Lithology Determination

Mixture of matrix material (sandstone + limestone,

limestone + dolomite or sandstone + dolomite)

Presence of Gas

• Low neutron porosity reading and high density

porosity reading

• Connect equal porosity tie lines on sandstone and

limestone curves and extend to porosity read value –

gives approximate φ for the formation

Evidence of shale

• Shale point established using readings on nearby shale

bed

• Plotting points corresponding to values within a

formation of interest, we might observe a trend or

trajectory:

o If trajectory resembles A – structural shale

o Trajectory B – laminated shale

o Trajectory C – dispersed shale

o Recall- structural shale implies little correction to

φdens, dispersed shale – maximum correction,

laminated – less correction

RESISTIVITY LOGS

Basic Concepts

• Ability of formation to conduct current is directly related

to the amount of water in formation

• Rock grain material have very low conductivity, hence

measured conductivity (resistivity) is a function of water

saturation and porosity

• Resistivity is related to resistance through:

L

ArR ×= R – resistivity ohm-m

• Formation resistivities range from 0.2 – 1000 ohm-m

• Current flow in formation through water made

conductive by salts (Na+, Cl- ions)

• Resistance due to a cube full of water:

A

LRr ww ×=

Replacing water with porous material 100% saturated

with water, resistance measured is:

'

'

A

LRr wo ×= (neglecting resistivity of rock material)

LL >' due to tortuosity, AA <' reduced by the effective

pore volume available for current flow.

Basic Concepts (cont’d)

• The ratio w

o

r

r is a measure of the formation

characteristics

• Taking L = 1 m and A = 1 m2, w

o

w

o

R

R

r

r= and formation

resistivity factor , w

o

R

RF =

• Since Ro is different from Rw because of tortuosity

(related to cementation and rock texture) and reduction

in area (due to porosity), formation resistivity factor F:

m

aF

φ= (Archie’s

formula)

a – rock texture; m – cementation index

• Calibration results:

2

81.0

φ=F in sands

2

1

φ=F in carbonates

• Humble formula:

15.2

62.0

φ=F sandstone

Saturation determination

• In formation containing oil or gas (insulators), resistivity

is a function of F, Rw and water saturation Sw (fraction of

pore space occupied by water):

t

ow

R

RS =

2 Archie’s formula

• Ro, resistivity corresponding to formation 100%

saturated with water is rarely measured directly.

Knowing porosity from sonic and/or neutron log:

t

wm

t

ww

R

Ra

R

RFS

⋅⋅=

⋅=

−φ2

Rt measured by resistivity log, Rw from oil field water

catalog / water compositional analysis / SP log

• The Rwa log is computed as

F

RR t

wa =

where Rt is from a deep-investigation resistivity log and

F is calculated from a porosity log reading.

For clean water bearing zones, Rt = Ro = FRw, which

implies that Rwa = Rw

Resistivity of formation

If a consistent low value is observed in the Rwa log for

several potential reservoir zones, then that low value of

Rwa is probably the formation water resistivity Rw.

Water resistivity from SP logs

Recall SP is natural potential induced due to salt

concentration difference between formation water and mud

filtrate:

mf

w

a

aKSP log⋅=

aw is the chemical activation potential of formation water,

amf of filtrate and K is a solution constant (function of

Tformation)

Expressed in resistivity terms:

mfe

we

R

RTSP log)133.060( ⋅+−=

T – formation temperature in oF

Formation waters rarely composed of pure NaCl, other ions

such as Ca+ and Mg+ are present. Similarly, mud filtrate

may sometimes contain potassium, calcium or magnesium

Rmf measured must be converted to Rmfe using chart in

following page

e

e

mf

w

R

RKSP log⋅−=

K = -(60 + 0.133T)

K

SP

mfw

e

e

RR

−

=

10

Formation water resistivity

Read SP corresponding to clean water bearing layer.

Calculate Rwe, calculate Rw from chart or from:

)24.069.0(

1058.0−

+−= weRwR if Rwe @ 75oF > 0.12

ohm-m

we

wew

R

RR

377146

577

−

+= otherwise

Resistivity Tools - Normal Device

• Current of constant intensity between electrodes A & B.

• Equipotential lines due to current are spheres

• Difference in potential between M and N (located an

infinite distance away) measured

• Potential recorded is related to resistivity of formation

• Distance AM – spacing of tool (16 in., 64 in etc.)

• Deepest point where measurement is made corresponds

to point O (zero point - midway between A and M)

Resistivity Tools - Lateral device

• Constant current between A and B

• Potential difference between two points M and N on two

concentric spherical surfaces centered on A measured

• Zero point is at O midway between M and N

• Spacing of tool is AO (18 ft. 8in lateral etc.)

• In general for both normal and lateral tool, longer the

spacing, deeper the radius of investigation

Normal and Lateral Curves

• Normal curve opposite resistive formation – apparent

bed thickness less than true by distance equal to tool

spacing – thick bed Rt equal to true resistivity (no

invasion)

• Thin resistive bed – curve reversed:

Rt-app <Rsh when Rt-true > Rsh.

Two spurs observed – distance between spurs equal to

true bed thickness + tool spacing

• Thick bed less resistive than surrounding formation –

apparent thickness greater than true thickness by amount

equal to tool spacing

Effect of bed thickness on lateral device

Formation more resistive than

surrounding

Formation less resistive than

surrounding

• A minimum bed thickness is needed to obtain plateau

reading uninfluenced by surrounding formation

• In very thin beds – strong peak corresponding to resistive

bed, “blind zone” below the bed and a spurious reflection

peak

• Curves in all cases not symmetrical • When formation less resistive than surrounding, anomaly extends

below bed for distance > tool spacing

Resistivity Tools

Focussed devices (Laterologs, SFL)

Useful when:

− Rt/Rm ratios are large

− Beds show large resistivity contrasts and/or

are thin

− Drilling muds are salty and conductive

• Comprises of a center electrode A0, three pairs of

electrodes: M1M2, M1’M2

’ and A1A2

• Each electrode pair symmetrically located with

respect to A0 and connected to each other (short-

circuited)

• Constant current emitted from A0. Adjustable

bucking current emitted in A1A2. Current intensity

adjusted until same potential measured at the

monitoring pairs M1M2 and M1’M2

’

• M1-M2 and M1’- M2

’ are at same potential (since they

are shorted). M1-M1’ are at same potential. No

current flowing in hole between monitoring pairs

current from A0 flows as a sheet into the formation

• Potential drop between M1M2 (or M1’M2

’) and ground

electrode recorded

Effect of bed thickness

• Thickness of current sheet is approx. 32 in when

length A1A2 is 80 in. (Laterolog 7)

• If bed thickness is greater than 32 in. – adjacent bed

effects eliminated

• If bed thickness < 32 in. current divided between bed

and adjacent formation – apparent resistivity reading

increased if Rsh > Rbed and lowered if Rsh < Rbed

• In general, even if Rt/Rm > 5000, beds can be clearly

delineated

Induction Tools

• Measures conductance (inverse of resistance) of the

formation

• An alternating current is applied to the insulated

transmitter coil, produces an alternating

electromagnetic field

• Magnetic field penetrates formation and induces

current

• Formation current induces secondary magnetic field

around receiver coil

• Secondary field converted to current whose intensity

is proportional to conductivity of formation

• Tool response can be visualized as sum of all

formation loops (mud + invaded zone + virgin zone +

surrounding formation) Total induced current on

receiver coil can be written as:

ssttxoxommI CGCGCGCGC +++=

G’s are geometric factors

and 1=+++ stxom GGGG

Induction tools

• Volume of space (mud, invaded zone etc..) defined

only by its geometry relative to the tool and this can

be used to prepare correction charts for invasion,

mud etc..

• In dual induction tool– a shallow curve measures

flushed zone resistivity, a medium zone measures

invaded zone and a deep zone reflects Rt

• Induction log ideal for air-drilled holes or holes

drilled with non-conducting mud

Induction log corrections

Borehole diameter correction

Induction log corrections

Bed thickness correction

Porosity- Resistivity Crossplot (Pickett plot)

tm

w

t

w

t

ow

n

R

Ra

R

RF

R

RS

⋅

⋅=

⋅==

φ

Taking logarithm of above expression:

wwt SnRamR log)log(loglog ⋅−⋅+−= φ

If we have a formation with constant lithology (texture)

index “a” and Rw, then in regions with constant Sw :

.loglog ConstmRt +−= φ

i.e. a log-log plot of Rt versus φφφφ (or vice-versa) will be a

straight line, with slope = m− (cementation factor).

If Sw = 100%, then )log(loglog wt RamR ⋅+−= φ

Another straight line, parallel to other Sw lines. At φ φ φ φ =

100%, )log(log wt RaR ⋅=

Therefore:

Log Rt

Log φ

Slope = m Constant Sw

Log Rt

Log φ

Sw=100%

φ=100%

aRw

Resistivity-Porosity Cross plots

When it is not known that the resistivity values

correspond to 100% water saturation, but aRw is

known, using estimate for m and plotting a point (Rt =

aRw, φφφφ = 100%), draw the line for Sw=100%

Log Rt

Log φ

Points with

unknown Sw

φ=100%

Sw=100%

Assumed m

(Rt=aRw, φ=100%)

Adjusting log values for presence of shale

ShNshNcorrN

ShDshDcorrD

V

V

φφφ

φφφ

⋅−=

⋅−=

Compute corrected porosity as:

2

corrcorr ND φφφ

+=

Then calculate the corrected saturation as:

sh

wShArchiesww

R

RVSS

⋅⋅

⋅−=

φ4.0

This is called Fertl’s correction

Log reading in a shale zone

Log reading in a shale zone