[p.T] Petrophysics Logging Tools

8/8/2019 [p.T] Petrophysics Logging Tools

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SPONTANEOUS POTENTIAL LOG

HISTORY

One of the first log measurements made.

It was discovered as a potential that effected old electric logs.

It has been in use for over the past 50 years.

APPLICATION

Correlation from well to well

Depth reference for all logging runs

Detecting permeable beds

Detecting bed boundaries

Qualitative indication of shalyness

Rw determination

THEORY OF MEASUREMENT

Operation

An electrode (usually lead) is lowered down the well and an electrical potential isregistered at different points in the hole with respect to surface electrode.

Therefore SP is a recording of the difference in potential of a moveable electrodein a borehole and a fixed electrode on the surface. In order to record a potentialthe hole must contain conductive mud, as it cannot be recorded in air or oil-basemud. Logging rate is approximately 1500m per hour and recordings are

continuous.

The SP electrode is built into different logging tools for example:

o Induction log.

o Laterolog.

o Sonic log.

o Sidewall core gun.

FIGURE 1: THE SP MEASUREMENT

SP results from electric currents flowing in the drilling mud. There are threesources of the currents, two electrochemical and one electrokinetic. Deflection ofSP is caused by the Electrochemical Ec and Electrokinetic Ek actions:

Electrochemical Component

Ec = Elj + Em

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These two effects are the main components of the SP. They are caused as a resultof differing salinities in the mud filtrate and the formation water.

Elj: "Liquid Junction Potential"

The ions Na+ and Cl- have different mobilities at the junction of the invaded and

virgin zones. The movement of the ions across this boundary generates a currentflow and hence a potential.

If the salinity of the mud in the borehole is weaker or stronger than that of theformation water the potential generated between the two solutions is known asthe Liquid Junction Potential or Elj. The greater the difference between the salinityof the solutions the greater the potential.

FIGURE 2: LIQUID JUNCTION EFFECTS #1

FIGURE 3: LIQUID JUNCTION EFFECTS #2

Em: "Membrane Potential"

Shales are permeable to Sodium ions but not to Chlorine ions. Hence there is amovement of charged particles through the shale creating a current and thus apotential. This is known as the membrane potential or Em.

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FIGURE 4: MEMBRANE POTENTIAL SP

Electrokinetic Component

An Electrokinetic potential (Ek) is generated by the flow of mud filtrate through aporous permeable bed. It depends upon the resistivity of the mud filtrate and willonly become important if there are high differential pressures across theformation. This process is not well understood and the effects are normallynegligible in permeable formations because the mud cake builds quickly and haltsany further invasion. In low porosity, low permeability formations, the mud cakebuilds slowly and the Electrokinetic potential becomes predominate. This is thepotential that makes the SP appear to float randomly in very tight formations suchas low porosity carbonates. In these conditions the SP cannot be used todetermine Rw.

FIGURE 5: TOTAL SP

Deflection of the SP curve The SP measurement is constant but jumps suddenly to another level whencrossing the boundary between two different formations.When Rmf > Rw The SP deflects to the left (-ve SP) found in permeable formationsfilled with formation waterWhen Rmf < Rw The SP deflects to the right (+ve SP) found in permeable formationfilled with formation water

There is no deflection in non-permeable or shaly formations.

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FIGURE 6: SP DEFLECTION

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 2-3inches if highly permeable and more than 2-3 feet if permeability is low.

Vertical resolution of the SP tool is approximately 3 meters

CALIBRATION

In the logging unit there is a small battery and a potentiometer in series between the twoelectrodes. The logging engineer can adjust the potentiometer so that the SP appears intrack 1. Since we need to remove all extraneous potentials to the membrane potential,the SP needs to be normalised in a computing centre so that there is no potential(SP=0.0MV) opposite shale beds. This is done concurrently with the SP drift correction.

The absolute difference between shale and sand remains the same after drift correction.Caution:

Some field engineers in the past varied the potentiometer to correct the drift whilelogging and therefore keep the SP on the display track. Recent logging tools record theraw SP on data storage (i.e. no battery and no potentiometer) and it is sometimespreferable to use this raw SP to perform the SP correction. An offset can be applied to theraw SP if its values range significantly above zero.

LIMITATIONS AND PRESENTATION

LimitationsBorehole mud must be conductive.

Formation water must be water bearing and conductive.A sequence of permeable and non-permeable zones must exist.Small deflection occurs if Rmf=RwNot fully developed in front of thin beds

Metallic reaction at measure electrode

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This is one of the components that will cause the SP to drift. The SP electrodemade of mild iron will rust and this oxidizing effect of the electrode results in anadded electrochemical potential to the SP measurement. The drift graduallydisappears as the electrode becomes fully oxidized. Because this is an undesirablepotential, the drift can be removed by correcting the SP curve using computersoftware. See the practical example of how to remove SP drift and normalize the

SP in section 8.0.

Possible solution to the problem:

o The bridle electrode should be made of lead as it incurs less oxidization and

therefore less drift.o Never clean or remove the rust from the SP electrode.

o One hour before going down hole, wrap the electrode in a rag soaked in the

mud pit. This will reduce the oxidizing effect down hole

Other unwanted SP potentialsHeavy rain:

If heavy rain starts during logging, the surface conductivity of the soil willgradually change and therefore can gradually change the potential between thesurface reference and the down hole electrode and thus contribute to the SP drift.Noise:Surface noise such as electrical leakages on the rig, welding equipment, weatherstorms and lightning strikes will cause the SP to be noisy and at random. Nowelding should be allowed during the recording of the SP log.Logging drum and sheave magnetism:If part of the logging drum, wire line sheave or measure wheel is magnetized, thiswill appear on the SP curve as a short and regular deflections.Disruptions to the ground reference:

The SP electrode (called the fish) should be placed in an undisturbed position inthe mud pit away from moving mud fluids.

Powerlines, electric trains, close radio transmitters and cathodic protection devicesall create currents, which disrupt the ground electrode reference causing a poor,sometimes useless log.Bimetallism occurs when two different metals are touching surrounded by mudproduces a weak battery.Spikes in the curve can be caused by contact of the wire line cable and casing.

This is not normally a problem.Using a curve smoothing program can remove unwanted noise.

Presentation

SP is presented in track 1 by a thin continuous line with the mnemonic of SP. SP is

measured in MV (millivolts) and although there is no absolute scale, a relativescale of 10 MV per small division and usually -80 to 20MV across track 1 is used.

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FIGURE 7: TYPICAL SP LOG PRESENTATION

TOOL COMBINATIONS

The SP is usually run with the resistivity service. The Induction tool contains an SPelectrode. An SP electrode is also available in the bridle of the logging cable and is used

with the Laterolog, Sonic and even Side Wall Coring tools.

Associated MnemonicsSP Spontaneous PotentialSSP Static Spontaneous Potential

Typical Log Readings

The value of the SP measurement depends upon the salinity contrast of Rmf andRw. Values are expected to range approximately + or - 50mV about the 0mV shalebase line.

LQC, CORRECTIONS AND INTERPRETATIONLog Quality Control

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FIGURE 8: SP IN HIGH RESISTIVE

BEDS

FIGURE 9: SHALE BASE LINE

SHIFTS

High resistive beds:

High resistivities can alter the distribution of the SP currents and hence the shapeof the SP curve.Telluric Currents:Natural current flow of fluids in the borehole is a major source of SP drift.Shale base line shifts:Occurs when an imperfect cationic membrane of a shale bed separates formationwaters of different salinities. There is also a shift when two different salinity watersare present in a bed. This process is not very well understood.

FIGURE 10: SAW TOOTH SP

Invasion Effects:Fresh water filtrate in permeable salt-water sands will float near the upperboundary resulting in a saw tooth SP.

= [1+3E5/Salinity(ppm)^(1/1.05)]/81.77

CEMENT BOND LOGHISTORY

The Cement Bond Log has been used since the 1960's. It is still widely used and is

often preferred to many other more recent cement evaluation tools.

In the mid 1980's ultrasonic transducer tools were introduced like the CET and PETtools.

APPLICATION

Determine cement bond quality between cement and casing and also between

cement and formation for zone isolation

Correlate open hole logs to cased hole logs using the Casing Collar Locator (CCL)

and Gamma Ray tool

An indication of cement compressive strength. These tools (CET, PET) also

measure casing thickness, micro annulus and cement channeling but do notmeasure cement bond to formation as well as the CBL.


Operation

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FIGURE 1: SCHEMATIC REPRESENTATION OF THE CBL/VDL TOOL

Once a well has been determined to be productive, casing is run in the open holeand cement is pumped to the outside of the casing to seal the casing to theborehole wall. A Cement Bond Log (CBL) is then run to inspect the integrity of the

cement sealing to the casing and to the formation. This will ensure that formationfluids will flow into the casing when the productive zone is perforated and not upor down the outside of the casing.

The CBL is similar in operation the open hole Sonic tool. There is only onetransmitter however and two receivers at distances of 3 and 5 feet from thetransmitter. As with the Sonic tool the compressional or P waves are used tomeasure the time to travel from the transmitter to the receiver. The CBL tool isuncompensated unlike the open hole Sonic tool. Centralization of the CBL istherefore critical to it's operation. Rigid steel Gemoco centralizer whos outsidediameter match exactly the casing inside diameter should always be attached tothe CBL tool. This will ensure good centralization.

The 3-foot signal from the transmitter to the first receiver, will primarily measurethe cement to casing bond. If there is little or no bond the amplitude of the signalwill be very large. If there is good bond the amplitude will be very small. This iscommonly known as the TT3 (Travel Time 3 foot) or CBL (Cement Bond Log) signal.

A Similar compressional wave will be measured with the 5-foot signal from thetransmitter to the second receiver. The signal will however read deeper into theformation. It will predominately measure the cement to formation bond. Again alarge signal amplitude indicates a bad cement to formation bond and a smallamplitude a good cement to formation bond. This is commonly known as the TT5(Travel Time 5 foot) or VDL (Variable Density Log) signal.

Here the horizontal line is the threshold detection. The TT3 travel time ismeasured between the transmitter pulse at the start and the amplitude arrive 'E2'.

The CBL signal amplitude is measured by the height of this first arrival.The 5-foot waveform is used differently to the 3 foot. Here the horizontal threshold'cuts through' the positive peaks of the received signal. It is this cross sectionthrough the positive peaks that is displayed on the VDL track as if viewed from thetop of the waveform.Depth of Investigation and Vertical Resolution

The 3-foot CBL signal measures immediately outside the casing. The 5-foot CBLsignal has a larger spacing and is sampled over the entire wave train. It thereforereads several inches into the formation.


LimitationsThe borehole must have fluid in the well bore in order for acoustic coupling tooccur.

Presentation

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FIGURE 2: TYPICAL

CEMENT BOND LOGPRESENTATION

FIGURE 3: GOOD

FORMATION BOND FIGURE 4: FREE PIPE

TT5 signal is displayed in the pseudo standard VDL presentation. This is a 'Bird'seye view' of the TT5 waveform 'above' the threshold. See Figure 3

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TOOL COMBINATIONS

The CBL tool requires a gamma ray measurement to correlate on depth with the openhole gamma ray. A casing collar locator is also used to enable correlation of wirelineperforating guns.


Good cement to casing bond exists when the CBL signal amplitude is less thanabout 10mV. Thick 'wavy' VDL response indicates good cement to formation bond.Free pipe signal takes on specific values for different casing sizes. Typically 62mVfor 7 inch and 72mV for 5.5" casing. See table in Figure 4 above.

LQC, CORRECTIONS AND INTERPRETATION

Log Quality ControlMicro annulus is often a problem when performing a casing cement job. Once the

cement has been pumped into the casing annulus, micro annulus can occur whenthe wellhead pump pressure is held too long, causing the casing to expand. Whenthe pressure is released the casing retracts and a thin break occurs between thecasing and the cement. Holding of wellhead pressure immediately after thecement job should be kept to a minimum.

Another cause of micro annulus occurs if there is any residual coatings left on theoutside of the casing during manufacture. When the cement job is run thesecoatings inhibit the cement to bond to the casing again leaving a thin microfracture or break between the casing and cement. The cement job requires a freeflush chemical fluid to remove any coatings immediately before the cement ispumped outside the casing.

Similarly a free flush needs to be run to remove any borehole wall mud cake. Thiswill help ensure a good cement to formation bond also.

Drilling operations can cause micro annulus. A CBL log run soon after the casing isset may not confirm if micro annulus exists however.

If the 3-foot travel time is not primarily a straight line, then the CBL tool is poorlycentralized and the cement bond will not be accurate.

CorrectionsMicro annulus is noticeable when the CBL signal is approximately 10-20mV. If

micro annulus is suspected, the casing should be pressured to 1000psi well headand the CBL survey run again under the 1000psi pressure. If the CBL signalreduces to below 10mV then micro annulus exists. Micro annulus is not usually aproblem for zone isolation.Interpretation

The purpose of interpreting the CBL log is to ensure good zone isolation over aproductive formation. By viewing the CBL log presentation; a qualitative analysisof the cement bond can be determined.Good Bond:CBL signal - The interval 3307.5-3310.5ft has very good bond between cementand casing by virtue of small CBL amplitude in Track 3 of approx. 4mV. Often atthese low amplitudes the TT3 travel time will cycle skip.

VDL signal - There are good formation arrivals indicated by the VDL display inTrack 5. The formation arrivals are depicted by the very thick VDL lines (thickbecause the amplitude is very high). These formation arrivals should also followthe open hole Sonic transit times. This indicates a good cement to formation bondalso.

Free Pipe signal:

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CBL signal - Here you can see that the free pipe signal is reaching a maximum ofapproximately 62mV. There is some cement scattered around the pipe that isreducing the CBL signal in places but essentially this is still free pipe. There is nocontinuous cement seal to the casing. The TT3 is reading 280usec and the freepipe signal is 62mV both indicating 5.5 inch casing.

VDL signal - At the start of the VDL signal in track 5 there are straight thin linesrepresenting casing arrivals. The thicker formation arrivals are also relativelystraight which are not representative of the formation response.

COMPENSATED NEUTRON LOG

APPLICATION

The Neutron tool is used to determine primary formation porosity, often called the porespace on the formation rock which is filled with water, oil or gas. Together with other toolslike the density, the lithology and formation fluid type can also be determined.

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FIGURE 2: THREE TYPES OF

NEUTRON INTERACTION

An Am241Be source emits neutrons into the formationat approximately 4MeV. (Plutonium Berilium sources

are no longer used since they can be broken down tocreate atomic weapons). After collisions with theformation, the neutron energy levels fall to between0.1 and 10eV. These are known as epithermal neutrons.After further collisions neutron energy levels fall below0.03eV and these are termed thermal neutrons. Byvirtue of its similar mass to neutrons, Hydrogen morethan any other element in the formation slows downthe neutrons dramatically. A useful analogy is a billiardball interacting with a bowling ball or a ping-pong ball.

The billiard ball only loses significant velocity when ithits another billiard ball not when it hits a ping-pongball or bowling ball. Since hydrogen is primarily onlypresent in water, oil and gas, the neutron tool gives adirect measurement of the fluid in the pore space ofclean formations. Two detectors, one short spaced andthe other long spaced from the source are used toeliminate some borehole effects and detect thenumber of neutrons returning back to the tool. A lowneutron return count indicates the presence ofhydrogen and therefore porosity.

FIGURE 3: NEUTRON ENERGY

DECAY

Once the neutrons reach the thermal stage, theyare ready to be captured. The presence of strongneutron absorbers like Chlorine have a capturecross section about 100 times that of Hydrogen atthe thermal level. Thermal neutrons thereforeneed to be corrected for fluid salinity and matrixcapture cross section effects. Epithermal neutronsdo not need to be corrected for capture effects butonly have one tenth of the population of thermal

neutrons. Some neutron tools like the CNT-GA candetect both epithermal and thermal neutronsgiving two different porosity measurements. Thestandard CNT Tool measures only thermalneutrons.


Halliburton

Neutron

CNT Tool

Schlumberger

Neutron CNT Tool CNT Tool Enhanced

Vertical Resolution 24 inches Vertical Resolution 24 inches 12 inches

Depth ofInvestigation

8-12 inchesDepth of Investigation 9-12 inches 9-12 inches

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FIGURE 4: STANDARD DETECTORRESPONSE

FIGURE 5: DEPTH-MATCHED DETECTORRESPONSE

LIMITATIONS, OPERATION AND PRESENTATION

Limitations

The neutron tool can be used in any borehole filled with fluid or air. Both can berun in boreholes with up to 20,000psi, 400degF and less than 24 inch holediameter.

Similarly with the gamma ray tool the neutron tool must be handled gently. Roughtreatment or heavy impacts can crack the crystal and this will need to be replacedbefore logging.

Neutrons travel in a random manner and not in a continuous flow. The neutronmeasurement is therefore affected by statistical variations. Statistical variationscan be reduced with a lower logging speed. As with gamma ray detection,neutrons are averaged over a period of time. The slower the logging speed the

more accurate the measurement. Logging speeds of 30ft.min(1800ft/hr) withsoftware averaging produces accurate results.

Operation

Some Density/Neutron combinations are pad mounted devices and centered in the borehole. This

provides two caliper readings orthogonal to each other. The Neutron caliper has a stronger spring thanthe Density, and will measure the largest part of any oval borehole. The pad device ensures a better

borehole contact for Neutron measurements and therefore requires less corrections. Some Neutron toolsuse a source that is activated electronically. In this way the tool emits Neutrons only when it is switched

"ON" while downhole at the start and finish of logging.

Presentation

Presented in track 5 and 6 by a dashed line with the mnemonic NPHI and withscales, 45% to 15% (or .45 to 0.15 p.u.-porosity units).

FIGURE 6: TYPICAL DENSITY/NEUTRON LOG PRESENTATION

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TOOL COMBINATIONS

Neutron is usually run in combination with the Density tool to help evaluate oil, gas andwater in the pore space

LQC/CORRECTIONS

Log Quality Control and Interpretation

Shale affects the neutron log reading by indicating larger than true porosity byway of neutrons colliding with the bound water in the shales. Similarly a boreholewashout will indicate a larger than true porosity reading. A gaseous formation hasa lesser concentration of hydrogen than if filled with water or oil and the Neutronwill therefore indicate a pessimistic porosity value.

Using compatible limestone scales for density (1.95 RHOB 2.95) and neutroncurves (45% NPHI 15%) then:-In a clean wet limestone RHOB and NPHI curves will overlay.

In shale RHOB plots right of NPHI depending on the amount of shale present.In a gas limestone RHOB plots > 3pu left of NPHIIn clean wet sand RHOB plots 3pu left of NPHIIn a clean wet dolomite RHOB plots right of NPHIUsing compatible sandstone scales for density (1.90 RHOB 2.90) and neutroncurves (45% NPHI 15%) then:-In a clean wet sand RHOB and NPHI curves will overlay.In a shale RHOB plots right of NPHI depending on the amount of shale present.In an oil sand RHOB plots 1-3pu left of NPHIIn a gas sand RHOB plots > 3pu left of NPHI

FIGURE 7: SHALY

FORMATION

Shale effectively reduces the measuredporosityon both the Density tool and the Neutrontool by:-

VDshale = (PHID PHIeff) / PHIDsh

VNshale = (PHIN PHIeff) / PHINsh

Environmental Corrections

Log quality is ensured if good contact is made with the borehole wall from the toolbow spring. Environmental corrections that need to be applied for the Neutron logare:-

1. Borehole size2. Borehole salinity3. Borehole temperature and pressure4. Mud cake5. Mud weight6. Formation salinity7. Tool standoff from borehole wall

It should be noted that each Neutron tool is different for each wireline loggingcompany and the specific correction chart should be used for that specific Neutrontool. The Neutron tool response is dependant upon the source strength anddetector spacing.


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Mineral NPHI (%)

100% Limestone 0%

100% Sandstone -2%

100% Dolomite 1%

Shale 30-45%Expected logreadings

0-45%

DENSITY LOG

APPLICATION

The density tool is used to determine formation density and estimate formation porosity.Together with other tools like the Neutron, the lithology and formation fluid type can alsobe determined. The density tool can distinguish between oil and gas in the pore space by

virtue of their different densities. Modern density tools also measure the photoelectriceffect to help distinguish between rock lithologies, recognize presence of heavy minerals,fracture identification when barite is present and additional clay evaluation. In additionthe density can be used to determine Vclay and to calculate reflection coefficients toprocess synthetics.

Figure 1: Gamma rayinteractions

A 1.5 Ci Cs137 chemical source bombards gamma rays at 662keVenergy into the formation. The high-energy gamma rays interactwith the electrons of the formation by way of Compton scatteringand lose energy in the process. Other processes also occurnamely photoelectric absorption and pair production, althoughpair production only becomes significant at energies above 1MeV.

A low number of gamma rays detected through Comptonscattering will indicate a high electron density. The bulk density rBhas a close relationship to the electron density as shown by thefollowing experimentally determined equation: -

RHOB = 1.0704*RHOe - 0.1883

A spectral or litho density tool measures not only the bulk densitybut also a photoelectric absorption index PEF. The photoelectriceffect occurs when the incident gamma ray of low energy isabsorbed by the electron and the electron is then ejected from theatom.

PEF = (Z/A)3.6

A=Atomic weight, Z=Atomic number (or # of hydrogen atoms)

The photoelectric effect of absorbed gamma rays is directlyrelated to the Z, the number of electrons per atom, which is fixedfor each element. Different values of the PE curve indicatedifferent types of formation rock being measured and areindependent of formation porosity.

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Figure 2: Energy Spectrum for measuring

Compton Scattering and Photoelectric Absorption

The Density tool is usually run eccentered together with the Neutron tool. The Densityhas a backup caliper arm to push the pad against the borehole wall and the Neutron uses

a bow spring.

FIGURE 3: DENSITY PAD SCHEMATIC

Density Porosity DeterminationSince the bulk density (rB) is a measure of the matrix density (rma) and the fluid density(rf) in the pore space, then the amount of pore space or formation porosity can bedetermined. The rma and rf must however be known.

RHOB = RHOMA(1-PHID) + PHID*RHOFor

PHID = (RHOB - RHOMA) / (RHOF-RHOMA)Where:-

RHOB = Density log readingRHOMA = Density MatrixRHOF = Density Fluid

PHID = Density Porosity

Synthetic Processing

The Density is used along with the Sonic velocity to compute Acoustic impedance(I) by:-

I = Density(rho) * Velocity (V)

The Reflection coefficient (R) at a bed boundary is then determined by:-R = (I2 - I1) / (I2 + I1)

The Reflection coefficient is then used to generate synthetic processing curvesthat can match the exploration seismic.


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HalliburtonDensity

StandardDensity

LithoDensity

SchlumbergerDensity

Litho Density

VerticalResolution

7.5 inches 7.5inches Vertical Resolution

18 inches(Standard)6 inches(Enhanced)

Depth ofInvestigation

2 inches 2 inchesDepth ofInvestigation

6-9 inches

CALIBRATION:

The density tool is calibrated using a Cs137 source to read rB = 1.00 g/cc in water and rB= 2.71 g/cc in limestone and is calibrated against standard aluminum and sulphur blocks,which characterize a water filled limestone formation. At the time of calibration a well siteverifier with small gamma sources is placed on the density tool and a measurementtaken. The PEF curve is also calibrated in a similar manner to read 5.085 in calcite and1.806 in quartz.

Well site calibration checks are performed before and after each logging suite with thewell site verifier to ensure the tool was operating the same as when it was calibrated.

LIMITATIONS/OPERATION/PRESENTATION:LIMITATIONS

The density tool can be used in any borehole, whether it contains oil-based mud,water-based mud, salty mud or even air. A Density tool can be run in boreholeswith up to 20,000psi, 400degF and less than 22 inch hole diameter.

The major problem associated with the density tool is ensuring a good pad contactagainst the borehole wall. Bad pad contact usually occurs in a washed out or

rugose hole, possibly caused by a fast drilling rate or brittle formation.

Similarly with the gamma ray tool the density tool must be handled gently. Roughtreatment or heavy impacts can crack the crystal and this will need to be replacedbefore logging.

Measurement of detected gamma rays is averaged over a period of time. Theslower the logging speed the more accurate the measurement. Logging speeds of30ft.min(1800ft/hr) with software averaging, produces accurate results.

OPERATION

Density tools use a Cs137 chemical source of 1.5Ci activity that continuously emitsgamma rays. The Density pad is heavily shielded, allowing gamma rays to passthrough a small window at the front of the pad and into the formation. Gammarays travel in a random manner and not in a continuous flow. The gamma raymeasurement is therefore affected by statistical variations. Statistical variationscan be reduced with a lower logging speed.

The Density tool is run eccentered against the borehole wall by virtue of themechanical pad design. The caliper is opened by a coil spring mechanical designand is closed by a down hole motor and worm gears or by a hydraulic pumpoperation.

PRESENTATION

Presented in track 5 and 6 by a thin continuous line with the mnemonic RHOB. Forsandstone scales, 1.90 to 2.90 with units of g/cc and neutron from 45% to 15%.For limestone scales, 1.95 to 2.95 with units of g/cc and neutron from 45% to 15%. The amount of density correction is presented in track 6 by a dashed linewith the mnemonic DRHO. DRHO scales are -0.25 to 0.25 with units of g/cc.

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FIGURE 5: TYPICAL DENSITY/NEUTRON LOG PRESENTATION

TOOL COMBINATIONS:

Density is usually run in combination with the Neutron tool to help evaluate oil, gas and

water in the pore space.

LQC/CORRECTIONS:Log Quality Control and InterpretationShales are usually less dense than in a clean formation. RHOB will therefore readless than the true density in shales and as a result the computed density porositywill be higher in shales than the true porosity. In gas bearing formations, RHOB willshow a large drop in densityUsing compatible limestone scales for density (1.95 RHOB 2.95) and neutroncurves (45% NPHI 15%) then:-In a clean wet limestone RHOB and NPHI curves will overlay.In a shale RHOB plots right of NPHI depending on the amount of shale present.

In a gas limestone RHOB plots > 3pu left of NPHIIn a clean wet sand RHOB plots 3pu left of NPHIIn a dolomite RHOB plots right of NPHIUsing compatible sandstone scales for density (1.90 RHOB 2.90) and neutroncurves (45% NPHI 15%) then:-In a clean wet sand RHOB and NPHI curves will overlay.In a shale RHOB plots right of NPHI depending on the amount of shale present.In an oil sand RHOB plots 1-3pu left of NPHIIn a gas sand RHOB plots > 3pu left of NPHISince the PEF of water, hydrogen and Oxygen are almost zero the effect ofporosity on the PEF measurement is negligible. Basic lithologies can therefore beinterpreted directly from the PEF curve alone.

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FIGURE 6: SHALY FORMATION

Volume of Shale calculations:A shaly formation is depicted in Figure 7a. If Vsh is thefractionalvolume of shale then the fractional volume of matrix

is (1-Vsh-f) and: -RHOB = (1-Vsh-f)*RHOMA + Vsh*RHOSH + PHI*RHOF

andPHI = (RHOMA-RHOB)-Vsh*(RHOMA- RHOsh

(RHOMA-RHOF)and

Vsh = (RHOMA-RHOB)-PHI* ( RHOMA -RHOF)(RHOMA-RHOsh)

Shale effectively reduces the measured porosity onboththe Density tool and the Neutron tool by:-

PHID = PHIeff + PHIDsh(Vsh)PHIN = PHIeff + PHINsh(Vsh)

FIGURE 7: GAS BEARING FORMATION

Gas Effects:Figure 7b illustrates a gas bearing formation and: -

RHOB = (1- PHI)*RHOMA + PHI*Sxo*rmf + PHI*(1-Sxo)*RHOg

andPHI = (RHOMA -RHOB)/[RHOMA -RHOG-(RHOmf-RHOg)*Sxo]An approximation phiorrg (in g/cc) can be given by: -

RHOg = 0.18/[(7644/D) + 0.22] where D = depth in feet


Mineral RHOB(g/cc)

PEF

100%Limestone

2.71 5.09

100%Sandstone

2.65 1.81

100%Dolomite

2.85 3.05

Shale 2.2-2.7 3.36(typically)

Anhydrite 2.92-2.98 5.05

Salt 2.06 4.65

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Coal 1.68 0.18

Hydrogen -0.61

Carbon -0.29

Water 1 -0.02

Environmental CorrectionsLog quality is ensured if good contact is made with the borehole wall. As mud cakebuilds up on the borehole wall, or the borehole wall is rugose, the density toolmeasures less than true density because it is also reading the less dense mud. Theshort and long spaced detectors are affected differently by the mud beingmeasured. The amount of correction that needs to be applied to the raw densityreading can therefore be determined via the spine rib plot. The corrected densityreading is shown on the log and the amount of correction applied is depicted bythe DRHO curve.

If a large DRHO occurs but RHOB follows DT and NPHI then RHOB is considered anaccurate reading. DRHO can be small indicating little correction applied but RHOBvery erratic and therefore accuracy is questionable. Sometimes DRHO is low, the

hole is not rugose but the borehole size is reaching the limit of the calipermeasurement. Here the tool is simply reading the borehole mud. It is important tocheck the caliper, DRHO and hole rugosity to validate a good Density log.

FIGURE 8: DENSITY RESPONSE IN RUGOSE BOREHOLE

As can be seen in Figure 9A, a rugose borehole exists between 4008m and 4017m. The DRHO is very large and RHOB is still reading borehole mud even aftercorrections. Between 3989m and 4008m the DRHO is still very large but RHOBappears good except for a couple of thin streaks. The zone above at 3972m to3989m has DRHO < 0.05g/cc and RHOB is very accurate.

N.B. In the case of mud containing barite or high-density mud, a negativecorrection will be applied to the DRHO curve.

Corrections are applied for:-Mud cake thickness - real timeMud weight real timeRugose borehole - real timeBorehole size

DIP METER LOGHISTORY

Early tools employed 3 and 4 arms with a single current emitter or button on each

pad.

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To achieve greater borehole coverage, the 1990's saw the introduction of high-

resolution tools with 24 and 25 buttons on each pad.

Borehole televiewers and acoustic scanners generate borehole images covering

100% of the borehole.

APPLICATION

Determination of borehole inclination and direction

Determination of formation thickness, dip and direction

Determination of True Vertical Depth (TVD)

Hole ovality plots to determine insitu stress and breakout directions

Image data processing allows paleontology studies and diagenetic history

Volumetric measurements to determine thin bed total thickness


Operation

Accelerometer and Magnetometer transducers are placed inside the sonde body ofeach dipmeter and imaging tool. There are 3 accelerometers, one along the axis ofthe tool in the "Z" direction and in the "X" and "Y" direction at 90deg to the toolaxis. The accelerometers measure the tool acceleration and can determine if thetool is jerking up the hole during logging. By applying these measurement, toolspeed corrections can be applied. There are also 3 magnetometer measurementsthat measure the tool orientation in the X, Y and Z directions with respect theearths magnetic field. These measurements help determine borehole inclinationand direction and also then formation dip angle and direction.

Dipmeter

FIGURE 1: BASIC DIPMETER TOOL

The dipmeter caliper arms are deployed against the borehole wall by either toolhydraulic pressure or mechanical caliper springs. The dipmeter pads attached to eachcaliper arm, measure the formation micro resistivity that is very similar to the MSFLmeasurements. The resulting curves are called correlation curves and are used todetermine formation dip. The resistivity measurements require conductive boreholemuds. If oil based muds exist, then conductivity pad devices are employed usinginduction type technology.

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FIGURE 2: PAD DIMENSION FOR IMAGING TOOL

High-resolution dipmeters or imaging tools are similar to the standard dipmetertools except they have 24 or 25 buttons on each pad of each arm. See Figure 3. Inthis way micro resistivity measurements cover a much greater percentage of theborehole approximately 50% of 8.5" in diameter.

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Acoustic Imaging

FIGURE 3: TYPICAL ACOUSTIC SCANNING TOOL

The Acoustic scanning tools typically have a single acoustic transmitter thatrotates at about 7.5 rps. The acoustic signal requires fluid in the borehole for

transmission. The reflected signal from the borehole wall positively interacts withthe transmitted signal setting up a standing wave. The wavelength is known andtime for the transmission to return from the borehole wall is measured. Theborehole diameter can then be determined.

While the acoustic scanning tools measure 100% of the borehole the image qualityis often poor when compared tom the high-resolution dipmeter results. This isusually due to the poor acoustic coupling of the fluid in the borehole.


Depth of Investigation

FMS 0.2 inch

FMI 0.1 inch

EMI 0.1 inch

UBI 0.4 inch

Specifications

Tool typeFMS

(Schlumberger)

FMI(Schlumberg

er)

EMI(Halliburton

)

STARBakerAtlas)

# Pads 4 4 6 6

# Flaps 0 4 0 0# Rows 2 2 2 2

# Buttons 24 48 25 24

Button horizontalspacing

0.2 inches 0.2 inches 0.1 inches 0.1 inches

Button verticalspacing

0.3 inches 0.3 inches 0.3 inches 0.3 inches

Even pad vertical 0 2.5 inches 2.5 inches

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spacing

Flap spacing 0 6 inches No flaps No flaps


Limitations

As with all pad device tools, the dipmeter suffers from poor pad contact with theborehole wall when the hole is rugose or washed out. The acoustic scanning toolrequires clean borehole fluids else a poor acoustic coupling will result giving poorprocessed acoustic images.

Presentation

FIGURE 4:STANDARD

FMIPRESENTATIO

N

Dark colours are conductive muds.Light colours are high resistive formation.


Log Quality ControlThe Borehole Azimuth (HAZI) should not change dramatically during logging andPAD1 azimuth (P1AZ) and Relative Bearings (RB) should closely track each other.At all times however HAZI = P1AZ - RB (Relative Bearing) Tool rotation should bekept to a minimum. More than 1 tool rotation per 100ft and the log should be runagain.CorrectionsEMEX Corrections Necessary for STAR tool logs only. Star tool data is recorded in 2byte words and then converted to 4 byte words after multiplying by 4. The gain ofeach pad changes when conductivity limits are reached. This needs to beaccounted for before processing.

De-stripe / button normalise Normalising all buttons on each pad is often requiredwhen one pad has a heavy striping effect on the plotted image. Stripping typicallyoccurs when there is a bad contact usually corrosive on one of the buttonsconnectors. This is can be overcome by better tool maintenance,a simple tool pad calibration or normalizing software.Compute Accelerometer corrected depths If the borehole is rugose and washoutor the image tool caliper arms are deployed hard against the borehole wall, thetool may stop momentarily and 'jerk' up the borehole. This change in accelerationmust be corrected for before any sedimentology interpretation is performed.

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Apply Accelerometer corrected depths Errors in the accelerometer data can resultin an image worse than the original. It is recommended computing the correctionbut not applying to the image itself.Pad / Button Depth Shifts As can be seen from the tool diagrams above, pads andpad button rows do not measure the formation at the same depth at the sametime. Each pad and pad button row needs to be shifted to ensure they are all

measuring at the same depth.Tool tilt and swing arm corrections All efforts should be made to ensure, thedipmeter image tool is centralized at all times in the borehole. Occasionally due toborehole washout, the tool is tilted and not central in the borehole. In these casestool tilt corrections must be applied. Borehole size changes will also dramaticallyaffect the dip interpreted by the image interpretation. Swing Arm corrections mustalso be applied before interpretation.Compute 6 calipers from Sonic image transit times Borehole caliper measurementscan be derived from the time taken for Sonic images to reflect off the boreholewall back to the tool.InterpretationStandard Formation Dip Processing Formation dip and direction can be determinedfrom the standard correlation curves using dipmeter correlation programs.

Changes in bed boundary resistivity can be matched to opposing dipmeter arms todetermine the dip angle and direction of the formation bed.Image Log Interpretation Using the recent image log technology, formation dip anddirection can be graphically determined from the image plots. The userinteractively generates dips from the image by select 3 points that define a planefrom the image plot. This approach has become highly sought after for severalreasons.

Dips can be assigned different categories like structural dip, open fracture

etc.

Each dip category can be edited and displayed in any combination.

Image dips are considered to have 100% confidence, where as computer

processed dips have varying degrees of confidence.

The borehole image itself allows the formation geology to be studied andinterpreted. Paleontology of the image can be performed helping to interpret theexistence of bugs and fossils. Sedimentology interpretation helps determine theprocess of deposition and diagenisis or post sedimentology changes.

Thin Bed Total Thickness Since the dipmeter imaging tools have a far greatersampling rate and therefore greater vertical resolution than standard loggingtools, a more accurate thin bed analysis can be calculated. The detail of the imagelog makes it ideal for fracture detection both open (sudden low resistivity) orclosed or healed (sudden high resistivity).

Tooltype

Button shift Pad shift

FMS Row2 of all pads by

0.3inches

No shift

FMI Row2 of all pads by 0.3inches

Flap pads by+6.0inches

EMI Row2 of all pads by 0.3inches

Pads 2,4,6 by 2.5inches

STAR Row2 of all pads by 0.3inches

Pads 2,4,6 by 3.4inches

Borehole Breakout and Formation Stress The imaging tools have 2-6 caliper armmeasurements that determine the existence of any borehole ovality. Boreholeovality helps indicate principle formation stress directions. The direction ofbreakout is the direction of weakest formation strength and is perpendicular to theprimary stress direction.

SONIC LOG

APPLICATION:

o Porosity PHIS

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o Volume of clay VSo Lithology

o Time-depth relationship

o Reflection coefficients

o Mechanical properties

o VDL/CBL

By combining sonic and Checkshot data we can calibrate down hole log data withsurface seismic data. Mechanical properties can be determined from the shearand compressional waves, fracture identification from shear and Stoneley wavesand permeability indication from Stoneley waves.

THEORY OF MEASUREMENT:

Transmitter emits sound waves into the formation and measures the time taken to detectat a receiver of known distance from the transmitter. The Sonic tool operates at 20 cyclesper second as sounds similar to a pedestrian crossing at a set of traffic lights. The firstarrival is the compressional or 'p' waves, which travel adjacent to the borehole as shownin Figure 1. It is this arrival that is used to measure the individual travel times T1, T2, T3,

and T4. Two receivers for each transmitter eliminates the borehole signal. The transit timeDT is computed from these travel times as shown in the equation below. This particulararrangement of sonic tool transmitters and receivers is known as the standard BHC Sonictool and compensates for borehole washouts and also for tool tilting in real time whilelogging.

DTLOG = [(T1 - T2) + (T3 - T4)] / 2

T1 and T3 travel times have a Tx-Rx spacing of 5 feet and T2 and T4 travel times have aTx-Rx spacing of 3 feet. This results in a DT of 2 feet and is also the vertical resolution ofthe tool. The shear signal arrives next which usually has a slightly larger amplitude thanthe compressional arrival, then mud arrivals and Stoneley waves. The various arrivals in

the received sonic signal can be seen in Figure 1. Stoneley waves are used to interpretthe existence of fractures.

Long Spaced Sonic tools

Long spaced sonic tools have a larger spacing between the transmitter and receiver. Toolspacing are 8ft-10ft and 10ft-12ft. This allows a deeper depth of investigation andimproves the tool response in larger boreholes or where mud invasion is affecting thestandard tool. The DT measurement requires the 8ft-10ft signals to be memorized untilthe 10ft-12ft signals are recorded and then a DT can be computed. This is known asDepth Derived Borehole Compensation or DDBHC. The long and short spaced sonic toolscan be used in combination to identify swelling shales.

The Array or Full Waveform Sonic tools

Recent advances have seen the emergence of digital or array sonic tools where the entirewaveform is digitally recorded for analysis of the individual arrivals. The amplitude as wellas the travel time of the sonic signal can give important information about the formation.Included in the array sonic tool is eight receivers each measuring approximately 1/8th ofthe borehole. This allows eight independent measurements in each direction rather thanan average of the borehole.

1. Full wave mode providing a full waveform analysis. Full wave recording in cased holecan produce a compressional Delta-T with comparable results to the open hole Delta-Tmeasurement. The open hole DT should always be used in preference.

2. DDBHC mode where log spaced 8-10 and 10-12 foot or short spaced 3-5 and 5-7 footlogs can be recorded.3. 6in Delta-T mode where 4 receivers record a long spaced transit time.4. CBL/VDL mode to measure standard 3 and 5 foot cement bond logs in casing.

Dipole/Monopole Operation

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The Schlumberger DSI tool or Dipole Shear Imager, generates monopole and dipolesignals. The dipole signal is directional allowing the inclusion of a shear wave to berecorded in slow formations. The DSI tool generates compressional and shear waves froma 12kHz monopole signal, two orthogonal shear waves from 2.2kHz dipole signal and aStoneley wave from 1-2kHz monopole signal.


Schlumberger BHCLong SpacedBHC

SDT

Depth ofinvestigation

5inches

12 inches12inches

Vertical resolution24inches

24 inches36inches

Halliburton BHC ToolLong SpacedBHC

Long SpacedFWST


16" it is run eccentered to

overcome weak signal amplitudes.

Operation

The Sonic tool has slots in the sonde body to reduce interference from the fastsignal traveling along the sonde itself. This makes the sonde very flexible and thetool should always be made up or connected vertically at the well site to avoidexcessive tool bending and flexing of the fragile internal electronics. Some loggingcompanies insert the Sonic tool into an aluminum sleeve when it is lifted up the rigVdoor from the catwalk for this same reason.

In vertical boreholes 3 spring centralizers should be used to avoid the tool bowing

and to keep the tool centralized. For deviated holes and holes greater than 16",1.5" standoffs should be used instead and the tool run eccentered against theborehole wall. Standard BHC tools can be affected when zones are altered byborehole fluids. Long spaced sonic tools provide a deeper depth of investigationand are therefore preferred in larger boreholes or where mud invasion is affectingthe standard tool.

Cycle Skipping: The problem of cycle skipping occurs if a weak signal is received. The lowamplitude first arrival may be skipped over and not detected. The subsequentarrival is usually larger and often detected instead, thus a cycle has been skippedshowing a longer than true transit time. Cycle skipping occurs in washed outboreholes and unconsolidated formations.

Road Noise:The problem of road noise can occur from tools dragging against the boreholewall. Road noise increases the background amplitude and as a result increases thepossibility of detection before the first compressional arrival. Road noise creates afaster than true sonic transit time. Only slowing the logging speed can possiblyreduce road noise. Recent advances in Sonic tools lock onto the compressionalarrival within a window interval using computer software techniques. Faster noisearrivals are ignored and so are slower shear, mud and Stoneley arrivals.

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FIGURE 1: SONIC CYCLE SKIPPING AND NOISE TRIGGERING

Long Spacing Sonic Tools:A long spacing Sonic (which has longer spacing between transmitters and

receivers) reads only slightly deeper into the formation but enough to be lessaffected by swelling shales. As a result the standard 3 and 5 foot spacing transittimes will read slightly slower in swelling shales than the longer 9 and 11 footspacing Figures 4 - 8 show examples of cycle skipping, noise and casing signalalong with the corrected sonic longs

Presentation

Presentation is usually 140-40 us/ft (or 500-100 us/m) across tracks 5 & 6

FIGURE 2: TYPICAL SONIC LOG PRESENTATION

TOOL COMBINATIONS:

The Sonic tool can be run alone but is usually run at the top of the Resistivity tool with theopen hole Gamma Ray tool above the Sonic. The resistivity/sonic service is usually thefirst logging run since the string is cheaper, usually centered and has no radioactivesources.

LQC/CORRECTIONS:

Log Quality Control

To adequately prepare for the possibility of cycle skipping and/or road noise, eachtravel time (usually T1, T2, T3 and T4) should be monitored on a screen while

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logging so the threshold can be lowered to detect low amplitude arrivals but alsoraised to avoid detection of any road noise.

If several transit times (usually DT, DTL, DTLF, DTLN or some variation of these)complement each other then an accurate DT measurement can be made.

Corrections for tool tilting and borehole wash-out can be performed in real timewith the standard BHC Sonic tools.

A sonic reading of approx. 57us/ft (187us/m) should be observed in the surfacecasing with no cement both before and after the logging run.

Environmental Corrections

Computer editing of cycle skipping and noise effects is often necessary to obtainan accurate Sonic log.

Borehole Effects:

The presence of gas in the well will severely attenuate the sonic signal and mayresult in extensive cycle skipping. In altered or invaded zones, employment of along spaced sonic tool will read deeper into the formation bypassing any swellingshales. Washed-out holes or caves attenuate the sonic signal resulting in cycleskips. Fractures significantly attenuate the shear and Stoneley waves.

. MaterialDelta-T(us/ft)

Non Porous Anhydrite 50

Solids Calcite 49.7

. Dolomite 43.5

. Granite 50.7

. Gypsum 52.6

. Limestone 47.6

. Quartz 52.9

. Salt 66.6

. Steel 50

. Casing 57.0

WaterSaturated

Dolomites (5-20%) 50.0-66.6

Porous

Rocks Limestone (5-20%) 54.0 - 76.9

. Sandstones (5-20%) 62.5 - 86.9

.Sands (unconsolidated -20-35%)

86.9 - 111.1

. Shales 58.8 - 143.0

Liquids Water (pure) 208

.Water (100,000mg/L ofNaCl)

192.3

.Water (200,000mg/L ofNaCl)

181.8

. Petroleum 238.1

. Mud 189

Gases Hydrogen 235.3

. Methane 666.6

InterpretationHydrocarbons:

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It is generally considered that hydrocarbons have no significant effect on the Sonictransit time.

Fractures/Vugs and Stoneley Analysis:

The Sonic tool tends to ignore the effect of fractures or vugs, which result in

secondary porosity. The Sonic tool therefore measures primary porosity only whichis less than true total porosity if fractures or vugs exist.An increase in the permeability or in the number of fractures present willattenuate the Stoneley wave. Low frequency Stoneley waves are more sensitive topermeability and fractures. If a low pass 4kHz filter is applied to the sonic signal,the Compressional and shear waves are removed and the remaining Stoneleywave can be analyzed.

Porosity Effects:

The Sonic porosity is used for interpretation to complement the porositymeasurements obtained from the Density and Neutron tools.

FORMATION TESTING First used in the early 1980's

Early tools suffered poor resolution and accuracy of pressure gauges.

Often good formation seals could not be monitored in real-time.

APPLICATION

Measure formation pressures accurately

Take several formation fluid samples without mud filtrate contamination

Take true PVT samples Estimate formation permeability and formation damage

Determine gas/oil/water gradients and fluid contacts

Rw and Sw determination


Operation

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FIGURE 1: SCHEMATIC REPRESENTATION OF THE WIRELINE FORMATIONTESTER

The Wireline Formation Tester is lowered in the hole until the snorkel is oppositethe zone of interest. Tool hydraulics is deployed to open the rubber packer and

backup arms and seal against the borehole wall. Hydraulic pressure, 1500psiabove hydrostatic pressure is usually sufficient to obtain a good seal. This stopsany borehole mud contaminating the formation fluid sample being tested. Thesnorkel is then deployed or extracted at various rates and volumes, to draw theformation fluid into the pre-test chambers of the tool. Pre-test chambers aretypically 0-30cc in volume. After a few moments the snorkel deployment is thenceased and the formation pressure build-up is then monitored and recorded.Further deployment of the snorkel will draw the formation fluid into samplechambers attached at the bottom of the tool. The fluid samples are stored atformation pressures that help in determining hydrocarbon composition.

Depending upon the formation permeability, pressure build-up times can varyfrom seconds for high permeability (>5mD) to hours for low permeability

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Wireline Formation Tester tools can typically operate in borehole sizes rangingfrom 7" to 19" in diameter. This depends upon the design of each tool and it'sspecifications.

FIGURE 2: TYPICAL PRESSURE PLOT VS. TIME

Advances in Sample Detection

Early tools could not distinguish between mud filtrate and virgin formation fluidbefore sampling. Advances in the sampling operation have included resistivitymeasurements to distinguish between mud filtrate, formation water andhydrocarbons. Once a change in resistivity is detected the sampling operation canbe engaged and formation fluids (water or hydrocarbons) can be sampled.Implementation of Density fluid sensors will further distinguish between the gasand oil

FIGURE 3: DISTINGUISHING BETWEEN MUD FILTRATE AND FORMATIONFLUIDS

Sample Chambers

Several types of sample chambers are available. Figure 5 shows a multiple samplechamber allowing multiple zones to be sampled during one in the hole. Figure 6shows a PVT sample chamber, where formation fluids are maintained at reservoirpressures. This is critical in determining hydrocarbon composition in the reservoir.

FIGURE 4: MULTIPLE SAMPLE CHAMBER

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FIGURE 5: PVT SAMPLE CHAMBER


The Wireline Formation Tester can sample formation fluids at several feet into theformation. Depending upon permeability and mud invasion, the tool ideally readsthe virgin formation fluid beyond the zone invaded with mud filtrate.

The snorkel has a diameter of approximately 0.5 inches

Specifications

Petroquartzgauges

Straingauges

Tolerances

0.5% offull scale

+/-1psi

Resolution

0.01psi 1psi

Repeatability

1psi 3psi


Limitations

High-pressured borehole mud can cause differential sticking if the tool is samplinga single point for a long period of time. The Wireline Formation tool is the mostcommon wireline tool that becomes stuck in the hole. Sticking occurs since thereare very large sample chambers, typically 2.6 and 5 gal (10ltrs and 19ltrs)attached to the tool. Some Wireline Formation tools sample only formation fluidsand therefore only require small sample chambers of approximately 600mL. Withlarge sample chamber tools, sampling period greater than one hour should betreated with care. Long sampling periods often occur in where the formation

permeability is low.Earlier tools had no means of determining if the tool was measuring virginformation fluid or the invaded mud filtrate. Modern tools measure the fluidresistivity and density and display this at the surface for the logging engineer toview. The engineer is then able to make real time decisions as to whether the fluidis mud filtrate and if not then decide if the fluid is formation water, oil or gas.

Presentation

Presentation of the Wireline Formation Tester has changed little over the years.The data is sampled as an increment of time rather than depth like typical loggingtools. The sample pressure is displayed in track 1 and also numerically in theusually "depth" track. The remaining tracks display each significant digit of thesample pressure. Track 3 displays units of 1000psi, Track 4 units of 100psi, Track 5units of 10psi and Track 6 units of 1psi. In this way small pressure changes can bemonitored graphically.

TOOL COMBINATIONS

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The Wireline Formation Tester tool is run with a depth control device usually a GammaRay tool.

Associated Mnemonics

Early Tools

RFTRepeat Formation

TesterSchlumberger

Fixed pre samplevolume

Variable presample rate

SFTSelective Formation

TesterHalliburton

Variable pre samplevolume

Fixed pre samplerate

Modern Tools

FET Formation Evaluation Tool Crocker Research

MDT Modular Dynamics Tester Schlumberger

RDT Reservoir Description Tool Halliburton

RCI Reservoir Cauterization Tool Baker Atlas


The Formation Tester tool can measure pressures up to 10,000psi. Formationpressures are usually up to 200psi below the borehole hydrostatic pressures.


Log Quality ControlUpon entry into the well bore, the tool should be tested at regular depths forborehole or hydrostatic pressure. If the mud weight is known the hydrostatic

pressure at specific depths can be calculated (say every 500m). This givesconfidence that the tool is measuring fluid pressure accurately. Hydrostaticpressure can be calculated by the following: -

Hydrostatic Pressure = Depth*(0.052*Mud Weight)

Where: Hydrostatic Pressure is in units if psiDepth is in units of feetMud Weight is in units of lbs/gal

The packer hydraulic pressure should be monitored at all times during sampling toensure it is approximately 1,500psi above borehole hydrostatic pressure. This

ensures data samples are not contaminated with borehole mud.

Ultimately, a valid formation pressure test or fluid sample is essential. Once thetool packer is set, the pre sample pressure should be drawn down below theexpected formation pressure. If pressure build-up stabilizes but is still below theborehole hydrostatic pressure, then it can be concluded that a sufficient seal fromthe borehole mud has been achieved and the fluid being pressure tested orsampled is fluid from the formation. If the pressure does not build-up within areasonable time, then the tool should be reseated and another formation pressuretest or sample is performed. At all times the standard wireline log measurementsshould be viewed to determine if the hole is washed out (creating difficultyobtaining a packer seal) or if a shale zone is being tested (creating tight lowpermeability tests).

Low pre-test volumes and sample volumes should be used in low permeabilityformations to enable pressure build-up times to be reduced.

In unconsolidated sands, slower flow rates maybe required to reduce sand flowinto the probe of the Formation Tester tool.

Corrections

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No environmentally corrections are applied to the Formation tester.

InterpretationPermeability from Pre-test Draw down:

Tools that are able to perform draw down at various rates can determinedraw down permeability and formation damage.

K = 921.3(CQu)[1-(rp/re)]/dP

Where: k = permeability in mdarcies, dP = draw down pressure in psi, C =flow shape factor between 0.5 and 1, Q = flow rate in cc/sec

u = fluid viscosity in cp, rp = probe radius in inches, re = effectivedrainage radius in inches,

Where: re = .394(CV/phi)^(1/3) and V = pre-test volume and phi =formation porosity.

Permeability from Pre-test Buildup:

FIGURE 6: PRESSURE BUILD-UPS FOR VARIOUS PERMEABILITYS

FIGURE 7: EFFECT OF SATURATION ON RELATIVE PERMEABILITYFOR OIL AND WATER

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FIGURE 8: CYLINDRICAL AND SPHERICAL FLOW

Cylindrical Buildup

When the bed thickness is relatively small, a cylindrical build-up dominatesthe formation fluid flow to the probe. The build-up is a function of thehorizontal permeability only. If pressure is plotted verses the cylindricaltime = log[(T+dT)/dT], a straight line results. This is called a Horner plot.Permeability is given by: -

kc = -(88.4Qu)/(Mh)

where: -

kc = cylindrical permeability T = sampling time for Q

Q = flow rate in cc/sec dT = elapsed time after shut-inu = fluid viscosity in cp M = slope of Horner ploth = bed thickness in ft

FIGURE 9: CYLINDRICAL PRESSURE VS. TIME PLOT

Spherical BuildupA spherical build-up will exist, with large bed thickness typically greaterthan 30ft. If pressure is plotted verses the spherical time = (dt)^-0.5 -(T+dT)^-0.5 a straight line again results. Permeability id given by: -

ks = 1856u(Q/M)^2/3(phiCt)^1/3where: -

ks = spherical permeability T = sampling time for QQ = flow rate in cc/sec dT = elapsed time after shut-in

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u = fluid viscosity in cp M = slope of Horner plotCt = virgin fluid compressibility phi = formation porosity

FIGURE 10: SPHERICAL PRESSURE VS. TIME PLOT

Fluid Pressure gradients:The change in pore pressure with depth can be plotted to indicate pressuregradients. Different pore fluid density exhibit different pressure gradients. Ifthe pressure gradients are extrapolated and they intersect each other, thewater-oil and the oil-gas contact points can be determined.

Hydrocarbon density can be determined since the formation pressuregradients are a function of the fluid density as follows:

Pore fluid density (g/cc) = Pressure gradient (psi/ft) * 2.3071

Oil and Gas saturation and production from fluid sample:Once the fluid sample has been recovered and the salinity of the sample,mud filtrate and formation water can be measured, the percentage offormation water can be estimated by:

Sw = (Csample - Cmf) / (Cw - Cmf)

If the fluid sample volumes can be measured, then the water cut % can beestimated by:

Water cut (%) = (volume formation water)/(volume oil + volume formationwater)

GAMMA RAY LOG

APPLICATION

Standard Gamma Ray Applications:

o Primary depth reference for all logging runso Correlation from well to well

o Lithology identification

o Identification of organic material, permeable beds and source rocks

o Fracture identification

o Calculate clay volumes

o Mineral analysis

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Natural Gamma Ray Tool (NGT) Applications:

o Detect, identify and evaluate radioactive minerals

o Identify clay type and calculate clay volumes

o Provides insight into depositional environment and the diagenetic history

o Uranium response of NGT is sometimes useful as a moved fluid indicator

o Permeable beds may have higher Uranium salt content than lesspermeable beds.

The Gamma Ray log is typically run with most logging runs as a correlation toolsince natural Gamma Rays can pass through casing. Production tools andperforating equipment can be accurately positioned using the Gamma Ray as acorrelation tool. Slim hole Gamma Ray tools, 1 11/16", 1 7/16" and 1" in diameterfor example, can be run through tubing to correlate TCP (Tubing ConveyedPerforation) guns on depth. A Gamma Ray tool can be run in boreholes with up to20,000psi, 350degF and less than 24 inch hole diameter


There are two types of Gamma Ray measurements used by the wireline logging industry.

Naturally occurring Gamma Rays:

These are Gamma Rays that occur naturally in the formation and have relativelylow energy levels. Tools that measure natural Gamma Rays are known as standardand gamma spectrometry tools. Standard Gamma Ray tools measure theoccurrence of all Gamma Rays. Spectrometry Gamma Ray tools also measure theGamma Ray energy levels and therefore determines the concentrations of thethree normally present radioactive elements namely Uranium (Ur235/238),Potassium (Isotope 19K40) and Thorium (Th232). These have long half-lives and

their radiation energy level is like a material fingerprint that is unique to thematerial being measured.

Induced Gamma Rays:

Tools such as gamma - gamma logs use a high energy Gamma Ray source tomeasure other formation parameters - see Density log and Neutron log

FIGURE 1: EMISSION SPECTRA FOR POTASSIUM, THORIUM AND URANIUM

SERIES

How are Gamma Ray's measured?

Typically two types of Gamma Ray detectors have been used in the industry, theGeiger Mueller and Scintillation crystals. The Geiger Mueller is more reliable androbust but the Scintillation is more accurate. When a Gamma Ray strikes thecrystal a single photon of energy is emitted. A burst of electrons are then emittedas the photon hits the photocathode. The electrons multiply as they hit several

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anodes in an electric field until a small electric pulse is produced. Each electricpulse is produced from a single detected gamma ray.

FIGURE 2: GAMMA RAY DETECTOR TUBE

Gamma Rays occur naturally and at random as bursts of energy over time. Toreduce statistical variation in the Gamma Ray measurement, logging companiestake an average reading over time. The recommended time constant is 2 seconds.As the tool is gradually moving up the hole this 2-second delay will cause a timelag. A logging speed of 30ft/min (1800ft.hr) means that the tool will move 1ftevery 2 seconds. Logging too fast will cause the Gamma Ray log to be off depthwith other logs unless the time constant is changed for example a log at 60ft/min(3600ft/hr) requires a time constant of 1 second. The witness should closelymonitor logging speed as a quality check. The higher the time constant the moreaccurate the Gamma Ray log since it has a lower statistical variation. A timeconstant of 4 seconds would be preferable but the 15ft/min (900ft/hr) loggingspeed required, results in increased rig time and thus increased expense. The 2-

second time constant is an acceptable compromise.

The slower the logging speed the more accurate the measurement. Loggingspeeds of 30ft/min (1800ft/hr) produce accurate results. For quick correlationpurposes speeds up to 100ft/min (6000ft/hr) can be used with acceptableaccuracy.


Depth of investigation of the standard Gamma Ray tool is approximately 10 inchesand that of the Spectrometry Gamma Ray tool is approximately 15 inches

Vertical resolution of the standard Gamma Ray tool is approximately 10 inches andthat of the Spectrometry Gamma Ray tool is approximately 15 inches


Limitations

A Gamma Ray tool can be run in boreholes with up to 20,000psi, 350degF and lessthan 24 inch hole diameter.

Gamma Rays travel in a random manner and not in a continuous flow. The GammaRay measurement is therefore affected by statistical variations. Lower logging

speed may be required to reduce this.

Presentation

The Gamma Ray is presented in track 1 by a thin continuous line with themnemonic GR or a variation of this. Typically a scale from 0 to 200 with units ofAPI. The right scale can be reduced to 150 or 120 if Gamma Ray activity is low.

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Alternatively Spectrometry Gamma Ray tools can also present the followingcurves: -

1. Total Gamma Ray (SGR)2. Uranium free Gamma Ray (CGR) - to distinguish permeablestreaks with high Uranium.3. Ratio Th/K - to distinguish between minerals

4. Ratio Th/U - to distinguish between minerals

FIGURE 3: TYPICAL SPECTROMETRY GAMMA RAY LOG

The SGR curve has Uranium removed to produce the CGR curve. Notice in Figure 5that Uranium is negative and when removed from SGR, CGR becomes larger thanSGR. Although Uranium is actually present in the formation the problem is that theNGT tool is poorly calibrated.

TOOL COMBINATIONS

The Gamma Ray tool is almost always used with every logging suite to correlatesubsequent logging runs on depth with the first original logging pass. The Gamma Raytool is usually connected at the top of the tool string.

The Gamma Ray tool must be handled gently. Rough treatment or heavy impacts cancrack the crystal and this will need to be replaced before logging.

LQC AND CORRECTIONS


In a clean formation (void of shale), the Gamma Ray measurement is low, typicallyaround 20-30 API. A shaly formation can have Gamma Ray readings varyingbetween 80 and 300 API

Environmental corrections to be made

Large boreholes and high-density mud's (often containing barite) decrease theGamma Ray count rate as the mud "shields" some Gamma Rays before reachingthe tool. Similarly a tool centered in the borehole receives less Gamma Ray countsthan an eccentered tool up against the bore hole wall. An eccentered Gamma Rayis preferred since it requires less correction. A Gamma Ray tool run in KCl mud willreceive more counts by virtue of the increased Potassium content in the mud.

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Thus corrections are made for: -

1. Hole size and mud weight.2. KCl mud correction3. Casing size and weight4. Cement thickness

Interpretation

The most common naturally occurring radioactive elements are 19K40 isotope, Th232 and Ur235/238. The "average" shale contains 2% potassium, 12-ppmthorium and 6ppm uranium. A high Gamma Ray measurement therefore usuallyindicates a shale sequence. The Gamma Ray tool is often used as the primaryindicator of shale content. The percentage of rock that is considered shale and notrock matrix can be estimated by: -

Vshale = (GRlog GRclean)(GRshale - GRclean)

The Gamma Ray appearance can be used to help identify different depositionalenvironments and therefore used as a stratigraphic tool.

As stated before, the Spectrometry Gamma Ray tool measures not only thenumber of Gamma Rays returned but also their individual energies. Each energylevel is a characteristic of the type of formation being logged. Analysis of thepotassium, thorium and uranium energies can help indicate fractures, mineralogyand clay type.

Kaolinite has almost no potassium where as Illite contains between 4% and 8%potassium. Montmorillonite contains less than 1% potassium.

The ratio's U/Th, U/K and Th/K can be used to indicator fractures. The individual U, Th and K concentrations when combined with other tools help determinemineralogy and clay type.

INDUCTION LOGGING

APPLICATION

The Induction log was introduced to measure the formation resistivity in fresh or oil-based

mud and is used to detect the presence of hydrocarbon bearing zones. The tool wasdeveloped from mine detector technology developed during the Second World War.

By analysing resistivity measurements, we can differentiate between formationscontaining conductive and non-conductive fluids. Conductive fluids in the formationusually consist of water or mud filtrate and non-conductive fluids consist of oil and gas.

Using equations such as the Archie formula shown below, we can establish the relativeproportions of hydrocarbons and water resident in the formation: -

Rt = aRw /(PHIm Sw

2)Where:-

Rt = Formation ResistivityRw = Formation water resistivitySw = Percentage of water in pore space (WaterSaturation)F = Formation Factor = a/PHIm

PHI = Formation Porosityn = 2, Saturation componenta and m, experimentally determined constants

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where a is close to 1 and m is close to 2


Most resistivity logs measure from 10 to 100 ft3 of material around the sonde, howeverthe micro-resistivity log measures only a few cubic inches of material near the borehole

wall. Resistance (R-Ohms) is related to current (I-Amps) and voltage (V-Volts) according toOhms law and is described by: -

V= IR

Resistivity (R) can be defined as the property of a material that resists the flow of electriccurrent, and is the voltage required to pass one amp through a cube with a one metersquare face area. The unit of measurement is Ohm-meter2/meter (ohm m2/m or ohm m).If two pieces of material were placed end to end they would still have the same resistivitybut twice the resistance.

Resistivity = RA/L = KR = KV/I

Where:-R = resistanceA = cross sectional areaL = lengthK = Geometric constant

The Induction logging tool determines resistivity by measuring the formation conductivity. The Induction tool induces and focuses an electromagnetic field into the formationadjacent to the tool by generating an alternating current source in the primary coil. Thisinduced electromagnetic field will produce a measurable current and potential in thereceiver coil of the tool proportional to the formation conductivity. The primary andsecondary windings of a common transformer are a simple analogy. The measuredvoltage in the receiver coil is then used to determine the formation conductivity and thus

the formation resistivity. Conductivity is the inverse of resistivity (1/resistivity) and hasthe units of mho/m. Formation resistivity is computed using the following formulae:-RILD = 1000/CILD where:-RILD= Resistivity (ohmm)CILD= Conductivity (mmho/m)

The Direct Coupling signal is the 'In'phase or X-Signal and the Formation Signalis the 'Out' of phase or R-Signal

FIGURE 1: INDUCTION MEASUREMENT PRINCIPLE

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FIGURE 2:

DILTOOL

The deep measurement ILD uses a different transmitter/receiver spacingto that of the medium measurement ILM enabling two different depths ofinvestigation into the formation. The standard Induction tool (known as6FF40/28 series) uses a total of 6 coils, which are used in pairs to improve

focusing and thus vertical resolution of the Induction measurements. Thedeep measurement receives no signal from the first 40 inches surroundingthe tool with a transmitter/receiver spacing of 40 inches. The mediummeasurement has a transmitter/receiver spacing of 28 inches. Ideally thedeep measurement will read primarily the uninvaded zone resistivitydepending upon diameter of invasion and the medium measurement willread more of the transition and some flushed zone resistivity dependingupon diameter of invasion. Usually a small focused laterolog measurementis incorporated in the Induction tool to measure the flushed zone resistivitydepending upon diameter of invasion. These measurements requirecorrections for borehole and invasion effects. This will be described inSection 6.0. MWD logs have less invasion effects since they measure theformation immediately after drilling before the mud cake is formed andinvasion has ocurred. The process of giving greater emphasis tothe coils atthe centre of the tool in preference to those coils either side is termeddeconvolution. Modern Phasor Induction tools use the dielectric or X-signalto make a non-linear deconvolution correction. This X-signal was ignored inearlier tools. An Array Induction tool measures 28 independent signalsfrom 8 arrays.


Halliburton DIL

Tool Deep(ILD) Medium(ILM) Shallow(LL3)

Vertical resolution 60 inches 54 inches 6 inches


65 inches 30 inches 14 inches

Schlumberger DIT-ETool

ILD IDPH IDER IDVR

Vertical resolution72-84inches

72-84 inches36inches

9-24inches

Depth of investigationDeep 90inches

Medium 40inches

Schlumberger AITTool

3 Vertical resolutions12, 24 and 48 inches

5 Depths ofinvestigation

10, 20, 30, 60 and 90inches

LIMITATION/OPERATION/PRESENTATION

Limitations

The Induction tool is design to accurately measure formations less than 20ohmm

(50mmhos). Accuracy is reduced up to 200ohmm (5mmhos) and large correctionsand errors occur above 200ohmm (5mmhos). Often the sonde error itself is 3-4mmhos and if this is removed from a 200ohmm (5mmhos) raw signal, a correctionof close to 100% is required giving less and less confidence to the recorded data.

The principle operation of the Induction tool is to actually measure the formationconductivity. As the formation conductivity is reduced (and formation resistivity isincreased) the Induction tool will measure more of the relatively conductive mud.A Phasor Induction tool will overcome some of the problem. The Induction tool

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therefore operates best in high resistivity drilling mud (ie fresh water), oil baseddrilling mud and also in air.

The placement and polarity of the receiver coils effect the depth of investigationand the vertical resolution of the tool.

The Induction tool is preferred over the Laterolog tool

typically when the following conditions apply: -

1. The Rmf/Rw ratio is greater than 2.52. When the formation resistivities do not exceed 200 ohmm3. The bed thickness is greater than 10 ft.

When the porosity is below the Rw line but Rmf/Rw is still above 2.5, eddy currentsare not able to be induced as efficiently and the Laterolog tool rather than theInduction tool could alternatively be used.Skin EffectEach Inductance coil is not independant of other coils in the Induction tool.Additional voltages are induced not only from neighbouring coils but also from the

coil itself. This is known as mutual-inductance and self-inductance respectfully. Theis that the strength of the field is reduced resulting in a higher than true resitivityreading. Skin is a inversely proportional to the formation conductivity, magneticpermeability and the transmitter frequency. Thus the higher the transmitterfrequency, the less skin effect. Correction for skin effect is usually only performedon the deep measurement. The medium measurement is usually less than 1% as aresult of the shorter coil spacing.

Operation

The logging speed is approximately 6000 ft/hr but is usually run at 1800 ft/hr whenrun in combination with other logging tools. Standoff sizes are critical fordetermining the amount of borehole correction to be applied. In holes above 8.5

inches, the tool is run eccentered with 1.5 inch standoffs along the tool. Thefollowing table gives recommended standoff sizes.

Hole Size

StandoffDistance

9.5 inches 2.0 inch

Presentation

The deep Induction log is presented in track 3-4 (logarithmic) by a thindashed line with the mnemonic ILD. The medium Induction log is alsopresented in track 3-4 (logarithmic) by a thin dotted line with themnemonic ILM. The shallow focused resistivity log (alternatives are theShort Guard) is presented in track 3-4 (logarithmic) by a thin continuousline with the mnemonics SFLU or some. variation of this. The scale typicallyranges from 0.2 to 2000 with the units in Ohmm.

TOOL COMBINATIONS

The Induction tool can be run alone but is usually run at the bottom of the Sonic tool withthe open hole Gamma Ray tool at the top. The resistivity service is usually the firstlogging run since the tool is cheaper, usually centered and has no radioactive sources.

Tool types available

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DIT-D Standard Dual Induction Tool containing 6 coils for focusing signals toimprove vertical resolution.

DIT-E Phasor Dual Induction Tool. The Phasor tool also measures the in-phase(resistive) and the quadrature (dielectric) signals.

AIT Array Induction Tool. The AIT measures 28 independent signals from 8arrays. The single transmitter operates at 3 different frequency and the in-

phase (resistive) and the quadrature (dielectric) signals are measured. TheAIT measures signals AIT10 (10 inches into the formation), AIT20 (20inches into the formation) etc up to AIT90. A combination of these is usedto compute an Rt value, however if one of these readings is affected bymicro annulus the computed Rt can be inaccurate.

LQC/CORRECTIONS

Log Quality Control and Interpretation

Permeability can be indicated by the separation of the resistivity readings for ILD,ILM and SFLU. This occurs when the higher-pressure borehole mud invades into the

formation displacing the original formation fluid. Ideally SFLU measures theinvaded zone (Rxo fully flushed by borehole mud), ILM measures the transitionzone (partially flushed by borehole mud) and ILD measures the un-invaded zone(virgin formation fluid).

The Rxo < ILM < ILD profile will exist if Rw > Rmf or the profile ILD < ILM < Rxowill exist if Rw < Rmf. If no permeability exists and therefore no mud invasion, astypically is the case with shales, the deep, medium and Rxo measurements willoverlay unless environmental corrections still need to be applied.

While logging check that SP deflections are normal (to the left if Rxo > Rt) and notnoisy. Check that resistivity readings do not flat top in high resistivity beds andthat the deep and medium measurements remain symmetrical and on depth.

The measured formation resistivity is a function of:

1. The formation water resistivity2. Lithology changes3. Porosity changes4. Changes in the mud-filtrate resistivity, which often occurs between loggingruns.

Solid rock and hydrocarbons will have an extremely high resistivity. A good rule ofthumb is that hydrocarbons are indicated where the RILD > RILM > RSFLU profile exists.

FIGURE 3: VRT CLAY

INDICATOR

The Resistivity can be used as an indicator of claycontent. The percentage of rock that is consideredclay and not rock matrix can be estimated by: -

VRT = (Rsand RT) / (Rsand - Rclay)

In practice this equation is modified and multipliedby 4*Rclay/RT to avoid giving erratic readings. VRT is

usually much too high except when high resistivityformations are present. Since clays are conductive,an Rsand minimum value helps to fix the zero VRT point.

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LATEROLOG TOOL

APPLICATION

The Laterolog tool was introduced to measure the formation resistivity in salty or highconductive mud and is used to detect the presence of hydrocarbon bearing zones.

By analyzing resistivity measurements, we can differentiate between formationscontaining conductive and non-conductive fluids. Conductive fluids in the formationusually consist of water or mud filtrate and non-conductive fluids consist of oil and gas.

FIGURE 1: CLEAN UNIT OF

FORMATION

Using equations such as the Archie formula

shown below,we can establish the relative proportions ofhydrocarbonsand water resident in the formation:

Rt = aRw /(PHIm Sw

2)Where:-Rt = Formation ResistivityRw = Formation water resistivityPHI = Formation PorositySw = Percentage of water in pore space(WaterSaturation)n = 2, Saturation componenta and m, experimentally determined

constantswhere a is close to 1 and m is close to 2F = Formation Factor = a/PHIm


Most resistivity logs measure from 10 to 100 ft3 of material around the sonde, howeverthe micro-resistivity log measures only a few cubic inches of material near the borehole

wall. Resistance (R-Ohms) is related to current (I-Amps) and voltage (V-Volts) according toOhms law and is described by: -

V= IR

Resistivity (R) can be defined as the property of a material that resists the flow of electriccurrent, and is the voltage required to pass one amp through a cube with a one metersquare face area. The unit of measurement is Ohm-meter2/meter (ohm m2/m or ohm m).If two pieces of material were placed end to end they would still have the same resistivitybut twice the resistance.

Resistivity = RA/L = KR = KV/IWhere:-R = resistanceA = cross sectional areaL = lengthK = Geometric constant

Conductivity is the inverse of resistivity (1/resistivity) and has the units of mhos.

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FIGURE 2:

FOCUSED/UNFOCUSEDCURRENT PATH

The sonde for this resistivity log uses guard or buckingelectrodes to f

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