Well logging

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Well logging
Compiled by: P.Eng Mahmoud Jad Mahmoud Jad
http://www.linkedin.com/in/mahmoudjad
https://about.me/ma7moud.jad
Petroleum Engineering
Compiled By: P.Eng. Mahmoud Jad

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 Geology
is the study of the Earth, including the materials That it is made of, the physical and
chemical changes that occur on its surface and in its interior and the history of the
planet and its life form
 Petroleum Geology:
The use of geologic techniques to locate oil reserves and determine methods for
profitable extraction.
is the practical use of all the established and recognized geologic principles in finding
and exploiting petroleum deposits.
 Geophysics:
Geophysics is a branch of the Earth sciences which aims to understand the the
subsurface structure of the Earth using the methods of physics which is important for
both scientific and economic reasons .
1. Gravity Survey Method
Survey Application - Airborne, ground, downhole
Physical Parameter measured - Vector component of gravity field
Source of Anomaly - Density contrast
Depth of Investigation - All
2. Magnetic Survey Method
Physical Parameter measured - Vector component of total magnetic field
Source of Anomaly - Magnetic susceptibility and or remnant magnetisation contrast
Depth of Investigation - All
3. Radiometric Survey Method
Physical Parameter measured - Count rate and Energy level of recieved gamma ray
photons
Source of Anomaly - K, Th and U contrast
Depth of Investigation - Upper 25 cm
4. Electromagnetics Survey Method - many variations available
Physical Parameter measured - Dependent on method; Vector component of
magnetic field (B Field), time derivative of magnetic field (dB/dt), ratio of received
to applied electric and magnetic fields, total magnetic field
Source of Anomaly - Lateral or vertical changes in Earth conductivity. Requires a
target with a high absolute conductivity.
Depth of Investigation - Highly dependent on frequency. Shallow (VLF - 10m,
controlled source –300m), intermediate (AMT – 1km), deep (MT-10km)
5. MagnetoMetric Resistivity Survey Method
Survey Application - Ground and downhole
Physical Parameter measured - Vector Component of Magnetic field
Source of Anomaly - Lateral or vertical changes in Earth conductivity. Only requires
a target with a conductivity contrast rather than one with a high absolute
conductivity.
Depth of Investigation - A few hundred metres

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6. Sub-Audio Magnetic Survey Method
Survey Application - Ground
Physical Parameter measured - Total Magnetic Intensity (TMI), Total Field
MagnetoMetric Resistivity (TFMMR)
Source of Anomaly - Relative conductor
Depth of Investigation - 50m
 Well Logging
is the technique of making petrophysical measurements in the sub-surface earth
formations through the drilled borehole in order to determine both the physical and
chemical properties of rocks and the fluids they contain.
Well Logging measurements can:
•Ascertain hydrocarbon potential of the well
•Determine hydrocarbon type and volume
•Determine what types of fluid will flow and at what rate
•Optimize well construction and hydrocarbon production
Well Logging finally serves to:
•Identify Hydrocarbon Reservoirs
•Define Total and Recoverable Reserves
WELL LOGGING TECHNIQUES
•Well Logging Measurements are carried out through the drilled borehole
•The drilled borehole may be either an Open Hole or a Cased Hole
•Open Hole:
A borehole drilled in the formation, usually available immediately after drilling
–All basic petrophysical measurements for Formation Evaluation
•Cased Hole:
A borehole wherein steel casing pipes have been placed and cemented suitably
–Measurements mostly concern with Reservoir Development & Production
 Basic Well Logging Equipments
•Logging Unit
–A specialized truck installed with a full computer system for data acquisition &
processing
•Logging cable or the Wireline
–An electro-mechanical cable reel mounted on the truck and operated by the truck
hydraulics
•Logging Tool or Sonde
–An electronic instrument containing sensors and processing circuitry for data
acquisition and transmission
The logging tool is lowered into the wellbore by means of the logging cable or
wireline. The wireline also connects the logging tool electrically to the surface
computer system. Data acquired by the tool are transmitted to the surface system
over the logging cable using digital telemetry. The surface computer records,
processes and plots these data as a function of well depth and produces what is
called a “log” or “well log.”
This is normally called the Wireline Logging Technique.

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 Definition: Well logs
 Well log is a continuous record of measurement made in bore hole respond to variation in some physical
properties of rocks through which the bore hole is drilled.
 Well logs are primarily tools for petrophysical analyses to determine (a) reservoir rocks, (b) their fluid
content (water, oil and gas) and (c) their reservoir properties (porososity, permeability).
 Well logs reflect indirectly the lithology of the subsurface rocks and must be interpreted in terms of
sandstone, shale, carbonate, coal, etc.
 Well log patterns, trends and abrupt changes indicate change in the stratigraphic succession, facies and
boundaries.
 The Field Operation
 Wireline electrical logging is done from a logging truck, sometimes referred to as a "mobile
laboratory"
The truck carries the downhole measurement instruments, the electrical cable and winch needed
to lower the instruments into the borehole, the surface instrumentation needed to power the
downhole instruments and to receive and process their signals and equipment needed to make a
permanent recording of the log.
 Creating the Well Log "Logging Operation''
1. Log Data Acquisition
With digital telemetry
The use of digitized signals also facilitates the
transmission of log signals by radio, or
satellite , or telephone line to computer
centers or base offices.
2. Data Transmission
With the LOGNET communications network,
graphic data or log transmitted via Satellite
from the well site to multiple locations.
A small transportable communications
antenna at the wellsite permits transmission
of well log data via satellite to a computing
center.
3. Data Processing
* Signal processing can be performed on
three levels;
1-Downhole in the tools
2-Up-hole in the truck
3-Central computing office
* Sometime the logging tool is designed to
process data downhole and transmitted to
the surface.
* The computer center offers a more powerful computers, expert log analysts, more time and the
integration of more data, ex. Schlumberger computer centers

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 Compositions of the Uphole- Downhole lnstruments
 Uphole Instruments include the Logging Truck and the Rig.
The logging Truck mainly consists of mechanical Winches and ordinary driving machine.
 Downhole Instruments are represented by Cables and Sondes.
 Sondes
 Sondes differ in function from measurement to another based on the required physical property to be
measured (GR , Resistivity, Neutron, Sonic, Density, Magnetic, Thermal, etc).
 The Sonde consists of two parts:
1. Sensor: It is an electronically complicated part used for picking the required property. It is usually
shielded with fibers in the modern tools.
2. Cartridge: Surrounding the sensor in the modern tools and do three functions:
i. Powering the sensor to be ON/OFF.
ii. Processing the acquired data (First step of processing).
iii. Data transmission along cables to the up-hole instruments.
 Logging units
Logging service companies utilize a variety of logging units, depending on the location (onshore or offshore) and
requirements of the logging run. Each unit will contain the following components:
logging cable
winch to raise and lower the cable in the well self-contained 120-volt AC generator
set of surface control panels
set of down hole tools (sondes and cartridges) digital recording system
Resistivity is the physical property of a formation
which impedes the flow of electric current.
Importance of Geophysical
Well Logging
• Zone correlation
• Structure and Isopach mapping
• Defining physical rock characteristics:
– Lithology
– Porosity
– Pore geometry
– Permeability
• Identification of productive zones
• Determination of depth and thickness of zones
• Distinguish between oil, gas and water
• Estimation of hydrocarbon reserves
• Determination of facies relationships

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USES OF LOGS
A set of logs run on a well will usually mean different things to different
people. Let us examine the questions asked–and/or answers sought
by a variety of people.
The Geologist:
The Geologist may ask:
'' What depths are the formation tops?
'' Is the environment suitable for accumulation of Hydrocarbons?
'' Is there evidence of Hydrocarbon in this well?
'' What type of Hydrocarbon?
'' Are Hydrocarbons present in commercial quantities?
'' How good a well is ti?
'' What are the reserves?
'' Could the formation be commercial in an offset well?
The Geophysicist:
As a Geophysicist what do you look for?
'' Are the tops where you predicted?
'' Are the potential zones porous as you have assumed from seismic data?
'' What does a synthetic seismic section show?
The Drilling Engineer:
" What is the hole volume for cementing?
" Are there any Key-Seats or severe Dog-legs in the well?
" Where can you get a good packer seat for testing?
" Where is the best place to set a Whipstock?
The Reservoir Engineer:
The Reservoir Engineer needs to know:
" How thick is the pay zone?
" How Homogeneous is the section?
" What is the volume of Hydrocarbon per cubic metre?
" Will the well pay-out?
" How long will it take?
The Production Engineer:
The Production Engineer is more concerned with:
" Where should the well be completed (in what zone(s))?
" What kind of production rate can be expected?
" Will there be any water production?
" How should the well be completed?
" Is the potential pay zone hydraulically isolated?
Table 1.3 Questions answered by well logs, according to someone trying to sell a well log
interpretation course.

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Drilling fluid invasion
 During drilling, Mud is pumped down the drill string forcing the
rock cuttings up to the surface. These cuttings are analyzed for
indications of oil or gas.
 Hydrostatic pressure of the mud column is usually greater than
the pore pressure of the formations
 Because of the differential pressure ,the liquid component of the
drilling fluid (known as the mud filtrate continues to "invade" the
porous and permeable formation
 The mud filtrate displaces some or all of the moveable fluids in the
formation, leaving an invaded zone. until the solids present in the
mud, commonly bentonite, clog enough pores to form a mud cake
 Mud cake usually has a very low permeability (10-2
-10-4
md) and, once developed, considerably reduces
the rate of further mud filtrate invasion/ infiltration.
Establishment of a–Flushed zone–Transition zone or Annulus–Non-invaded, virgin or
uncontaminated zone
o Very close to the borehole most of the original formation water and some of the hydrocarbons
may be flushed away by the filtrate. This zone is referred to as the flushed zone.
It contains, if the flushing is complete, only mud filtrate; if the formation was originally
hydrocarbon bearing, only residual hydrocarbons.
o Sometimes in oil- and gas-bearing formations, where the mobility of the hydrocarbons is greater
than that of the water because of relative permeability differences, the oil or gas moves away
faster than the interstitial water.
In this case, there may be formed between the flushed zone and the uninvaded zone an annular
zone with a high formation water saturation
Flushed zone
The volume close to the borehole wall in which all of the moveable fluids have been displaced by mud
filtrate. The flushed zone contains filtrate and the remaining hydrocarbons, the percentage of the former
being the flushed-zone water saturation, Sxo. In simple models, the flushed zone and the invaded zone
are synonymous.
Invaded zone
#the volume close to the borehole wall in which some or all of the moveable fluids have been displaced by
mud filtrate. # It consists of the flushed zone and the transition zone or annulus. (Sro= 1 –Sxo)
Transition zone
The volume between the flushed zone and the undisturbed zone in which the mud filtrate has only
partially displaced the moveable formation fluids. One common model of invasion assumes a smooth
transition in resistivity and other formation properties from the flushed to the undisturbed zone.
Undisturbed zone
The part of the formation that has not been affected by invasion.
It is also called virgin zone. # non-invaded zone resistivity; Rt
Pores contain formation waters, oil and/or gas.
Invasion depth
 Equal
 The radial depth from the well bore to the outer limit of invasion. Usually measured in inches.
 depends on factors such as 1- mud properties/quality 2-permeability 3-porosity 4-differential pressure.

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Annulus
(1) That space between a drill pipe and the formations through
which the drilling fluid (mud) returns to the surface.
(2) The space between tubing and casing or between casing and
formation.
(3) A ring of interstitial water produced by invasion processes in
hydrocarbon-bearing beds when both hydrocarbon and
interstitial water phases have mobility and their mobilities are
different.
When Rxo > Ro the annulus will be more conductive than the
flushed zone (Rxo) or the uninvaded oil-bearing zone (Rt).
When Rxo <Ro, the resistivity of the annulus will be intermediate
between that of the flushed zone (Rxo) and the uninvaded oil-
bearing zone (Rt).
Notes:
 Mud cake is the sealing agent which slows down invasion. As a result, high permeability zones which
allow quick buildup of mud cake, invade the least and low permeability zones invade the most or
deepest. Non-permeable zones are not invaded.
 The radial profile from the wellbore out to the undisturbed zone depends on permeability, with lower
permeabilities leading to sharper transitions.
 Mud cake formation more efficient in porous rocks, causing less deep penetration of mud filtrate in
porous rocks.
Drilling mud functions:
 Remove cuttings
 Lubricate and cool drill bit
 Maintain excess borehole pressure over formation pressure
•Mud filtrate into formation
•Build up of mud cake on borehole walls
 Drilling mud (Rm), mud cake(Rmc) and mud filtrate (Rmf) resistivities are recorded and used
in interpretations

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The borehole environment and symbols used in log interpretation
dh = hole diameter
di = diameter of invaded zone (inner boundary of flushed zone)
dj = diameter of invaded zone (outer boundary of invaded zone)
rj = radius of invaded zone (outer boundary)
hmc = thickness of mud cake
Rm = resistivity of the drilling mud
Rmc = resistivity of the mud cake
Rmf = resistivity of mud filtrate
Rs = resistivity of the overlying bed (commonly assumed to be shale)
Rt = resistivity of uninvaded zone (true formation resistivity)
Rw = resistivity of formation water
Rxo = resistivity of flushed zone
Sw = water saturation of uninvaded zone
Sxo = water saturation flushed zone

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12 ASQUITH AND KRYGOWSKI
Distance from the borehole
di djhmc
borehole wall
di djhmc
borehole wall
di djhmc
borehole wall
Rxo
Ro
Rxo
Ro
Rxo
Ro
Rt
Ri
Ri
Step Profile
Transition Profile
Annulus Profile
ResistivityResistivityResistivity
Figure 1.3. Resistivity profiles for three idealized versions of fluid distributions in
the vicinity of the borehole. As mud filtrate (Rmf) moves into a porous and permeable
formation, it can invade the formation in several different ways. Various fluid
distributions are represented by the step, transition, or annulus profiles. All three profiles
illustrate the effect of a freshwater mud; for profiles using saltwater mud see figures
1.4 and 1.5. Mud cake thickness is indicated by hmc.
Step profile:
This idealized model is the one inferred by the use of three resistivity logs to esti-
mate invasion. Mud filtrate is distributed with a cylindrical shape around the borehole
and creates an invaded zone. The cylindrical invaded zone is characterized by its abrupt
contact with the uninvaded zone. The diameter of the cylinder is represented as dj. In
the invaded zone, pores are filled with mud filtrate (Rmf); pores in the uninvaded zone
are filled with formation water (Rw) and hydrocarbons. In this example, the uninvaded
zone is wet (water saturated and no hydrocarbons), thus the resistivity beyond the
invaded zone is low. The resistivity of the invaded zone is Rxo, and the resistivity of the
uninvaded zone is Rt (where Rt reduces to Ro when the formation is water bearing).
Transition profile:
This is the most realistic model of true borehole conditions. Here again invasion is
cylindrical, but in this profile, the invasion of the mud filtrate (Rmf) diminishes gradually,
rather than abruptly, through a transition zone toward the outer boundary of the invad-
ed zone (see dj on diagram for location of outer boundary).
In the flushed part (Rxo) of the invaded zone, pores are filled with mud filtrate
(Rmf), giving a high resistivity reading. In the transition part of the invaded zone, pores
are filled with mud filtrate (Rmf), formation water (Rw), and, if present, residual hydro-
carbons. Beyond the outer boundary of the invaded zone, pores are filled with either
formation water or formation water and hydrocarbons. In this diagram, hydrocarbons
are not present, so resistivity of the uninvaded zone is low. The resistivity of the invad-
ed zone is Rxo, and the resistivity of the uninvaded zone is Rt (where Rt reduces to Ro
when the formation is water bearing).
Annulus profile:
This reflects a temporary fluid distribution and is a condition that should disappear
with time (if the logging operation is delayed, it might not be recorded on the logs at
all). The annulus profile represents a fluid distribution that occurs between the invaded
zone and the uninvaded zone and only exists in the presence of hydrocarbons.
In the flushed part (Rxo) of the invaded zone, pores are filled with both mud fil-
trate (Rmf) and residual hydrocarbons. Thus the resistivity reads high. Pores beyond the
flushed part of the invaded zone (Ri) are filled with a mixture of mud filtrate (Rmf), for-
mation water (Rw), and residual hydrocarbons.
Beyond the outer boundary of the invaded zone is the annulus zone, where pores
are filled with formation water (Rw) and residual hydrocarbons. When an annulus pro-
file is present, there is an abrupt drop in measured resistivity at the outer boundary of
the invaded zone. The abrupt resistivity drop is due to the high concentration of forma-
tion water (Rw) in the annulus zone. Formation water has been pushed ahead by the
invading mud filtrate into the annulus zone. This causes a temporary absence of hydro-
carbons, which have been pushed ahead of the formation water.
Beyond the annulus is the uninvaded zone, where pores are filled with formation
water (Rw) and hydrocarbons. The resistivity of the invaded zone is Rxo, and the resis-
tivity of the uninvaded zone is Rt (where Rt reduces to Ro when the formation is water
bearing).
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Basic Relationships of Well Log Interpretation 13
Figure 1.4. Resistivity profile for a transition-style
invasion of a water-bearing formation.
Note: These examples are shown because freshwater
muds and saltwater muds are used in different geographic
regions, usually exclusively. The geologist needs to be
aware that a difference exists. To find out which mud is
used in your area, check the log heading of existing wells
or ask your drilling engineer. The type of mud used affects
the log package selected, as will be shown in later
chapters.
Freshwater muds:
The resistivity of the mud filtrate (Rmf) is greater
than the resistivity of the formation water (Rw)
(remember, saltwater is conductive). A general rule when
freshwater muds are used is: Rmf > 3 Rw. The flushed
zone (Rxo), which has a greater amount of mud filtrate,
has higher resistivities. Away from the borehole, the
resistivity of the invaded zone (Ri) decreases due to the
decreasing amount of mud filtrate (Rmf) and the
increasing amount of formation water (Rw).
With a water-bearing formation, the resistivity of the
uninvaded zone is low because the pores are filled with
formation water (Rw). In the uninvaded zone, true
resistivity (Rt) is equal to wet resistivity (Ro) because the
formation is completely saturated with formation water
(Rt = Ro where the formation is completely saturated with
formation water).
To summarize: in a water-bearing zone, the
resistivity of the flushed zone (Rxo) is greater than the
resistivity of the invaded zone (Ri), which in turn has a
greater resistivity than the uninvaded zone (Rt).
Therefore: Rxo> Ri > Rt in water-bearing zones.
Saltwater muds:
Because the resistivity of mud filtrate (Rmf) is
approximately equal to the resistivity of formation water
(Rmf ~ Rw), there is no appreciable difference in the
resistivity from the flushed (Rxo) to the invaded zone (Ri)
to the uninvaded zone (Rxo = Ri = Rt); all have low
resistivities.
Both the above examples assume that the water
saturation of the uninvaded zone is much greater than
60%.
ResistivityResistivity
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14 ASQUITH AND KRYGOWSKI
Figure 1.5. Resistivity profile for a transition-style invasion
of a hydrocarbon-bearing formation.
Freshwater muds:
Because the resistivities of both the mud filtrate (Rmf) and
residual hydrocarbons are much greater than formation water
(Rw), the resistivity of the flushed zone (Rxo) is comparatively
high (remember that the flushed zone has mud filtrate and
some residual hydrocarbons).
Beyond its flushed part (Rxo), the invaded zone (Ri) has
a mixture of mud filtrate (Rmf), formation water (Rw), and
some residual hydrocarbons. Such a mixture causes high
resistivities. In some cases, resistivity of the invaded zone (Ri)
almost equals that of the flushed zone (Rxo).
The presence of hydrocarbons in the uninvaded zone
causes higher resistivity than if the zone had only formation
water (Rw), because hydrocarbons are more resistant than
formation water. In such a case, Rt > Ro. The resistivity of the
uninvaded zone (Rt) is normally somewhat less than the
resistivity of the flushed and invaded zones (Rxo and Ri).
However, sometimes when an annulus profile is present, the
invaded zone’s resistivity (Ri) can be slightly lower than the
uninvaded zone’s resistivity (Rt).
To summarize: Rxo > Ri > Rt or Rxo > Ri < Rt in
hydrocarbon-bearing zones.
Saltwater muds:
Because the resistivity of the mud filtrate (Rmf) is
approximately equal to the resistivity of formation water
(Rmf ~ Rw), and the amount of residual hydrocarbons is low,
the resistivity of the flushed zone (Rxo) is low.
Away from the borehole, as more hydrocarbons mix with
mud filtrate in the invaded zone the resistivity of the invaded
zone (Ri) increases.
Resistivity of the uninvaded zone (Rt) is much greater
than if the formation were completely water saturated (Ro)
because hydrocarbons are more resistant than saltwater.
Resistivity of the uninvaded zone (Rt) is greater than the
resistivity of the invaded (Ri) zone. So, Rt > Ri > Rxo. Both the
above examples assume that the water saturation of the
uninvaded zone is much less than 60%.
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Resistivity
 The electrical resistivity of a substance is its ability to impede the flow of electrical current through
the substance. #the unit used in logging is ohm-m.
 Electrical conductivity is the reciprocal of resistivity and is expressed in milliohms per meter
(mmho/m).
 Resistance depends on size and shape
 Hydrocarbons , rock and freshwater are highly resistive
 Salt water is highly conductive.
Symbol R, measured in Ω·m(ohm·m2/m)
•With r = resistance; A = area of substance being measured; L = length of substance
•Resistivity is a basic measurement of a reservoir’s fluid saturation and is a function of porosity, type of
fluid, amount of fluid and type of rock
 Most formations logged for potential oil and gas saturation are made up of rocks which, when
dry, will not conduct an electrical current; i.e., the rock matrix has zero conductivity or infinitely
high resistivity. An electrical current will flow only through the interstitial water saturating the
pore structure of the formation, and then only if the interstitial water contains dissolved salts.
 Resistivity measurements are essential for saturation determinations - particularly saturation
determinations in the Virgin, noninvaded portion of the reservoir.
Resistivity measurements arc employed, singly and in combination, to determine formation
resistivity in the noninvaded formation (called true resistivity, Rt). Resistivity measurements are
also used to determine the resistivity close to the borehole (called flushed-zone resistivity, Rx0),
where mud filtrate has largely replaced the original pore fluids. Resistivity measurements, along
with porosity and water are used to obtain values of sw.
 Formation water, sometimes called connate water or interstitial water, is the water,
uncontaminated by drilling mud, that saturates the porous formation rock .
The resistivity of this formation water, Rw is an important interpretation parameter since it is
required for the calculation of saturations (water and/ or hydrocarbon) from basic resistivity
logs.
Formation Factor and Porosity
Archie's Law
The rock matrix is considered a perfect insulator; i.e. conducts no electricity
Therefore all conduction via fluid in pores !!
Water-bearing formations therefore tend to have high electrical conductivity or low resistivity
Electrical current that does flow is forced to make a tortuous path, weaving around the hydrocarbon that
occupies the larger pore spaces.
So basis of logging is to compare the actual resistivity with the resistivity that would be expected is all the
pore spaces contained water.
If measured resistivity is significantly higher than the calculated resistivity, the presence of hydrocarbons is
inferred.
Definition of Rw
Rw is the resistivity of the formation water, in units of ohm-metres .
This resistivity is an intrinsic property of the water and is a function of its
salinity and temperature.

The higher these two variables, the more conductive the water will be and the lower its resistivity.
Definition of R0
Ro is the resistivity of the water-bearing formation.
It will be larger than Rw.
R0 is the resistivity of a non-shaly formation rock 100% saturated with
brine of resistivity Rw,
Definition of Rt
Rt is the resistivity of the oil-bearing formation.
It will be greater than Ro
Formation Factor, F
The resistivity Ro, is proportional to Rw, since only the water conducts. Thus: Ro = F. Rw
The proportionality constant F is termed the Formation (resistivity) Factor. F =Ro/Rw
Archie proposed a formula relating porosity,& and formation factor, F; the relationship is
•Tortuosity factor (a), 0.62-2.45
•Cementation factor/Exponent (m), 1.0-2.15
•Rw= Resistivity of the formation water
•Rt= Resistivity of a rock with HC, i.e. true resistivity
•Ro= Resistivityofthe100% water-saturated rock•
When = 1 (all water, no matrix), R0 must equal Rw;
When = 0 (no pre water, solid matrix), R0 must be infinite since the rock itself is an insulator.
The equation satisfies these conditions regardless of the value of m, which is termed the Cementation
Exponent.
 The resistivity of a clean, water-bearing formation (i.e., one containing no appreciable
amount of clay and no hydrocarbons) is proportional to the resistivity of the brine with
which it is fully saturated.
 For a given porosity, the ratio R0/Rw remains nearly constant for all values of Rw below
about 1 ohm-m.
The value of m reflects the tortuosity of current flow through the maze of rock pores .
If the pore space consisted of cylindrical tubes through an otherwise solid matrix, current flow
would be straight and m would be 1.0.
In the case of porous formations, measurements have shown me 2 on average .
Accepted relations for the range of porosities encountered in logging are :
Formation factor:
 'geochemistry' The ratio of the resistivity of a rock filled with water (Ro) to the
resistivity of that water (Rw). Also known as resistivity factor.
 'geology' A function of the porosity and internal geometry of a reservoir rock system,
expressed as F = a -m
 Formation factor is a function of porosity and pore geometry.

The first relationship is popularly referred to as the Humble formula;
the second, as the Archie formation factor relationship
Water Saturation
Knowing Ro and Rt, water saturation, Sw, the fraction of pore space containing water, can be calculated.
General principles must be relation of the form:
Because when Sw= 1 (all water in the pores), Rt must equal R0;
when Sw= 0 (all oil in the pores, if it were possible), Rt must be infinite, as both oil and rock are insulators .
These conditions are satisfied regardless of the value of exponent n.
. Lab experiments have shown n=2 in the average case.
This relation can be sued directly to calculate the water saturation of a hydrocarbon-bearing zone when an obvious
water-bearing zone of the same porosity and having water of the same salinity is nearby.
An example would be a thick sand with an obvious water-oil contact in the middle.
In general there will not be a nearby water sand to give Ro, There by replacing Ro by Ro= F . Rw and F = 1/ 2
It is a purely empirical law attempting to describe ion flow (mostly sodium and chloride) in clean, consolidated sands,
with varying intergranular porosity. Electrical conduction is assumed not to be present within the rock grains or in
fluids other than water.
Archie's law is named after Gus Archie (1907–1978) who developed this empirical quantitative relationship between
porosity, electrical conductivity, and brine saturation of rocks. Archie's law laid the foundation for modern well log
interpretation as it relates borehole electrical conductivity measurements to hydrocarbon saturations (which, for fluid
saturated rock, equals 1-Sw
Where C= 1 for carbonates and 0.9 for sands constant "c" equivalent to "a" tortuosity factor. # n: Saturation exponent.
Tortuosity
 A measure of the geometric complexity of a porous medium.
 Tortuosity is a ratio that characterizes the convoluted pathways of fluid diffusion and electrical
conduction through porous media.
 In the fluid mechanics of porous media, tortuosity is the ratio of the length of a streamline—a flow line
or path—between two points to the straight-line distance between those points.
 A measure of deviation from a straight line. It is the ratio of the actual distance traveled between two
points, including any curves encountered, divided by the straight line distance.
 Tortuosity is used by drillers to describe wellbore trajectory, by log analysts to describe electrical current
flow through rock and by geologists to describe pore systems in rock and the meander of rivers.
Archie Equation for Water Saturation

15
ARCHIE Equations
Water bearing reservoir
In a clean water bearing reservoir, all the pore space is filled with
formation water. The matrix is an electrical insulator. The only
conductor present is the formation water. Its resistivity (Rw)
depends on the concentration of salts dissolved in the water and the
temperature of the reservoir.
The total resistivity of a water bearing formation (Ro) depends on
the resistivity of the water (Rw), the amount of water present (equal
to Ø) and the shape of the water body (expressed by the
cementation factor: m).
Ro = Rw • Ø -m
This is the first Archie equation. The cementation factor, depends on
the shape of the pore space. m is reasonably constant within
granular rocks, independent of Ø. It ‘s value can be measured on
core plugs, deduced from various combinations of logs or estimated
for the described rock type.
For quick look evaluations use the following m values, if no other
accurate estimate is available: Sandstone: m = 1.8
Carbonate: m = 2.0
HC bearing reservoir
In a hydrocarbon bearing reservoir part of the water is replaced by oil
or gas, which are also electrical insulators. If the rock is water-wet,
the HC is accumulated in the centre of the pore spaces. The
remaining water coats the grain surfaces. Electrical current can still
travel through the reservoir, along the water layer around the grains.
The total resistivity of the reservoir (Rt) can be orders of magnitude
higher than the Ro of a similar water bearing formation, because the
volume and the connectivity of the conductor (water) is smaller.
Therefore, in addition to the parameters of the first Archie equation,
the total resistivity also depends on the water saturation (Sw =
fraction of the Ø which is filled with water) and the geometry of the
water coating the grains (expressed
by the saturation exponent: n).
Rt = Rw • Ø -m
• Sw-n
This is the second Archie equation.
Similar to m, n is often constant
within a particular rock, independent
of Sw. It ‘s value can be measured on core plugs or estimated for the
described rock type. For quick look purposes n is often assumed
equal to m.
Evaluation objective
Calculation of the water saturation (Sw).
= Matrix = Water = Hydrocarbon

Spontaneous Potential (SP) Log
The SP Curve
 The SP curve is a continuous recording (versus depth) of
the difference in potential between a movable electrode in
the borehole and a fixed (zero) potential surface electrode.
 Units used are millivolts.
 The SP curve records the electrical potential (voltage)
produced by the interaction of formation connate water,
conductive drilling fluid and certain ion-selective rocks
(shale).
 The spontaneous potential log, commonly called the self-
potential log or SP log.
Measurement Tools
 The tool is extremely simple, consisting of a single
electrode that is connected to a good surface earthing
point via a galvanometer for the measurement of DC
potential. A small 1.5 V battery is also included
commonly to ensure that the overall signal is measured
on the correct scale.
 The simplicity of the log means that it is extremely
cheap, and therefore gives tremendous value for
money.
 Only relative changes in potential are measured
because the absolute value of the SP is meaningless.
 Changes of the order of 50 mV are typical. For the log
to be good, a good earth is necessary, which is often a metal spike driven 1 m into the
ground.
The SP curve is a recording versus depth of the difference between the electrical potential of a
movable electrode in the borehole and the electrical potential of a fixed surface electrode.
 An SP curve cannot be recorded in holes filled with nonconductive muds because such muds do not provide
electrical continuity between the SP electrode and the formation.
 Furthermore, if the resistivities of the mud filtrate and formation water are about equal, the SP deflections will
be small and the curve will be rather featureless.
 The position of the shale baseline on the log has no useful meaning for interpretation purposes. The SP sensitivity
scale is chosen and the shale baseline position is set by the engineer running the log so that the curve deflections
remain in the SP track. The SP log is measured in millivolts (mV).

There are three requirements for the existence of an SP current:
• A conductive borehole fluid (i.e., a water based mud).
• A sandwich of a porous and permeable bed between low porosity and impermeable formations.
• A difference in salinity between the borehole fluid and the formation fluid, which are the mud filtrate and
the formation fluid in most cases. Note, however, that in some special cases an SP current can be set-up when
there is no difference in salinity, but where a difference in fluid pressures occurs.
Origin of SP
• The deflections on the SP curve result from electric currents flowing in the mud in the borehole.
• These SP currents are caused by electromotive forces in the formations, which are of electrochemical and
electrokinetic origins.
1 . Electrokinetic Potential
• If a solution is forced by differential pressure to
flow through a membrane, an electrical
potential will appear across the membrane.
• A similar situation occurs when the mud filtrate
flows through the mud cake because of the
differential pressure between the mud column
and the formation.
• This electrokinetic potential (Ekmc) is generally
small.
2. Electrochemical Component of the SP
• This potential is created by the contact of two solutions of different salinity, either by a
direct contact or through a semipermeable membrane such as shales.
• These electrochemical factors are brought about by differences in salinities between mud
filtrate (Rmf) and formation water resistivity (Rw) within permeable beds.
• It consists of two different potentials which are
1 . Membrane Potential
2. Liquid Junction Potential

1. Membrane Potential
 Shales are ideal membranes as long as they are not too sandy or too
limy.
 In a borehole, a shale section usually separates salty water
(generally the connate water of the virgin zone) from a less salty
liquid (generally the mud) (Figure).
 There is migration at the positive ions (Na+) from the salty water
(formation) to the less salty water (mud).
 When an equilibrium is reached:
o Positive ions that have already crossed the shale membrane exert
a repelling force on the positive ions in the mud.
o Negative ions left behind in the formation exert an attractive
force on the positive ions which cannot travel any more into the
shale.
 The difference of potential appearing between the two solutions is given by the formula:
where
Rmf and Rw are the electro-chemical activities of mud filtrate and connate water, respectively.
2) Liquid Junction Potential
 The liquid junction potential takes place at the boundary between the flushed zone and the
virgin Zone. There is no shale separating the two solutions.
 Anions as well as cations can transfer from one solution to the other (Figure) because of
the higher salinity of the formation water and both Na+ cations and Cl- anions will migrate
toward the mud filtrate.
 The Na+ ion is comparatively
large and drags 4.5 molecules of
water.
 The C': ion is smaller and drags
only 2.5 molecules of water:
 Hence, the anion Cl- will migrate
more easily than the Na+ ions.
 The result is an increase of
positive charges left behind in the formation water. These positive charges restrict Cl-
migration toward the flushed zone.
 A difference of potential appears at the boundary
between the two solutions:
Original Conditions
Dynamic Conditions

 The total potential of the whole chain is thus the algebraic sum Em+ Ej, which is also called
the Static Spontaneous Potential (SSP). Electrokinetic potential is neglected.
 The SP is the drop of potential measured across the current lines in the borehole.
 The magnitude of SP deflections is always measured from
the shale line and for a clean, water-bearing formation
containing a dilute sodium chloride solution is given by
 The constant K depends on the temperature and salt types in formation water (K = 71 at 2
S°C for NaCl).
 Along its path the SSP current has to force
its way through a series of resistances,
both in the formation and in the mud.
 This means that the total potential drop
(which is equal to the SSP) is divided
between the different formations and mud
in proportion to the resistances met by the
current in each respective medium. The SP,
which is the measure of the potential drop
in the mud of the borehole, is only part of
the SSP.
 In general, It is a large portion because the
electrical resistance offered by the
borehole is, in general, much greater than
that offered by the formations.

 Opposite shales the SP curve usually
defines a more-or-less straight line on
the log, called the shale baseline.
 Opposite permeable formations, the
curve shows excursions from the shale
baseline; in thick beds, these excursions
(deflections) tend to reach an essentially
constant deflection defining a sand line.
 The SP is reduced by the shale in a shaly zone, and the deflection
is called the pseuostatic spontaneous potential (PSP).
 The ratio of these two values, termed a = PSP /SSP, can be used as
a shale indicator in sands.
 An approximation of the SSP in a shaly sand is SSP = PSP I (1 -
V5h),
 where the volume of shale (V5h) is estimated from the gamma
ray deflection.
 The SP response in shales is relatively constant and its continuity of amplitude is referred to as the
shale baseline.
 In permeable beds the SP will do the following relative to the shale baseline:
o negative deflection to the left of the shale baseline where Rmf ＞ Rw ;
o positive deflection to the right of the shale baseline where Rmf ＜ Rw ;
o no deflection where Rmf ＝ Rw .
SSP:
–StaticSpontaneousPotential
–MaximumSP that a thick, shale-free, porousand permeable
formation can have for a given ratio between Rmf and Rw
–Determined by formula or by chart
–Necessary for determining accurate valueso f Rw and volume of shale
SSP: Max deflection possible for given Rmf/Rw
SP. SP response due to presence of thins beds and/or gas
presence
PSP. Pseudostatic SP; SP when shale is present

Uses of SP
The SP can be used to:
1. Identify permeable bed boundaries (a qualitative indication only),
2. Identify impermeable zones such as shale, and permeable zones such as sand.
3. Determine Rw, formation water resistivity,
4. Give an indication of zone shale content
"Estimation of shale content Vsh for shaly sand formations."
5. Indicate depositional environment.
6. Stratigraphic correlations??
7. Detect boundaries of permeable beds.
8. An auxiliary use of the SP curve is in the detection of hydrocarbons by the suppression
of the SP response.
Factors Affecting the SP
1. Bed thickness: SP decreases when bed thickness decreases.
2. Invasion: Reduces SP.
3. Shaliness: Shale reduces SP.
4. Hydrocarbons: Hydrocarbons in slightly shaly formations reduce the SSP.
5. Mud filtrate: The magnitude and direction of SP deflection from the shale baseline
depends on relative resistivities of the mud filtrate and the formation water.
6. Fresh mud: negative SP (Figure), Rmf >> Rw,
7. Saline mud: positive SP (Figure), Rw <<Rrnf
8. Rw = Rmf: zero SP (Figure).

Depth of Investigation and Vertical Resolution
Depth of investigation of the SP tool is at the junction of the invaded and virgin zones.
Depending upon the diameter of invasion this can vary between only 2- 3 inches if highly
permeable and more than 2-3 feet if permeability is low.
Vertical resolution of the SP tool is approximately 3 meters
Limitations:
1. Borehole mud must be conductive.( it cannot be used in non-conductive (i.e. oil-based)
drilling muds.)
2. Formation water must be water bearing and conductive.
3. A sequence of permeable and non-permeable zones must exist.
4. Small deflection occurs if Rmf=Rw
5. Not fully developed in front of thin beds.
6. 6.The SP log is difficult to run offshore because
i. a good earth is difficult to find, and
ii. The amount of electrical noise on board a rig often causes problems for accurately
measuring signals that commonly change by less than a millivolt.

Resistivity Logs
Conventional Electrical Logs
 Principle
Currents were passed through the formation by
means of current electrodes, and voltages were
measured between measure electrodes.
These measured voltages provided the resistivity
determinations for each device.
In a homogeneous, isotropic formation of infinite
extent, the equipotential surfaces surrounding a
single current-emitting electrode (A) are spheres.
The voltage between an electrode (M) situated on
one of these spheres and one at infinity is
proportional to the resistivity of the homogeneous
formation, and the measured voltage can be scaled
in resistivity units.
# Conductivity is the reciprocal of resistivity and is expressed in mhos per meter.
# Formation resistivities are usually from 0.2 to 1 000 ohm-m. Resistivities higher than 1 000
ohm-m are uncommon in permeable formations but are observed in impervious, very low
porosity (e.g., evaporites) formations.

Normal devices
A current of constant intensity is passed between two
electrodes, A and B.
Electrodes A and M are on the sonde. B and N are,
theoretically, located an infinite distance away.
The resultant potential difference is measured
between two other electrodes, M and N.
The distance AM is called the spacing:
= 16-in. spacing for the short normal,
= 64- in. spacing for the long normal),
and the point of inscription for the measurement is at
o midway between A and M.
Lateral Device
# a constant current is passed between A and B,
and the potential difference between M and N,
located on two concentric spherical equipotential
surfaces centered on A, is measured.
# Thus, the voltage measured is proportional to
the potential gradient between M and N.
# The point of inscription is at 0, midway between
M and N.
# The spacing AO is 18 ft 8 in.
The sonde used in practice differs from that shown
in Figure in that the positions of the current and
measuring electrodes are interchanged.

Normal & Lateral Curves
In the following examples, the shapes of the normal and lateral curves are described for a
few typical cases. All cases correspond to non-invaded formations.
Normal Curves Response
The curves are symmetrical and the apparent bed thickness is greater than actual bed
thickness by an amount equal to the AM spacing.

Lateral Device Response
The Figure illustrate the response of the
lateral device in beds more resistive than
the surrounding formations. Since the usual
lateral spacing is 1 8 ft 8 in., the cases
represented correspond to bed thicknesses
of about 190, 28, and 9 ft. all curves are
dissymmetrical.
For the 190-ft bed, the curve presents a
fairly long plateau readings uninfluenced by
the surrounding formations.
The Figure illustrates the response of the
lateral device in beds less resistive than
the surrounding formations.
The curves are again dissymmetrical. In
both cases, the anomaly extends below
the bed for a distance slightly greater than
the AO spacing.
The Figures also correspond to formations
having moderate resistivities.
In highly- resistive formations, the normal curves are no longer symmetrical.

Focusing Electrode Logs
Introduction
The response of conventional electrical logging systems can be greatly affected by the
borehole and adjacent formations.
These influences are minimized by a family of resistivity tools that uses focusing currents to
control the path taken by the measure current.
These tools are much superior to the ES devices for large Rt/Rm values (salt muds and/or
highly resistive formations) and for large resistivity contrasts with adjacent beds (Rt/Rs or
Rs/Rt).
They are also better for resolution of thin to moderately thick beds. Focusing electrode
systems are available with deep, medium, and shallow depths of investigation.
Devices using this principle have as quantitative applications the determination of Rt and Rxo.
Laterolog 7
The LL 7 device comprises a center electrode, Ao, and
three pairs of electrodes: M1 and M2; M'1 and M'2; and
A1 and A2.
The electrodes of each pair are symmetrically located
with respect to Ao and are electrically connected to
each other by short-circuiting wire.
A constant current, io, is emitted from Ao Through
bucking electrodes, A1 and A2, an adjustable current is
emitted; the bucking current intensity is adjusted
automatically so that the two pairs of monitoring
electrodes, M1 and M2 and M'1 and M'2, are brought
to the same potential.
The potential drop is measured between one of the monitoring electrodes and an electrode at
the surface (i.e., at infinity).
With a constant io current, this potential varies directly with formation resistivity.
Since the potential difference between the M1-M2 pair and the M'1-M'2 pair is maintained at
zero, no current from Ao is flowing in the bore bet. M 1 and M '1 or between M2 and M '2.
Therefore, the current from Ao must penetrate horizontally into the formations.

The "sheet" of io current retains a fairly constant thickness up to a distance from the borehole
somewhat greater than the total length A1~ of the sonde.
The thickness of the io current sheet is approximately 32 in. {distance o1o2), and the length
A1A2 of the sonde is 80 in.
The conventional devices give poor results; the LL 7 curve, in spite of difficult conditions
(Rt/Rm is 5000), shows the bed very clearly and reads close to Rt.
Laterolog 3
The LL3 tool also uses currents from bucking electrodes
to focus the measuring current into a horizontal sheet
penetrating into the formation.
Symmetrically placed on either side of the central Ao
electrode are two very long (about 5-ft) electrodes, A1
and A2, which are shorted to each other. A current, i0,
flows from the A0 electrode, whose potential is fixed.
From
A1 and A2 flows a bucking current, which is automatically
adjusted to maintain A1 and A2 at the potential Ao.
All electrodes of sonde are thus held at the same constant potential. The magnitude of the io
current is then proportional to formation conductivity.
The io current sheet is constrained to the disk-shaped area. The thickness, o1o2, of the current
sheet is usually about 12 in., much thinner than for the LL7 device.
As a result, the LL3 tool had a better vertical resolution and shows more detail than did the LL7
tool. Furthermore, the influences of the borehole and of the invaded zone were slightly less.
Laterolog 8
# the shallow-investigation LLB measurement is recorded with small electrodes on the dual
induction-laterolog sonde.
# The device is similar in principle to the LL7 tool except for its shorter spacings.
# The thickness of the i0 current sheet is 14 in., and the distance between the two bucking
electrodes is somewhat less than 40 in.
The current-return electrode is located a relatively short distance from A0.
The LL8 device gives sharp vertical detail, and the readings are more influenced by the
borehole and the invaded zone than are those of the LL7 and LL3 tools.

Micro-resistivity logs
Micro-resistivity devices:
 Measure the resistivity of the flushed zone and
 Delineate permeable beds by detecting the presence of mud cake.
Measurements of Rxo are important for several reasons.
 When invasion is moderate to deep, knowledge of Rxo allows the deep resistivity
measurement to be corrected to true formation resistivity.
 Also, some methods for computing saturation require the Rx/Rt, ratio.
In clean formations, a value of F can be computed from Rxo and Rmf if Sxo is known or
can be estimated.
Micro-Resistivity Tools (MRT)
 Micro resistivity readings are affected by Mud cake:
The effect depends on mud cake resistivity, Rmc and thickness, hmc.
Moreover, mud cakes can be anisotropic, with mud cake resistivity parallel to the borehole
wall less than that across the mud cake.
Mud cake anisotropy increases the mud cake effect on micro resistivity readings so that
the effective, or electrical, mud cake thickness is greater than that indicated by the caliper.
 Newer micro resistivity equipment includes a microlog tool, and a MicroSFL tool. Mounted
on the powered caliper device
 The microlog can be run simultaneously with any combination of Lithe-Density, CNL, OIL,
NGS, or EPT logging services.
 The MicroSFL tool can also be run in combination with other services. It is most commonly
combined with the DLL or DIL equipment.
 Microresistivity logs are scaled in resistivity units.
Micro-Resistivity Tools (MRT)Applications
 In MSFL mode, the MRT provides excellent high-vertical-resolution, flushed-zone
resistivity (Rxo) measurements necessary for accurate movable hydrocarbon
determination.
 With a pad change, the MRT also can provide a high-quality permeability indication with
a MEL measurement.
Micro-Resistivity Tools (MRT) Features, Advantages and Benefits
1. Measures flushed-zone or invaded-zone resistivity
2. Provides input required to calculate movable hydrocarbons
3. Contributes to invasion profile characterization when combined with other resistivity
tools.

4. Indicates permeability
5. Defines bed boundaries
6. Measures borehole size with caliper measurement
Microlog
 An unfocused electrode device with small spacings, mounted on a pad and pressed against
the borehole wall.
The typical microlog has one current-emitting electrode and two measure electrodes in line
above it, one at 1 in. [2.5 cm], the other at 2 in. [5 cm].
The potential at the 2-in. electrode gives a 2-in. micro normal log.
The difference in potential between the two measure electrodes gives a 1-in. x 1-in. micro
inverse log.
The micronormal reads deeper than the micro inverse.
 Principle
The rubber micro-log pad is pressed against the borehole wall by arms and springs.
The face of the pad has three small inline electrodes spaced 1 in. [2.5 cm] apart.
With these electrodes a 1- by 1-in. micro-inverse (R1'' x R1'') and a 2-in. [5.1 cm]
Micro-normal (R2") measurements are recorded simultaneously.
The currents emitted from these electrodes are totally unfocused and hence flow by the
path of least resistance.

Positive curve separation.
 As drilling fluid filters into the permeable
formations, mud solids accumulate on
the hole wall and form a mud cake.
Usually, the resistivity of the mud cake is
slightly greater than the resistivity of the
mud and considerably lower than the
resistivity of the invaded zone near the
borehole.
 The 2-in. micro-nonnal device has a
greater depth of investigation than the
micro-inverse. It is, therefore, less
influenced by the mud cake and reads a
higher resistivity, which produce positive
curve separation.
 In the presence of low-resistivity mud
cake, both devices measure moderate
resistivities, usually ranging from 2 to 10
times Rm.
 In impervious formations, the two curves
read similarly or exhibit some negative separation. Here the resistivities are usually much
greater than in permeable formations.
The limitations of the method are as follows:
1. The ratio Rxo/Rmc must be less than approximately 15 (porosity more than 15%).
2. The value of hmc must be no greater than 0.5 in. [1.3 cm].
3. Depth of invasion must be greater than 4 in. [10 cm]; otherwise, the microlog readings
are affected by Rt.
 The micro-log is used to detect permeable zones across which a mud cake has formed.
Since the mud cake is usually less resistive than the invaded zone, the micro-inverse will
read less than the micro-normal opposite permeable zones.
 If the resistivity and thickness of the mud cake are known, it is possible to estimate the
resistivity of the flushed zone. The log is usually presented on a linear scale, chosen to
emphasize the lower readings often seen opposite permeable zones with mud cake.
Under favorable circumstances the microlog can be used to obtain Rxo but it is generally
considered a good qualitative indicator of permeability, rather than an Rxo measurement

Microlaterolog
 The microlaterolog tool was designed to determine Rxo accurately for higher values of
Rx0/Rm0 where the microlog interpretation lacks resolution.
 Principle
 A small electrode, Ao, and three concentric circular electrodes are embedded in a
rubber pad applied against the borehole wall. A constant current, io is emitted through
A0.
 Through the outer electrode ring, A1, a varying current is emitted and automatically
adjusted so that the potential difference between the two monitoring electrode rings,
M1 and M2, is maintained essentially equal to zero.
 The current is forced to flow in a beam into the formation. The resulting current lines
are shown on the figure. The io current near the pad forms a narrow beam, which opens
up rapidly a few inches from the face of the pad.
 The microlaterolog resistivity reading is influenced mainly by the formation within this
narrow beam.
Microloq vs. Microlateroloq

Proximity Log
 Principle:
 The Proximity tool is similar in principle to the microlaterolog device.
 The electrodes are mounted on a wider pad, which is applied to the wall of the
borehole; the system is automatically focused by monitoring electrodes.
 Vertical Resolution
 The resolution of the proximity log is about 6 in.
 Corrections for the effect of adjacent beds are unnecessary for bed thicknesses greater
than 1 ft.
Microspherically focused
 The MicroSFL tool is a pad-mounted, spherically-focused logging device that has replaced
the microlatero log and proximity tools.
 It has two distinct advantages over the other Rxo devices.
o The first is its combinability with other logging tools, including the Phasor- Induction
SFL, the AIT (Array Induction lmager and dual latero log tools).
This eliminates the need for a separate logging run to obtain Rxo information.
o The second improvement is in the tool's response to shallow Rxo zones in the
presence of mudcake.
 The chief limitation of the microlatero log measurement was its sensitivity to mud cakes.
When mud cake thickness exceeded about 3/8 in., the log readings were severely
influenced at high Rxo /Rmc contrasts.
 The proximity log, on the other hand, was relatively insensitive to mud cake, but it required
an invaded zone diameter of about 100 cm to provide direct approximations of Rxo .
Determination of Rxo
 Rxo can be determined from the microlatero log or MicroSFL-logs and can sometimes be
derived from the micro log or the Proximity log.
 These pad devices for Rxo determination are sensitive to mud cake effects and borehole
rugosity, but are usually insensitive to bed-thickness effects.
 In the absence of a micro-resistivity measurement, a value of Rxo
may be estimated from the porosity using a formula such as ::::::::>
Using from a porosity log and an estimated value of Sor (residual oil saturation).
 In water-bearing formations, this estimate may be good since Sor can be fairly safely
assumed to be zero.
 In hydrocarbon-bearing formations, any uncertainty in Sor will, of course, be reflected in the
Rxo estimation from Eq. 7-9.
Rxo=
𝟎.𝟔𝟐 𝑹 𝒎𝒇
𝟐.𝟏𝟓(𝟏−𝑺 𝒐𝒓) 𝟐

Induction Log
Introduction
 It was originally developed to measure formation resistivity in boreholes containing oil-
base muds and in air-drilled boreholes.
 The induction log had many advantages over the conventional ES log when used for logging
wells drilled with water-base muds.
 Designed for deep investigation, induction logs can be focused in order to minimize the
influences of the borehole, the surrounding formations, and the invaded zone.
Principle
1. Principle Today's induction tools have
many transmitter and receiver coils.
However, the principle can be understood
by considering a sonde with only one
transmitter coil and one receiver coil.
2. A high-frequency AC of constant intensity
is sent through a transmitter coil.
3. The alternating magnetic field created
induces currents in the formation
surrounding the borehole. These currents
flow in circular ground loops coaxial with
the transmitter coil and create, in turn, a
magnetic field that induces a voltage in
the receiver coil.
4. Since AC is constant frequency and
amplitude, the ground loop currents are directly proportional to the formation
conductivity.
5. The voltage induced in the receiver coil is proportional to the ground loop currents and,
therefore, to the conductivity of the formation.
The induction tool works best when the borehole fluid is an insulator-even air or gas.
The tool also works well when the borehole contains conductive mud unless the mud is too
salty, the formations are too resistive, or the borehole diameter is too large

In brief Induction Log Theory
1. Transmitter coil is excited by an AC current, I of medium
frequency
2. Current induces a primary magnetic field, BP. in the
formation near the wellbore
3. The vertical component of this induced magnetic field,
(Bp)z, generates an electric field, E, which curls around
the vertical axis.
4. This electric field causes a current to flow in the
formation in concentric circles.
5. Current density, J= f(E, C) C=conductivity
6. The current that flows in a ring behaves as a transmitter
coil and develops a secondary magnetic field, Bs
7. Bs is proportional to formation conductivity, and induces
an electric signal, V in the receiver coil.
When to Use an Induction Log?
1. Where fresh mud or oil-base mud (or air-filled holes) is used;
2. Where the Rmf /Rw, ratio is greater than 3;
3. Where Rt is less than 200 ohm-m;
4. Where bed thickness is greater than 20 ft.

Geometrical Factor:
 The tool response can be calculated as the sum of the elementary signals created by all formation
loops coaxial with the sonde.
 Each elementary signal is proportional to the loop conductivity and to a geometrical factor
that is a function of the loop position with reference to the transmitter and receiver coils.
Therefore,
Where
E is the induced electromotive force,
K is the sonde constant,
g is the geometrical factor for that particular loop,
C is the conductivity of that loop,
And ∑ gi=1.
 The geometrical factor, gi, corresponding to a medium is defined as the proportion of the total
conductivity signal contributed by the given medium.
 The formation can be split into cylinders coaxial with the sonde (tool being centralized);
they correspond to the mud column, invaded zone, virgin zone, and shoulder beds.
 The total signal can be expressed by:
Where:
And where G is the geometrical factor for a defined region.
E=K ∑ gi Ci
CI = GmCm + GxoCxo + GtCt + GsCs
Gm + Gxo + Gr + Gs = 1
 Because induction tools are designed to evaluate Rt it is important to minimize terms
relative to the mud, the invaded zone, and the shoulder beds.
 This is done by minimizing the corresponding geometrical factors with a focused signal.

Focusing Signal
 The simple two-coil system does not represent the tool used today. However, it can be
considered the building block from which today's multi-coil sonde was built.
 The response of a multi-coil sonde is obtained by breaking it down into all possible two-coil
combinations of transmitter-receiver pairs.
 The response of each coil pair is weighted by the product of the number of turns on the
two coils and by the product of their cross-sectional area.
 The responses of all coil pairs are added, with due regard to the algebraic sign of their
contributions and their relative positions.
Skin Effect
 In very conductive formations the
induced secondary currents in the
ground loops are large, and their
magnetic fields are important.
 The magnetic fields of these ground
loops induce additional emfs (electrical
voltages) in other ground loops.
 These induced emfs are out of phase
with those induced by the transmitter
coil of the induction tool.
 This interaction between the ground
loops causes a reduction of the
conductivity signal recorded on the
induction logs, which is called "skin effect" It is a predictable phenomenon.
 Fig. 7-20 shows the response of the tool compared to the actual formation conductivity of
the formation.
 Skin effect becomes significant when formation conductivity exceeds 1,000 mmho/m.
 Multi-coil sondes, or focused sondes offer certain advantages.
1. Vertical resolution is improved by suppressing the response from the shoulder
formations, and
2. Depth of investigation is improved by suppressing the response from the mud
column and the formation close to the hole.

Log Presentation and Scales
 The Figure illustrates the original IES
presentation. The induction
conductivity curve is sometimes
recorded over both Tracks 2 and 3.
 The linear scale is in mmho/m,
increasing to the left. In Track 2 both
the 16-in. normal and the
reciprocated induction curves are
recorded on the conventional linear
resistivity scale
DIL-LLB log introduced the logarithmic grid
in track 2 and 3.
The DIL-SFL log, in combination with sonic
log, required a modification of the previous
grid, as shown in the Figure.

Corrections Rt Determination
Read apparent resistivity from well log.Ra
Correct for borehole effect (if necessary)
Correct for bed thickness effect (if necessary)
Correct for invasion effect
(If three curve are present)
True formation resistivity, Rt
Induction log borehole effects.
• Significant when
- Mud is salty
- Borehole size is large and/or oval
- Formation resistivity is high
• Corrections greatest for
- Induction tool against borehole standoff is zero.
- ILM than ILD
- Boreholes > 12"
Induction log - bed thickness correction
•The bed thickness effect is a f(bed thickness. vertical
resolution of tool. resistivity contrast Rt/Rs)
• Corrections necessary for:
- thick beds w/ Rt/Rs >> 1
- thin beds with large Rt/Rs contrast

AIT or HRI
 Array Induction Image Tool (AIT) or High Resolution Imager (HRI)
 Main features:
 full borehole corrections over a range of Rt/Rm contrasts
 the ability to use short a1rny information to solve for effective borehole parameters
 Five log curves are presented at median depth of investigation of IO. 20. 30. 60 and 90
inches, Three vertical resolutions of I. 2 and 4 ft.
 Improvement in invasion profiles for both oil¬and water-based muds. This includes
accurate Rt estimate and a quantitative description of the transition zone.
 Capability of producing resistivity and saturation images of the formation

Gamma Ray
1. Introduction of Gamma Ray
 The GR log is a measurement of the natural radioactivity of the formations.
 The radioactive elements tend to concentrate in clays and shales.
 Clean formations usually have a very low level of radioactivity, unless radioactive
contaminant such as volcanic ash or granite wash is present or the formation waters
contain dissolved radioactive salts.
 The GR log can be recorded in cased wells that make it very useful as a correlation curve in
completion and workover operations. It is frequently used to complement the SP log and as
a substitute for the SP curve in wells drilled with salt mud, air, or oil-based mud. In each
case, it is useful for delineating shale and non shaly beds.
 The gamma ray log is a continuous recording of the intensity of the natural gamma radiations emanating
from the formations penetrated by the borehole vs. depth.
 All rocks have some radioactivity. The most abundant source of natural radioactivity is
1) the radioactive isotope of potassium, K40, and 2) the radioactive elements of the
uranium and 3) thorium series.
 In sedimentary formations, radioactive elements tend to concentrate in clay minerals,
which, in turn, concentrate in shales.
 In general, sandstones, limestones, and dolomites have very little radioactive content.
Black shales and marine shales exhibit the highest levels of radioactivity.
 It can be used to distinguish between shale and nonshale formations and to estimate the
shale content of shaly formations.

2. Properties of Gamma Rays
 Gamma rays are bursts of high-energy
electromagnetic waves that are emitted
spontaneously by some radioactive
elements.
 Nearly all the gamma radiation encountered
in the earth is emitted by the radioactive
potassium isotope of atomic weight 40 (K40)
and by the radioactive elements of the
uranium and thorium series.
 Each of these elements emits gamma rays;
the number and energies of which are
distinctive of each element.
 The Figure shows the energies of the
emitted gamma rays: potassium (K40) emits
gamma rays of a single energy at 1.46 MeV,
whereas the uranium and thorium series
emit gamma rays of various energies.
 In passing through a matter, gamma rays experience successive Compton scattering
collisions with atoms of the formation material losing energy with each collision.
 After the gamma ray has lost enough energy, it is absorbed by means of the photoelectric
effect via an atom of the formation.
 Thus, natural gamma rays are gradually absorbed and their energies degraded as they pass
through the formation. The rate of absorption varies with formation density.
 Two formations having the same amount of radioactive material per unit volume, but
having different densities will show different radioactivity levels; the less dense formations
will appear to be slightly more radioactive.
 The GR log response after appropriate corrections for borehole is proportional to the
weight concentrations of the radioactive material in the formation:

3. GR Logs
 The gamma ray log is usually recorded with
porosity-type logs, i.e., density, neutron, and
sonic. As Figure illustrates, the gamma ray curve
is recorded on the first track of the log with a
linear scale.
 All recordings are positive, with the radioactivity
level increasing to the right.
 Because shales normally display the highest level
of natural radioactivity, the gamma ray curve
generally appears similar to the self-potential
(SP) curve of the electric logs.
 In empty boreholes or boreholes drilled with oil-
based mud, an SP curve cannot be recorded. The
gamma ray curve replaces the SP curve on the
first track of the induction log.
4. Unit of Measurement
 When gamma ray logging was first introduced, comparisons of logs run by different service
companies were virtually impossible because they used different units of measurement
(e.g., counts per minute, counts per second, radiation units, micrograms of radium
equivalent per ton of formation, and microroentgens per hour).
 This lack of standardization prompted the American Petroleum Inst. (API) to appoint a
subcommittee to develop a standard practice that would create uniformity to allow direct
comparison of radioactivity logs.
 The subcommittee designed a standard log heading and form and established a standard
API unit of measurement for both gamma ray and neutron logs. A calibration facility for
nuclear logs was designed and promoted. A standard procedure for presenting calibration
data also was developed.
7. GR Equipment
 The GR sonde contains a detector to measure the gamma radiation originating from the
volume of formation near the sonde.
 Scintillation counters are now generally used for this measurement.
 They are much more efficient than the Geiger-Mueller counters used in the past. Because
of its higher efficiency, a scintillation counter, few inches in length is mostly used.
 The GR log usually runs in combination with most other logging tools and cased-hole
production services.

6. Logging Speed
 The number of pulses averaged by the
detector depends on the radiation intensity,
the counter's efficiency, the time constant,
and the logging speed.
 An increase in logging speed is equivalent to
an apparent delay of equipment reactions to
a change in radiation intensity: the higher the
speed, the smoother the tool response and
vice versa.
 The Figure shows the effect of speed on log
quality. The same section of a well is logged at
speeds of 720 and 2,700 ft/hr.
 The quality of these logs is different.
 Beds are not defined as well on the 2,700-
ft/hr log. But bed resolution also depends on
the time constant; a better resolution calls: for a smaller time constant. A good quality log
should be run with an optimum combination of logging speed and time constant.
8. Applications
1. The GR log is particularly useful for defining shale beds
1. when the SP is distorted (in very resistive formations),
2. when the SP is featureless (in freshwater-bearing formations or in salty mud; i.e.,
when Rmf ≅ Rw), or
3. When the SP cannot be recorded (in nonconductive mud, empty or air-drilled holes,
cased holes).
2. The bed boundary is picked at a point midway between the maximum and minimum
deflection of the anomaly.
3. The GR log reflects the proportion of shale and, in many regions, can be used quantitatively
as a shale indicator.
4. It is also used for the detection and evaluation of radioactive minerals, such as potash or
uranium ore.
5. Its response, corrected for borehole effect, is practically proportional to the K2O content,
approximately 15 API units per 1% of K20. The GR log can also be used for delineation of
nonradioactive minerals.

9. Tool Response and Interpretation
 The gamma ray tool response, recorded with an optimum
speed and time constant with the tool situated opposite a
given formation, depends on several factors:
1. specific formation radioactivity, i.e., gamma
rays/sec-g;
2. formation bulk density, ρb;
3. Specific activities of the borehole fluid;
4. density of the borehole fluid; borehole diameter;
5. characteristics of the detector and the counting
system; and
6. Position of the detector in the borehole i.e.,
eccentricity.
 In a cased hole, the tool response also depends on the specific activities of the casing and
cement and on the thicknesses and densities of the casing and cement.

The Depth of Investigation
 The depth of investigation of the gamma ray tool is
difficult to determine by experimentation.
 An analytical treatment using Monte Carlo simulation
shows that, in general, 90% of the signal comes from
a shell 6 in. thick.
 Depth of Investigation: The volume of the formation
contributing the major portion of the tool response.
 Radiation depth is generally small, difficult to be
precise about.
 One experiment found that 75% of radiation came
from 14cm radius and 25cm above and below
detector → this was under lab conditions.
 Natural conditions will vary with each specific case.
 Because of Compton scattering this volume will vary
with formation density: smaller in dense formations.
Gamma Ray Spectrometry Log “GRS Log”
1. Introduction: NGS Log
 Like the GR log, the NGS natural gamma ray spectrometry log measures the natural
radioactivity of the formations.
 Unlike the GR log, which measures only the total radioactivity, this log (NGS) measures both
the number of gamma rays and the energy level of each and permits the determination of
the concentrations of radioactive potassium, thorium, and uranium in the formation rocks.
 The spectral gamma ray log, or gamma ray spectrometry tool, also detects the naturally
occurring gamma rays and defines the energy spectrum of the radiations. Because
potassium, thorium, and uranium are responsible for the energy spectrum observed by the
tool, their respective elemental concentrations can be calculated.
 The average concentration of potassium in the earth’s crust is about 2.6%. For uranium, it is
about 3 ppm; for thorium, it is about 12 ppm.
 Obviously, individual formations may have significantly greater or lesser amounts ad
specific minerals usually have characteristic concentrations of thorium, uranium, and
potassium.

 Therefore, the curves of the NGS log can often be used individually or collectively to
identify minerals or mineral type.
 Chart CP-19 shows a chart of potassium content compared with thorium content for
several minerals; it can be used for mineral identification by taking values directly from the
recorded curves.
 Often, the result is ambiguous so other data are needed. In particular, the photoelectric
absorption coefficient in combination with the ratios of the radioactive families is helpful:
Th/K, U/K, and Th/U.
 Care needs to be taken when working with these ratios; they are not the ratios of the
elements within the formation but rather the ratio of the values recorded on the NGS log,
ignoring the units of measurement.
 Chart CP-18 compares the photoelectric absorption coefficient with the potassium content
or the ratio of potassium to thorium for mineral identification.

2. Physical Principle
 Most of the gamma ray radiation in the earth originates from the decay of three radioactive
isotopes: potassium 40 (K40), with a halflife of 1.3 x109 years; uranium 238 (U239), with a
half-life of 4.4 x109 years; and thorium 232 (Th232), with a half-life of 1.4 x 1010 years.
 K40 decays directly to stable argon 40 with the emission of a 1.46- MeV gamma ray.
However, U238 and Th232 decay sequentially through a long sequence of various daughter
isotopes before arriving at stable lead isotopes.
 As a result, gamma rays of much different energy are emitted and fairly complex energy
spectra are obtained, as next slide shows. The characteristic peaks in the thorium series at
2.62 MeV and the uranium series at 1.76 MeV are caused by the decay of thallium 208 and
bismuth 214, respectively.
Natural Gamma
Some applications are:
a) Clay typing: Potassium and thorium are the primary
radioactive elements present in clays;
b) Mineralogy: Carbonates usually display a low gamma
ray signature;
c) Ash layer detection: Thorium is frequently found in ash
layers.
The ratio of Th/U can also help detect these ash layers.
3. NGS Log Presentation
 The NGS log provides a recording of the amounts (concentrations)
of potassium, thorium, and uranium in the formation.
 These are usually presented in Tracks 2 and 3 of the log (Figure).
The thorium and uranium concentrations are presented in parts
per million (ppm) and the potassium concentration in percent (%).
 In addition to the concentrations of the three individual
radioactive elements, a total (standard) GR curve is recorded and
presented in Track 1.
 The total response is determined by a linear combination of the
potassium, thorium, and uranium concentrations. This standard
curve is expressed in API units. If desired, a “uranium free”
measurement (CGR) can also be provided. It is simply the
summation of gamma rays from thorium and potassium only.

4. NGR vs. NGS
 Gamma ray: record of total formations radioactivity, from uranium, thorium and potassium
 Simple gamma ray: all
 Spectral gamma ray: amount of each
5. Borehole Correction Curves
The response of the NGS tool is a function not only of the concentration of potassium,
thorium, and uranium but also of hole conditions (hole size and mud weight) and of the
interactions of the three radioactive elements themselves.

6. Applications
 The NGS log can be used to detect, identify, and evaluate radioactive minerals.
 It also can be used to identify clay type and to calculate clay volumes.
 This, in turn, can provide insight into the source, the depositional environment, the
diagenetic history, and the petrophysical characteristics (surface area, pore structure, etc.)
of the rock.
 The thorium and potassium response or the thorium-only response of the NGS log is often
a much better shale indicator than the simple GR log or other shale indicators. Shaly-sand
interpretation programs such as GLOBAL* and ELAN* can thereby benefit from its
availability.
 The NGS log can also be used for correlation where beds of thorium and potassium content
exist.
 The combination of the NGS log with other lithology-sensitive measurements (such as
photoelectric absorption, density, neutron, sonic) permits the volumetric mineral analysis
of very complex lithological mixtures. In less complex mixtures, it allows the minerals to be
identified with greater certainty and volumes to be calculated with greater accuracy.
 The uranium response of the NGS log is sometimes useful as a “moved fluid” indicator for
in-field wells drilled into previously produced reservoirs. Also, permeable streaks may Have
higher uranium salt content than less permeable intervals.
1. Shale Content From the Gamma Ray Log
The shale volume Vsh is determined BY:
Where:
 log = the gamma ray reading/response at the depth of interest
 min = the minimum gamma ray reading (Usually the mean minimum gamma ray response
through a clean sandstone or carbonate formation).
 max = the maximum gamma ray reading (Usually the mean maximum gamma ray response
through a shale or clay formation.)
Vsh =
𝛾 𝑙𝑜𝑔− 𝛾 𝑚𝑖𝑛
𝛾 𝑚𝑎𝑥− 𝛾 𝑚𝑖𝑛

Porosity Logs:
1. Sonic Logs
Introduction
 Total porosity may consist of primary and secondary porosity.
 Effective porosity is the total porosity after the shale correction is applied.
 Rock porosity can be obtained from the sonic log, density log or neutron log.
 For all these devices, the tool response is affected by the formation porosity, fluid and
matrix.
 If the fluid and matrix effects are known or can be determined, the tool response can be
determined and related to porosity.
Therefore, these devices are usually referred to as porosity logs.
 All three logging techniques respond to the characteristics of the rock immediately
adjacent to the borehole.
 Their depth of investigation is shallow-only a few centimeters or less-and therefore
generally within the flushed zone
 Conventional sonic tools measure the reciprocal of the velocity of the compressional wave. This
parameter is called interval travel time, t, or slowness, and is expressed in microseconds
per foot.

1. Single-Receiver System
 In its simplest form, a sonic tool consists of a transmitter that emits/initiates a sound pulse
and a receiver that picks up and records the pulse as it passes the receiver.
 The sound emanated from the transmitter impinges on the borehole wall. This establishes
compressional and shear waves within the formation, surface waves along the borehole
wall and guided waves within the fluid column.
 The time measured, tlog, is between the initiation of the pulse and the first arrival of
acoustic energy at the receiver.
 The sonic log is simply a recording versus depth of the time, time required for a
compressional sound wave to traverse 1 m of formation. Known as the interval transit time,
transit time, t or slowness, tcomp is the reciprocal of the velocity of the sound wave.
 The interval transit time for a given formation depends upon its lithology and porosity.
 This dependence upon porosity, when the lithology is known, makes the sonic log useful as
a porosity log. Integrated sonic transit times are also helpful in interpreting seismic records.
 The sonic log can be run simultaneously with many other services.

2. Dual Receiver System
 The dual-receiver system was introduced to remove the mud path contribution from the
response of sonic tools.
 The Figure shows a schematic of one of the first tools that incorporated the two-receiver
system.
 The tool consists of a transmitter and three receivers located 3, 4, and 6 ft from the
transmitter.
The transmitter emits acoustic waves at 10 waves/sec.
 The first arrival of acoustic energy at each receiver triggers its response system.
 A two-receiver system can be viewed as a very accurate stopwatch. The stopwatch starts
when the acoustic energy arrives at the first receiver and stops when it arrives at the
second receiver.
 The time indicated by the watch is the time required for the sound wave to traverse a length of
the formation equal to the spacing between the two receivers. (T is free from mud-path contribution)

3.BHC Tool
 BHC consists of pair of transmitters and number of four receivers
where the symmetry the variations that would be seen by individual
transmitter (to compensate the tool tilting and cavities in formation).
 The borehole-compensated (BHC) tool transmitters are pulsed
alternately, and t values are read on alternate pairs of receivers.
 The t values from the two sets of receivers are averaged
automatically by a computer at the surface for borehole
compensation.
The computer also integrates the transit time readings to obtain
total
Span between Receivers and Tool Resolution:
 Several parameters are involved in the
design and performance of sonic tools.
 The distance between the receivers, or
span, determines the tool's vertical
resolution-i.e. the thinnest bed that can
be detected by the measurement.
 As a rule, a tool resolution equals the
span between the receivers.
 Two sonic curves can be obtained with
the tool in the Figure; a curve based on
the travel time between Receivers Rl and
R2, which are 1 ft apart, and a second
curve based on the travel time between
Receivers R2 and R3, which are 3 ft apart

Cyclic skipping
 Sometimes the first arrival, although strong enough to trigger the receiver nearer the
transmitter, may be too weak by the time it reaches the far receiver to trigger it.
 Instead, the far receiver may be triggered by a different, later arrival in the sonic wave
train, and the travel time measured on this pulse cycle will then be too large.
 When this occurs, the sonic curve shows an abrupt, large excursion towards a higher t
value; this is known as cycle skipping.
Cycle skipping commonly occurs in:
1. Series of thin beds of different velocities,
2. Gas sands,
3. Gas-cut mud,
4. Poorly consolidated formations, and
5. Fractured formations.
6. enlarged borehole sections.
Depth of Investigation
The acoustic tools' depths of investigation vary with the wavelength, , which is related to the
formation velocity, v, and signal frequency, f, by:
Hence, for a 20-kHz wave, the depth of investigation varies from 0. 75 ft. for soft formations to
3. 7 5 ft for hard formations.
Basically, cycle skipping yields an incorrect reading. It can be useful, however, as an
indicator for gas-bearing formations and fractured formations.
𝜆 = v / f

Log Presentation
 The sonic log is run with t
presented on a linear scale in
tracks 2 and 3 with a choice
of two scales:
500-100 and 300-100
µsec/m.
 A three-arm caliper curve
representing the average
borehole diameter and a
gamma ray (GR) curve are
recorded simultaneously in
track l (See next Figure).
 The gamma ray curve
measures the natural
radioactivity of potassium,
uranium and thorium in the
formation and is usually
representative of the
amount of shale present.
This is because radioactive elements tend to concentrate in clays and shales.
Previously, we used the GR to compute volume of shale ( Vsh ).
Interpretation goals:
1. –Porosity
2. –Lithology identification (with Density and /or Neutron)
3. –Synthetic seismograms (with Density)
4. –Formation mechanical properties (with Density)
5. –Detection of abnormal formation pressure
6. –Permeability identification(from waveform)
7. –Cement bond quality

Porosity Determination:
 for clean and consolidated formations with
uniformly distributed small pores, a linear time-
average or weighted-average relationship between
porosity and transit time:
tlog= tf + (1- tmat)
Where:
tlog is the reading on the sonic log in µsec/m
tmat is the transit time of the matrix material
tf is the transit time of the saturating fluid
Typical Values:
Sand: t matrix = 182 µsec/m
Lime: t matrix = l 56 µsec/m
Dolomite: t matrlx = 143 µsec/m
Anydrite: t matrix = 164 µsec/m
 When the formations are not sufficiently compacted, the observed Atvalues are greater
than those that correspond to the porosity according to the time-average formula, but the
versus t relationship is still approximately linear.
In these cases, an empirical correction factor, CP, is applied to give a corrected porosity,
svcor:
cp = dividing sonic velocity in nearby shale beds by 328.
Vma(ft/sec) tma(µ.s/ft)
∆tma(µ.s/ft)
(commonly
used)
used)
Sandstones 18,000-19,500 55.5-51.0 55.5 or 51.0
Limestone
s
21 ,000-23,000 47.6-43.5 47.5
Dolomites 23,000 43.5 43.5
Anhydrite 20,000 50.0 50.0
Salt 15,000 66.7 67.0
Casing(Iron) 17,500 57.0 57.0
=
𝑡𝑙𝑜𝑔− 𝑡 𝑚𝑎𝑡
𝑡 𝑓−𝑡 𝑚𝑎𝑡
=
𝑡𝑙𝑜𝑔− 𝑡 𝑚𝑎𝑡
𝑡 𝑓−𝑡 𝑚𝑎𝑡
x
1
𝑐 𝑝

Factors Affecting Sonic Interpretation:
1. Lithology
 Lithology must be known to obtain the correct Vma.
 An incorrect choice of Vma will produce erroneous calculations.
2. Shale
 Shale content generally causes t to read too high for a porosity calculation
because of the bound water in the shale.
 The sonic reads primary porosity, which may be affected by shale.
3. Fluid Type
 The depth of investigation of the sonic is shallow; therefore, most of the fluid
seen by the sonic will be mud filtrate.
3.1. Oil
Oil usually has no effect.
3.2. Water
There is usually no effect from water except where the drilling fluid is salt
saturated, and then a different Vf should be used, usually 607 µsec/m.
3.3. Gas
Residual gas causes tlog to read too high when the formation is uncompacted.
The gas between the sand grains slows down the compressional wave resulting in
a long t. In compacted sands, the wave will travel from one sand grain to
another and the gas effect will be reduced.
4. Compaction
 The value of tlog will read too high in uncompacted sand formations.
 Compaction corrections can be made if the compaction factor (Bcp is known).
5. Secondary Porosity
 The sonic generally ignores secondary porosity. For example, in vugular porosity, the
travel time through the formation matrix is faster than the time through fluid in the
vugs, because tf, is about 3 to 4 times the value of tma.
6. Borehole Effect
 The compensated sonic is unaffected by changing hole size except in the case of
extremely rough, large holes where the formation signal is severely affected by the
noise of the mud signal and formation damage.
7. Mud cake
 Mud cake has no effect on the BHC sonic because the travel time through the mud
cake is compensated.

Porosity Logs:
2. Density Logs
 Uses:
Densities logs are primarily used as porosity logs, i.e.to determine rock porosity.
Other uses include:
1. The identification of minerals in evaporite deposits,
2. Detection of gas,
3. Determination of hydrocarbon density,
4. Evaluation of shaly sands and complex lithologies,
5. Determination of oil-shale yield, and
6. Calculation of overburden pressure and rock mechanical properties.
 The Principle
 A radioactive source, applied to the borehole
wall in a shielded sidewall skid, emits medium
energy gamma rays (662 keV) into the
formation.
 These gamma rays may be thought of as high
velocity particles that collide with the
electrons in the formation.
 At each collision, a gamma ray loses some, but
not all, of its energy to the electron and then
continues with diminished energy" Compton
scattering''.
 The scattered gamma rays reaching the
detector, at a fixed distance from the source,
are counted as an indication of formation
density.
 The number of Compton scattering collisions
is related directly to the number of electrons in the formation.
 Consequently, the response of the density tool is determined essentially by the electron
density (number of electrons per cubic centimeter) of the formation.
Electron density is related to the true bulk density ρb, which, in turn, depends on the
density of the rock matrix material, formation porosity and density of the fluids filling the
pores.

 In the FDC* compensated formation density tool, two detectors of differing spacing and
depth of investigation are used, as shown on Figure.
 Log Presentation
 Log information is presented as shown in the
Figure.
 The bulk density curve, ρb, is recorded in Tracks 2
and 3 with a linear density scale in grams per cubic
centimeter.
 An optional porosity curve may also be recorded
in Tracks 2 and 3.
 The Δρ(which shows how much density
compensation has been applied to correct for mud
cake and hole rugosity) is usually recorded in
Track 3.
 The caliper is recorded in Track 1.
 A gamma ray (GR) curve may also be
simultaneously recorded in Track 1.
 If a CNL* compensated neutron log is run in
combination with the FDC log, it is also recorded
in Tracks 2 and 3.

 Porosity from a Density Log
For a clean formation of known matrix density ρma, with a porosity φ that contains a fluid of
average density ρf, the formation bulk density ρb, will be
Where:
, is the measured bulk density (from Lithe-Density tool)
is the density of the matrix (depends on lithology)
is the density of the fluid in pore volumes.
is the percent volume of pore space
is the percent volume of matrix.
𝜌 𝑏 = 𝜌 𝑓 + 𝜌 𝑚𝑎

 Depth of Investigation
 The integrated geometric factor curves
obtained experimentally for the FDC
tool are shown in Figure.
 These experimental results indicate that
the tool investigates only the first few
inches of the region next to the tool.
 Half of the tool response reflects the
region within about 2 in., while 90%
reflects the region within 5 in. of the
borehole wall.
Consequently, the density tool investigates
the invaded zone of permeable formations.
Factors Affecting The Density Log
1. Lithology
 The correct ρma must be known to get correct porosity.
2. Shale
 The density of shale in sands can range from 2200 to 2650 but is usually close to 2650,
the same as sandstone.
 In shaly sands, the density usually gives a good value of effective porosity regardless of
the shale content. The shale appears as matrix to the density tool.
Typical Density Values

3. Fluid Type
 The depth of investigation is quite shallow: usually most of the formation fluid is flushed
away from the wellbore and the density tool sees drilling fluid or filtrate in the pore
space.
 Hence, the values of ρf to use is that of the drilling mud filtrate rather than the
formation water density.
3.1. Oil
Residual oil will make density porosities slightly high, because oil is lighter than drilling
mud filtrate.
3.2. Water
Water density is proportional to the amount of salt content. The value of ρf is selected in
the computer for porosity determination.
3.3. Gas
The ρf of gas is 100–300 kg/m3
. Porosity determination in gas zones may be high if there
is residual gas near the borehole. Usually most of the gas is flushed and little effect is
seen on the density log.
4. Compaction
 The density tool is unaffected by lack of compaction.
 The density reads intercrystalline,vugular and fractured porosity. The porosity measured
is therefore total porosity.
6. Borehole Effect
 Density gives good values for smooth holes up to 381 mm in diameter.
 The tool compensates for minor borehole rugosity, but a rough hole causes the density
to read too low densities (high porosities) because the skid-to-formation contact is poor.
7. Mud cake
 For normal mudcake thickness, there will be no effect because the tool automatically
compensates for mudcake.
 However for a Δρ correction of 100 kg/m3 and greater (i.e., Δρ> 100 kg/m3), the tool
compensation may be insufficient and the ρb no longer representative of the formation
density. In this case, the density should obviously not be used for porosity calculations.

Porosity Logs
3. Neutron Logs
 Neutron logs are used principally for the delineation of porous formations and
determination of their porosity.
 They respond primarily to the amount of hydrogen in the formation. Thus, in clean
formations that have pores filled with water or oil, the neutron log reflects the amount
of liquid-filled porosity.
 Gas zones can often be identified by comparing the neutron log with another porosity
log or a core analysis.
 A combination of the neutron log with one or more other porosity logs yields even more
accurate porosity values and lithology identification—even an evaluation of shale content.
 Neutron Logging Applications
Neutron tools are used primarily to determine:
1. Porosity, usually in combination with the density tool
2. Gas detection, usually in combination with the density tool, but also with a sonic tool
3. Shale volume determination, in combination with the density tool
4. Lithology indication, again in combination with the density log and/or sonic log
5. Formation fluid type.
 Principle
1) Neutrons are electrically neutral particles, each with a mass almost identical to the mass of
a hydrogen atom. High-energy (fast) neutrons are continuously emitted from a radioactive
source in the sonde.
2) These neutrons collide with the nuclei of the formation materials in what may be thought
of as elastic billiard ball collisions. With each collision, the neutron loses some of its energy.
3) The amount of energy lost per collision depends on the relative mass of the nucleus with
which the neutron collides. A greater energy loss occurs when the neutron strikes a nucleus
of practically equal mass (i.e., a hydrogen nucleus).
4) Collisions with heavy nuclei do not slow the neutron much. Thus, the slowing of neutrons
depends largely on the amount of hydrogen in the formation.
5) Within a few microseconds, the neutrons have been slowed by successive collisions to
thermal velocities, corresponding to energies of about 0.025 eV.
6) They then diffuse randomly, without losing more energy, until they are captured by the
nuclei of atoms such as chlorine, hydrogen or silicon.
7) The capturing nucleus becomes intensely excited and emits a high-energy gamma ray of
capture.

 Principle,
 When the hydrogen concentration of the material
surrounding the neutron source is large, most of the
neutrons are slowed and captured within a short distance
of the source.
 On the contrary, if the hydrogen concentration is small, the
neutrons travel farther from the source before being
captured. Accordingly, the counting rate at the detector
increases for decreased hydrogen concentrations and vice
versa.
 Thus, the neutron tool responds to the hydrogen index of
the formation.
 The hydrogen index is a measurement of the amount of
hydrogen per unit volume of formation (HI of water = 1).
 Hydrogen Index
 Hydrogen concentration may be defined in terms of the Hydrogen Index (HI), which is
proportional to the quantity of H atoms per unit volume.
 The hydrogen index of fresh water at surface conditions is taken as unity.
For a paraffinitic oil (nCH2) we find HIoil = 1.29.ρoil.
If the in-situ density of this oil is 0.78 g/cc, its hydrogen index is equal to that of water, which
by definition has a value of 1.
HI =
number of H atoms
Volume ∗ number of H atoms in 1 cc H2o

 Neutron Tools
 Neutron logging tools include the GNT tools series (no longer in use).
 The Sidewall Neutron Porosity (SNP) tools (in limited use) and the CNL tool series, which
includes (CNL) the compensated neutron and DNL* Dual-Energy Neutron Log.
 The current tools use americium-beryllium (AmBe) sources to provide neutrons with initial
energies of several million electron volts.
1) SNP
 detects epithermal neutrons
 utilizes a skid mounted single detector
 Can be run in open hole only, either liquid- filled or empty.
 most corrections are automatically applied during logging
 Limited availability.
2) CNL tool
 Detects thermal neutrons
 The CNL tool uses a two-detector system that depth and resolution matches each count
rate before the ratio is computed.
 Conversion from one porosity assumption to another can be done using Chart Por-13b.
Por-13b converts curves labelled "NPHI" that are not environmentally corrected and
also converts for curves labelled "TNPH“and "NPOR," which are environmentally
corrected.
 The CNL tool is especially designed for use in combination with other devices.
 The CNL tool can be run in liquid-filled holes, either open or cased, but not empty holes
(i.e., air- or gas-filled holes.)

3) DNL tool
 Detects thermal and epithermal neutrons
 The DNL tool incorporates two epithermal neutron detectors in addition to the two
thermal neutron detectors. Two separate porosity measurements are obtained, one
from each pair of detectors.
 Improves the response to gas and enhances interpretation in the presence of thermal
neutron absorbers.
 In shaly formations containing a large number of thermal neutron absorbers, the
porosity measured by the epithermal detectors reads lower and agrees more closely
with density derived porosity.
 As with the CNL tool, the DNL tool is especially designed for use in combination with
other devices. In addition, the DNL tool can be run in liquid-filled holes, air/gas-filled
holes (epithermal porosity only) and open or cased holes.
 Investigation Characteristics
 Vertical Resolution:
The typical vertical resolution of the SNP and CNL tools is 2 ft.
However, a new method of processing the count rates of the CNL tool is now available that
increases the vertical resolution to 1 ft by exploiting the better vertical resolution of the near
detector.

 Depth of Investigation:
 The radial investigation depends on the porosity of the formation.
 Very roughly, at zero porosity the depth of investigation is about 1 ft.
 At higher porosity in liquid filled holes, the depth of investigation is less because neutrons
are slowed and captured closer to the borehole.
 For average conditions, the depth of investigation for the SNP tool is about 8 in. in a high-
porosity rock; it is about 10 in. for the CNL tool in similar conditions.
 Both tools sample a somewhat larger volume of formation than the FDC tools.
 Factors Affecting CNL Logs, …
1. Lithology
 A single known matrix must be present to accurately determine porosities.
 Large errors can occur if the matrix selection is incorrect.
2. Shale
 The presence of hydrogen in chemically bound water causes the CNL/DNL tool to read
high porosities in shales or shaly formations.
3. Fluid Type
3.1. Water: Fresh water has no effects. Saline water has a reduced hydrogen content
and the CNL/DNL tool will read low porosity; the correction is in the chart book.
3.2. Liquid Hydrocarbons:
o If the hydrogen content is close to that of water, there is little or no effect.
3.3. Gas: If the hydrogen concentration is low, the CNL/DNL tool reads low porosity.
4. Compaction
 All neutron logs are unaffected by compaction.
 All neutron equipment measures total porosity (including primary and secondary).
6. Borehole Effect
 The effects of rough hole are minimized by a large depth of investigation obtained by
the use of a high-yield source and the two-detector system.
 When run in combination with the density tool, an automatic caliper correction system
is accurate to [356 mm]. Normally there is zero standoff correction.
7. Mud cake
 Corrections for mud cake, fluid (mud and formation) salinity, mud weight, pressure and
temperature are in Charts Por-14(a) and 14(b), in the Log Interpretation Chart Book.
 The average net correction is usually between one and three porosity units. Hence, for
calculations by hand, the correction is usually not done.

 Density-Neutron combination
 All porosity logs are designed to
measure porosity in the presence
of water and over-react in the
presence of gas (and to a smaller
degree in the presence of oil).
 This can be used to distinguish
between gas and oil.
Gas: too high
too low
Porosity gas zone= 𝑑
2
+ 𝑛
2
2

 Lithology and Porosity Determination
 We have seen that porosity measurements are inferred from measurements of bulk
density, hydrogen index and acoustic travel times.
 We have also seen that each measurement provides the necessary input to calculate
porosity under the following conditions:
1. Porosity type is inter-granular, not fractured or secondary (vuggy, moldic, etc.).
2. Matrix type is known and constant.
3. Rock is clean, (i.e., no shale present).
4. Porosity is filled with fluid.
 Violations of any of these conditions will cause the different porosity measurements to
disagree in one fashion or another.
 This can be used to determine lithology, primary and secondary porosity and gas vs.
liquid content.
 The question to be answered here is: Which porosity measurement should be used?
Total Porosity Value
 In A Sand-shale Sequence, For Initial Computations,
1. If is available, use =
2. If and t are available, use = with compaction corrections applied.
 In a carbonate, for initial computations (limestone matrix),
1. if and are available in sandstone and limestone units, then use :
2. if only t is available, use : = + estimate vugs
 If gas is present in the reservoir, additional corrections to and must be applied.
 Porosity calculations i11 complex lithologies shall are discussed in Section H.
Log Interpretation of Shaly Formations. Shaly Sand Porosity
 When sand contains shale we cannot obtain an accurate value of effective porosity from
one porosity log.
 The responses of the density and neutron logs to shale content in sands is considered to be
the same as in nearby bedded shales, no matter what model of shale distribution is
considered.
 On the other hand, sonic logs have quite a different response between laminated-structural
and dispersed shales.
𝒕𝒐𝒕𝒂𝒍= 𝑵+ 𝑫
𝟐

Density Logs of Shaly Sand Formation
 Neutron and Sonic φof Shaly Sand Formation

1. Effective Porosity and Shale Content from Porosity Logs
 Effective porosity can be calculated well if Vsh and sh are known.
 Experience has shown that, when one porosity tool is used to calculate , the density log
provides the best estimate. Because ( D)sh is much smaller than ( N)sh and ( S)sh the
correction term [Vsh ( a)sh] of the previous Equation is less sensitive to an incorrect
estimation of vsh .
To avoid misinterpretation caused by a non-representative Vsh value estimated from the
gamma ray log, an independent evaluation of Vsh is necessary. This can be done with two
porosity tool responses.
The two equations to be solved simultaneously for cj> and Vsh: <Pv =</>+ Vsh(<bo)sh • • and
<i>N=c/>+ Vsh«PN)sh•

Geology & Geophysics in Oil Exploration

58 Geology & Geophysics in Oil Exploration Mahmoud Sroor

Radioactive Tools:
Density Tool: Litho-Density Tool (LDT)
These tools have a caesium-137 or cobalt-60 source emitting gamma rays at 0.662 MeV,
a short-spaced and a long-spaced detector in the same way as the basic formation
density tool. However, the detectors are more efficient, and have the ability to
recognize and to count separately gamma rays which have high energies (hard gamma
rays: 0.25 to 0.662 MeV) and gamma rays which have low energies (soft gamma rays:
0.04 to 0.0 MeV).
Gamma ray enters the formation, then scattering & looses some of its energy then
absorbed by a formation. Then, the detectors detect γ ray which emitted from excited
atoms which related to the formation.
Notes:
• The borehole must be perfectly vertical (no washout) because in this case, the tool
will measure air response & causing errors in data.
• Drilling muds with high density will absorb gamma rays efficiently, such as barite filled muds, will effect the detector
readings. However, the effect of these muds is compensated for automatically by the spine and ribs correction.
Where: ρb = the bulk density of the formation ρma = the density of the rock matrix
ρf = the density of the fluids occupying the porosity ФD = the porosity of the rock.
Calibration:
The primary calibrations are made by inserting the tool into a block of pure
limestone saturated with fresh water of accurately known density.
Secondary (check) calibrations are made in the wireline tool workshop by inserting
the tool into large blocks of aluminum, sulphur and magnesium of known density.
Tool operation:
The tool is physically very similar to the formation density tool. It has enhanced
detectors, and the distance between the long spacing and the short spacing
detectors has been decreased. This decrease has increased the vertical resolution
of the tool and improved its overall counting accuracy. The accuracy of the
density measurement of the litho-density tool is approximately 0.01 to 0.02
g/cm3, whereas that of the formation density tool is approximately 0.02 to 0.03
g/cm3.
The density measurement has a vertical bed resolution of 50 to 60 cm, which is
slightly better than the formation density tool. The enhanced resolution results
from the shorter distance between the short and the long spacing detectors.
The log is commonly referred to as the photo-electric factor log (PEF).
ФD= (ρb‐ρma) / (ρf‐ρma)
The hard gamma rays are those that are undergoing compton scattering. The
count rates of these gamma rays (in the energy window 0.25 to 0.662 MeV) are
used in the conventional way to measure the formation density (Chapter 13). The
final density value obtained is more accurate than the basic formation density tool
because the harder gamma rays are less prone to attenuation by borehole
effects, and there is a smaller spacing between the two detectors that has
reduced statistical fluctuations in the count rates.
The soft gamma rays are those that are undergoing photo-electric absorption. This
effect can be used to provide a parameter which is dependent upon the atomic
number of the formation, and therefore immensely useful in lithological
recognition.

Thermal Decay Time
Introduction:
 The Thermal Decay Time (TDT) log records the thermal neutron capture cross section of the
formation by measuring the thermal neutrons’ rate of decay.
 Because chlorine is by far the strongest neutron absorber of the common earth elements,
the response of the TDT log is determined primarily by the chlorine present (as sodium
chloride) in the formation water.
 Since the effects of water salinity, porosity, and shaliness on the thermal neutron decay
rate are similar to those on resistivity logs, the TDT log resembles the usual open-hole
resistivity logs and is easily correlated with them. But the TDT differs in that it can be run in
cased holes.
 Consequently, when formation water salinity permits, TDT logging provides the means to
recognize the presence of hydrocarbons in formations which have been cased, and to
detect changes in water saturation during the production life of the well.
 The TDT log is thus useful for the evaluation of old wells, for diagnosing production
problems, and for monitoring reservoir performance.
 As in the case of the resistivity log, the most important parameter values needed for
quantitative interpretation are porosity and water salinity. Information is also required on
shaliness, lithology, and the nature of the hydrocarbon. Modern openhole logging
programs and crossplot techniques usually provide such information.
Principal :
 A neutron generator in the TDT sonde repeatedly emits pulses of high-energy neutrons.
Following each burst the neutrons are rapidly slowed down in the borehole and formation
to thermal velocities.
 They are then captured by nuclei with a corresponding emission of gamma rays. Relative
changes in the thermal neutron population in the media are sampled by gamma ray
detectors placed at a short distance from the source.
 During the period of measurement the thermal neutron population decreases
exponentially. This decrease is due to either neutron capture or neutron migration
(diffusion).
 At every point in the formation, a certain fraction of the thermal neutrons locally present is
absorbed per unit time.

Supervised by: Prof. Dr. Nabih A. Alsayed
Production logging report
Compiled by: Mahmoud Jad Mahmoud Jad
Production Logging
Definition
 Record of one or more in-situ measurements that describe the nature and behavior of
fluids in or around the borehole during production or injection.
 Production logging is the measurement of fluid parameters on a zone-by-zone basis to
yield information about the type and movement of fluids within and near the wellbore.
Major applications of production logging:
1. Evaluating completion efficiency.
2. Detecting mechanical problems, breakthrough, coning.
3. Providing guidance for workovers, enhanced recovery projects.
4. Evaluating treatment effectiveness.
5. Monitoring and profiling of production and injection.
6. Detecting thief zones, channeled cement.
7. Single layer and multiple layer well test evaluation.
8. Determining reservoir characteristics
9. Identifying reservoir boundaries for field development.
10.Measuring the performance of producing and injection wells.
Uses of Production Logging
Production Logging is put to many uses depending on the reservoir type, well conditions and
the perceived problem. Some of the major ones are:
1. Evaluate completion performance
# Newwells # Injection wells # Re-completions
2. Monitor reservoir performance & variations
# Flow profile # Well Test # Completion Efficiency
3. Diagnose well problems
# Water entry # Gas entry # Leaks and mechanical problems # Flow behind casing
4. Other
# Guidance for workover # Information for enhanced oil recovery projects
# identify boundaries for field development.
 The figures below show Common problems encountered in the producing wells where
production logging can be used.
 Some are due to mechanical problems others to the reservoirs such as bad cement,
unwanted flow, tubing leak, casing leak and packer leak & etc.)

PLT Tools
A family of production logging tools, designed specifically for measuring the performance of
producing and injection wells, is available. The sensors now included are:
1. Thermometer
2. Fluid density {gradiomanometer, nuclear)
3. Hold-up meter
4. Flowmeter spinners {continuous, fullbore, diverter)
5. Manometer {strain gauge, quartz gauge)
6. Caliper
7. Noise {single frequency, multiple frequency)
8. Radioactive tracer
9. Gravel pack logging.
Many of these sensors can be combined into one tool and recorded simultaneously to measure fluid entries
and exits, standing liquid levels, bottomhole flowing and shut-in pressures, pressure losses in the tubing, and
the integrity of the gravel pack and hardware assemblies.
Applications of specific measurements Production Logging Measurement Mechanisms
Each sensor has some specific uses, most are utilized
in combination, however, to give a total answer
for the well/reservoir (Figure).
1. Flowmeter:
 Determine producing zones
 Stimulation evaluation
 Secondary recovery
 Flow potential evaluation (SIP, AOF)
2. Temperature:
 Location of production or injection zones
 Monitor frac performance
 Gas entry
 Fluid movement behind pipe
 Fluid conversions
3. Fluid Density:
 Determine volumetric flow in two phase fie
 Show entry points in three phase flow
4. Pressure:
 Well test analysis (kh, skin)
 Reservoir extent, boundaries
 Fluid conversions
Tools
Production logging tools consist of a number of sensors
which make the measurements inside the well (Figure).
The main types are:
1. Flowrate (fluid velocity) measurement
• Spinner rotation
2. Fluid density measurement
 Differential pressure
 Gamma ray attentuation
3. Well bore temperature
• Variance in resistance
4. Well bore pressure
 Strain gauges
 Crystal gauges
A number of auxiliary measurements are used to
augment or assist in the analysis of the major logs. They
are:
 Caliper (mechanical)
 Fluid sampling
 Noise Logs
 Tracer surveys
 Water Flow Log

Temperature Logging
Introduction: Temperature Log:
A record of the temperature gradient in a well.
The temperature log is interpreted by lookmg for anomalies, or departures, the geothermal
gradient, a log recorded before production started or a log recorded with the well shut-m.
Most anomalies are related to the entry of fluids into the borehole or fluid exit into the
formation.
Since the temperature is affected by material outside the casing, a temperature log is sensitive to not only
the borehole but also the formation and the casing-formation annulus.
Temperature logs have many applications, with the most common being:
1. To identify zones producing or taking fluid,
2. To evaluate a cement or hydraulic fracture treatment, and
3. To locate lost circulation zones and casing leaks.
4. to derive profiles of borehole temperature and formation temperature vs. depth
5. to delineate fluid-inflow zones and to measure inflow rates.
Since temperature takes time to dissipate, a temperature log tends to reflect the behavior of a
well over a longer time period than other measurements.
The geothermal gradient or geotherm : The rate at which temperature in the sub-surface
increases with depth.
 The geothermal gradient is not constant because of differences in the thermal
conductivities of rocks between the bottom of the hole and the surface, and fluctuations in
the surf ace temperature which penetrate the sub-surf ace and perturb the sub-surface
temperature.
 Low thermal conductivity rocks, such as shale, act as a thermal insulator and have a large
temperature gradient across them, while high thermal conductivity rocks, such as salt,
permit the conduction of heat efficiently, and have a small temperature gradient across
them

Recent Uses of Temperature Logs
Borehole temperature data for formation evaluation are now used mainly:
1. To determine formation temperature/ depth profiles and
2. To delineate fluid inflow zones and to measure inflow rates.
3. In addition, the bottom hole temperature and the borehole-Temperature/depth
profile provide support data for many formation evaluation calculations.
4. Artificially fractured zones belong in a monograph on production logging.
Temperature Logs Applications
The temperature log has many applications, particularly when run in combination with other
sensors. Some of these applications are:
1. Detection of gas production via the cooling effect of expanding gas (in or behind casing);
2. Qualitative evaluation of fluid flow as indicated by departures from the geothermal gradient
3. Temperature (T) information for PVT equations and charts.
Temperature information is critical to the determination of gas expansion/compression,
GOR, and oil shrinkage from downhole to surface conditions and vice versa;
4. Evaluation of fracture treatments.
5. Evaluation of the mechanical integrity of a completion.
Temperature logging devices are of two types:
1. Down hole-recording systems; and
The two types within this system are
1. The maximum-recording mercury thermometer; and
2. The mechanical recording thermometer (the so-called temperature bomb).
2. Surface-recording systems.
Log Interpretations
 Temperature log interpretations can also be used to determine flow rates; however, other
sensors generally provide better results.
 The thermometer responds to temperature anomalies produced by fluid flow either within
the casing or in the casing annulus, and is thus useful for detecting the latter.
 The NEXT Figure illustrates the temperature log response in four different situations: liquid
flow, liquid flow behind casing, gas flow, and gas flow behind casing.

Temperature Log Responses
T

Spinner flow-meter Logging
1. Flow Velocity:
Flowmeter spinner tools and radioactive tracer tools are usually used to measure flow velocity.
Under certain conditions, the fluid density and temperature tools can be used to estimate flow
rates but their use for this purpose is much less common.
Fluid velocity is measured indirectly by the rate at which the fluid passing the production
logging tool turns a spinner (propeller).
(This is the inverse process to a ships propeller turning and moving the ship).
Basic Concept: Q = Vm x A
2. Spinner Flowmeter Tools:
Spinner flowmeters all incorporate some type of impeller that is rotated by fluid moving
relative to the impeller. The impeller commonly turns on a shaft with magnets that rotate
inside a coil. The induced current in the coil is monitored and converted to a spinner speed in
revolutions per second. This spinner speed is then converted to fluid velocity (flow rate).
Interpretation in Single-Phase Flow
Spinner revolution rate varies with fluid flow rate.
Therefore, in single-phase flow, the flow profiling
interpretation technique is essentially the plotting of
spinner data in revolutions per second, such that the
percentage flow contribution of each zone can be read
directly from the plot.
This assumes the fluid density and viscosity are
consistent throughout the interval and that the velocity
profile does not change.
An example showing percentage contributions is
shown in the Figure
Spinner rate is a function of fluid viscosity, density, and velocity.

Radioactive Tracer Tools
Tracer tools can be placed into the following two categories:
1. Gamma ray tools without downhole ejectors for releasing radioactive material, and
2. Gamma my tools with downhole ejectors and multiple gamma ray detectors.
1. Gamma ray tools without downhole ejectors:
 Tools in the first category are standard gamma ray tools that are used for flow
profiling with the controlled-time technique.
 They are also often used for channel detection and treatment evaluation by
comparing logging runs made before and after injecting fluids containing radioactive
materials into the well.
 The difference in the two runs will identify where radioactive material is present.
2. Gamma my tools with downhole ejectors:
 Tracer tools in the second category have multiple gamma ray detectors combined
with an ejector.
 The ejector consists of a chamber that will hold a small amount of radioactive
material and a pump that will eject a controlled amount upon command.
The detectors monitor the movement of the injected tracer material.
The standard tool configuration will consist of three detectors.
Radioactive tracer surveys are not routinely run in producing wells because of the
complications of produced radioactive fluid and multiphase flow effects. Therefore, the main
application of this technique is in injection wells.
If logging an injector well:
 The tool string will usually consist of one gamma ray detector above the injector and
two detectors spaced below.
When logging a producing well:
 The configuration will be reversed with one detector below and two detectors
spaced above the ejector.
 The single detector is used to detect unexpected flow reversals caused by thief zones
and for identifying channels behind casing, where flow is opposite of the wellbore
fluids. The two adjacent gamma ray detectors are used for flow profiling by
measuring the flow time between the two detectors.

Velocity Shot Interpretation
 The recording of a velocity shot consists of
ejecting a small slug of radioactive material into
the flow stream and measuring the time between
detection by two separate detectors.
 Usually, the velocity shots are recorded on time
drive with the tool stationary in the well.
 The Figure shows a 2-detector velocity shot.
The flow rate is computed as follows:
Where:
h = distance between gamma ray detectors
A = cross-sectional area
t =time.
The flow rate in barrels per day can be calculated from the following equation:
Where:
6.995 = numerical constant
D = casing inside diameter in inches
d= tool outside diameter in inches
X= detector spacing in inches
t= time, in seconds, to move X-inches.
q (BID) = 6.995 (D2-d2)X /t
q = h x A / t

Noise logs
Noise Tools
 There are two types of noise tools:
1. The Audio tool is a single frequency device that is usually run
in the continuous mode.
2. Multiple-frequency noise tools record station readings.
 A schematic of a typical noise tool is shown in Figure. The tool
consists of a transducer that converts sound into an electrical
signal. The signal is amplified and transmitted up the cable by the
electronics cartridge. The tool does not emit any sound energy. It
only responds to sound originating in or around the well bore.
Noise Logs
A record of the sound measured at different positions in the borehole.
Since fluid turbulence generates sound, high noise amplitudes indicate locations of greater
turbulence such as leaks, channels and perforations.
Noise logging is used:
1. Primarily for channel detection, but has also been used to measure flow rates,
2. Identify open perforations,
3. Detect sand production
4. Locate gas-liquid interfaces.
Although first introduced around 1955, the technique was not used commercially until after
laboratory studies in the early 1970s.
 The log may be either a continuous record against depth or a series of stationary
readings.
 The log may indicate the total signal over all frequencies, the signal at a single frequency,
or consist of a set of logs for different frequency ranges.
 Different frequency ranges can be tied to different sources of noise or different flow
regimes.

Noise Log Principle
 Liquid, gas, or a combination of the two (single and two phase) have a distinctive sound
when flowing through restrictions such as channels behind casing, perforations, or
casing leaks.
 This sound is detected and recorded on the Noise Log. A series of band pass filters
separates the frequency spectrum of the sound for analysis of the individual amplitudes
contained in each band.
From model studies in the laboratory and experience in the field, the relative energy
levels in the four bands of frequencies can be related to single and dual phase flow and
the probable location of the flow.
 Often considered to be a production logging instrument, the Noise Log can also be
definitive in open hole while drilling and during completion. To aid interpretation, the
Noise Log often is recorded in combination with a Temperature Log.
 The noise in a well is a function of the acceleration, or turbulence, of a fluid moving
across a pressure differential.
By varying the pressure differential, flow rate, or both, various types of noise can be
generated.
The noises can be characterized and categorized into different groups by examining the
frequency spectrum of the total signal. Information from the spectrum can be useful for
determining channels behind casing, tubing or casing leaks, and producing perforations.
 The noise log may be recorded in a stationary mode so that the tool will respond to
wellbore noise without being affected by extraneous noises caused by cable or tool
movement.
 The Figure shows a noise log that depicts
a gas entry through a set of perforations
from 8320 to 8350 ft.
 Above the perforations the discontinuous
phase in the wellbore is gas and the
sound attenuates quite rapidly. The
sound attenuates much slower in the
standing water below the perforations.

 The log in Figure illustrates the effectiveness of the noise log at
identifying fluid movement behind casing.
 The log indicates that there is flow behind casing from a group of
sands below 9900 ft into a zone at 8700 ft.
 Techniques have been developed to calculate flow rates from
noise logs, but factors such as distance from the noise source,
perforation size and condition, tool-to-casing contact, and fluid
environment create inaccuracies in the results. Generally, flow
rates are best determined by other sensors.
APPLICATIONS
1. Determine fluid flow behind or inside casing
2. Locate fluid flow in cement annulus channel
3. Locate gas or liquid entry through casing leaks
4. Locate gas/liquid interface in wellbore
5. Determine whether fluid flow is single or two phases
6. Locate points of gas production in open hole
7. Locate points of lost circulation in open hole
8. Locate points of sand production in perforated casing
9. Identify active perforations
Combinable tools
•Gamma Ray (GR) Tool
•Casing Collar Locator (CCL) Tool
•Pressure Transducer
•Noise Tool

Abnormal pressure Zones
Definition
Abnormal pressure is defined as any departure from normal hydrostatic pressure at a
given depth.
Causes:
Compaction disequilibrium is believed to be the most dominant cause of abnormal
pressure.
Importance of identifying overpressure
 Abnormal pressure (overpressure) conditions in the subsurface can pose/cause
significant drilling and safety hazards, e.g. (Shallow water flow, Blowouts, Shale
instability ) if not detected So Early and reliable detection of geopressure is vital to avoid
or mitigate these hazards by providing the chance to
1. Make appropriate design of drilling programs of offset wells by adjusting the
mud to avoid well and reservoir damage.
2. Make appropriate selection of DST design and the well control equipment.
3. Enables to determine casing type and casing points.
4. Minimize the dangers and problems of kicks or loss of circulation.
5. Be used in long range geological correlation.
This is a particular concern in deep-water wells in which the pressure difference; i.e., the
operating window, between the hydrostatic gradient and the fracture gradient can be
very narrow.
 In exploration for hydrocarbons and exploitation of the reserves, knowledge of the
pressure distribution is of vital importance
o For prediction of the reserves,
o For optimizing the recovery rate.
 Moreover, drilling of deep gas resources is hampered by high risk associated with
unexpected overpressure zones.
Identification:
By sonic log, density log and TDT log
 These formations are often overlain by shale formations that have an excess of pore water.
 Sonic transit time is greater in these shale formations than in normally compacted shale.

Logging Tools:
 These are electronic devices that records data
over depth.
 The tool is attached to the end of wireline cable
& lowered to the borehole.
 There are many types of tools such BHC tool,
GR tool, Density tool and many others
 Usually, these tools are integrated as
measurement sensors in one tool called Sonde.
 Cartridge: The section of a wireline logging
tool that contains the telemetry, the electronics
and power supplies for the measurement, as
distinct from the sonde that contains the
measurement sensors.
 The Caliper Tool is a 3 armed device that measures the internal diameter (I.D.) of casing or
open borehole completions.
 This information is crucial to all types of production logging.
 The caliper probe provides a “first look” at borehole conditions in preparation for additional
logging. It uses a tool which has 2, 4, or more extendable arms.
 The caliper is a useful first log to determine the borehole conditions before running more
costly probes or those containing radioactive sources.
 The log is used to: "Interpretation Goals"
1. measure borehole diameter,
2. Location of cracks, fissures, caving,faulting, casing breaks.
3. assess borehole quality and stability
4. For calculation of pore volume for pile construction.
5. Input for environmental corrections for other measurements.
6. Qualitative indication of permeability.
7. Correlation.
8. Correction of other logs affected by borehole diameter
9. Provide information on build-up of mudcake adjacent to permeable zones.
10.Locate packer seats in open hole.
 Increasing in diameter of borehole indicates about Wash out Process (ex: Shale).
 Decreasing in diameter of borehole indicates about Invasion process (ex: Porous Sand).
How Do They Work?
• Mechanical arms record hole size
• Hydraulic systems with calibrated
potentiometers.

Borehole Size
Borehole size is set by the drill bit, but it is influenced by:
• Changes in stress state
– borehole breakout
– induced fracturing
– creep of salt
• Chemical Reactions
– swelling clays in shales
– dissolution of salt
– Drilling Process
– spiral borehole
– bit marks
Note that when a hole is the
same diameter as the bit-size it
is called on gauge.

 Interpretation details
1. indication of hole diameter and volume
 hole diameter is read directly from the log. one- or two-arm calipers (like with the
density, dipmeter, or rxo tools) will tend to read the long diameter of the hole if the
hole is elongated, while three-arm calipers (like with the sonic) will read an average,
somewhere between the length of the long and short axis. one arm or two arm calipers
will tend to be more sensitive than three-arm calipers. calipers which show diameter in
two orthogonal directions will show holes which have become elongated.
 Hole volume is computed by integrating the hole volume calculated at each depth
sample. the hole is assumed to be circular for a single diameter measurement, and
assumed elliptical for a two dimensional measurement.
2. Input for environmental corrections for other tools
 The hole diameter is used in various charts for density, neutron, laterolog, and
induction, and to indicate the thickness of mud cake for rxo tool corrections.
3. Qualitative indication of permeability
 The existence of mudcake (when the borehole diameter is less than the bit size) is an
indication of the infiltration of mud into the formation. because of differences in mud
type, density, and other parameters, the magnitude of permeability cannot be
determined. mudcake is usually noted as a comparison to bit size. when the hole is
washed out, the presence of mudcake can be masked by the washout.
4. Correlation
 Curves can be scanned for general shape and changes in indicated hole size. some
formations can consistently wash out in a particular geographic area (regardless of
mud program), giving a general indication of the location of the well in the
subsurface.
5. Log quality control
 indications from the caliper that the hole is rough is a warning that measurements
which are from tools pressed against the borehole wall, such as density, neutron, and
the microresistivity curves, may not be reliable.
Secondary effects
1. Environmental effects
In highly deviated holes, the caliper mechanism may not be strong enough to support the
weight of the logging tool, and may not indicate the actual diameter of the hole.
2. Interpretation effects
Occasionally, mud cake indications can be masked by a washed out borehole
 Quality Control
Check the caliper value in casing against the casing diameter.
Shale values should be similar to those in nearby wells.
Check repeatability; curves should have the same values and character as those from previous
runs or repeat sections.
Cross-check the curve character with other curves from the same logging run.

of 107Page 100 of 107
The caliper log can be used also :
Caliper log: A representation of the measured diameter of a borehole along its depth
Notes:
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of 107Page 101 of 107
Petrophysics MSc Course Notes Caliper Logs
Dr. Paul Glover Page 92
Figure 9.3 Typical caliper responses to various lithologies.
Brittle Shale
Impermeable
Sandstone
Sloughing
Shale
Permeable
Sandstone
Impermeable
Limestone
Anhydrite
Marl
Shale
Caving
Bit
Size
Sloughing
Mud
Cake
CAL (in)
BIT SIZE (in)
6 16
6 16
Bit
Size
On
Gauge
On
Gauge
Caving
Tight Spot
Mud Cake
Caliper
Curve

of 107Page 102 of 107
CAL 4
Correlation/Lithology
Caliper
Log Example
Guide to Petrophysical Interpretation
Daniel A. Krygowski, Austin Texas USA

of 107Page 103 of 107
Notes on shale and clay mineral
Compiled by: Mahmoud Jad Mahmoud Jad Supervised by: Prof. Dr. Nabih A. Alsayed
 Shale is type of clastic sedimentary rock:
•Comprised dominantly of clay minerals and other clay-size fragments.
•Contains some silt-sized grains of:
-Quartz. -Feldspar. -Other minerals. -May contain organic fragments. (source rock)
•Shale is fissile - splits along bedding planes.
 Clay is the name for a family of alumino-silicate minerals including:
�Kaolinite("discrete particle")
�Chlorite ("pore lining")
�Illite("pore bridging")
�Smectite
�Montmorillonite
�Clay is a class of clastic sediments with a grain size (diameter) < 0.004 mm (< 4 microns)
�May contain clay minerals, quartz, feldspar minerals, etc.
�Clays form approximately40% of sedimentary rocks.

of 107Page 104 of 107
�Structural Shale:
�Replaces matrix (or feldspar) or can occur as detrital grains.
�May not affect porosity/permeability.
�Example—clast lag in channel deposits.
�Clay composition may differ from nearby shales
�Laminated Shale:
�Interlayered with sand.
�Affects porosity/permeability.
�Common scenario —shale laminae.
�Composition should be similar to nearby shale

�Dispersed Shale/Clay:
�Pore-filling clays (very common).
�Forms in-situ (authigenic clays form through diagenesis).
�Composition may differ greatly from nearby shales.
�Porosity and permeability reduction depend on volume and type of clay
minerals.

of 107Page 105 of 107
Dispersed Clay Types:
1. Kaolinite - booklets, particles.
•Moderate effect on permeability.
2. Chlorite - linings, coatings.
•Significant reduction in permeability.
•Traps water.
3. illite - pore-bridging tangles.
•Acts to choke pores and pore throats.
•Significant reduction in permeability.
•lllite will collapse when dry, yields erroneous
estimates of porosity (too high).
Authigenic Kaolinite
•Forms booklets or "discrete particles."
•Can cause significant re¬duction in
permeability, generally moderate.
•Yields a high irreducible water saturation.
•Fines migration is also a possibility with Kaolinite.
•Kaolinite is NOT recognized using the conventional Gamma Ray (GR) log.
Authigenic Chlorite
•Forms a "pore lining" - i.e., a thin coat on the detrital grain surfaces.
•Chlorite is rich in iron and will react with acids.
•Generally occurs in deeply buried sandstone reservoirs.
•Chlorite can significantly reduce permeability and tends to trap water.
Authigenic Illite
• lllite is consists of "pore-bridging" filaments (or fibers) which can signifi¬cantly reduce
permeability.
• lllite generally does not have a significant impact on porosity.
• Can cause high irreducible water saturation.
•Fines migration can be an issue with lllite.

of 107Page 106 of 107
Clay mineral classification:

of 107Page 107 of 107
References
 Prof. Dr.Adel Salem lectures of well logging course
 Daniel A. Krygowski Guide to Petrophysical Interpretation 2003
 Basic Well log analysis for geologists by George Asquith
 Schlumberger - Log Interpretation Principles – Applications
 Petrophysics MSc Course Notes Dr. Paul Glover
 Well logging for earth scientists

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