Petrophysics logging tools

SPONTANEOUS POTENTIAL LOGHISTORY

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 is registered at different points in the hole with respect to surface electrode. Therefore SP is a recording of the difference in potential of a moveable electrode in a borehole and a fixed electrode on the surface. In order to record a potential the hole must contain conductive mud, as it cannot be recorded in air or oil-base mud. 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 three sources of the currents, two electrochemical and one electrokinetic. Deflection of SP 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 result of 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 current flow and hence a potential.

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

FIGURE 2: LIQUID JUNCTION EFFECTS #1

FIGURE 3: LIQUID JUNCTION EFFECTS #2

Em: "Membrane Potential"

Shale’s are permeable to Sodium ions but not to Chlorine ions. Hence there is a movement of charged particles through the shale creating a current and thus a potential. 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 a porous permeable bed. It depends upon the resistivity of the mud filtrate and will only become important if there are high differential pressures across the formation. This process is not well understood and the effects are normally negligible in permeable formations because the mud cake builds quickly and halts any further invasion. In low porosity, low permeability formations, the mud cake builds slowly and the Electrokinetic potential becomes predominate. This is the potential that makes the SP appear to float randomly in very tight formations such as low porosity carbonates. In these conditions the SP cannot be used to determine Rw.

FIGURE 5: TOTAL SP

Deflection of the SP curve The SP measurement is constant but jumps suddenly to another level when crossing the boundary between two different formations.When Rmf > Rw The SP deflects to the left (-ve SP) found in permeable formations filled with formation waterWhen Rmf < Rw The SP deflects to the right (+ve SP) found in permeable formation filled with formation waterThere 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 2-3 inches if highly permeable and more than 2-3 feet if permeability is low.

Vertical resolution of the SP tool is approximately 3 meters

CALIBRATION

In the logging unit there is a small battery and a potentiometer in series between the two electrodes. The logging engineer can adjust the potentiometer so that the SP appears in track 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 while logging and therefore keep the SP on the display track. Recent logging tools record the raw SP on data storage (i.e. no battery and no potentiometer) and it is sometimes preferable to use this raw SP to perform the SP correction. An offset can be applied to the raw SP if its values range significantly above zero.

LIMITATIONS AND PRESENTATION

Limitations Borehole 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 electrode made of mild iron will rust and this oxidizing effect of the electrode results in an added electrochemical potential to the SP measurement. The drift gradually disappears as the electrode becomes fully oxidized. Because this is an undesirable potential, the drift can be removed by correcting the SP curve using computer software. 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 potentials Heavy rain:If heavy rain starts during logging, the surface conductivity of the soil will gradually change and therefore can gradually change the potential between the surface 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, weather storms and lightning strikes will cause the SP to be noisy and at random. No welding 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, this will 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 in the mud pit away from moving mud fluids.Powerlines, electric trains, close radio transmitters and cathodic protection devices all create currents, which disrupt the ground electrode reference causing a poor, sometimes useless log.Bimetallism occurs when two different metals are touching surrounded by mud produces 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 relative scale 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 SP electrode. 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 Mnemonics SP Spontaneous PotentialSSP Static Spontaneous Potential

Typical Log Readings

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

LQC, CORRECTIONS AND INTERPRETATION Log 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 shape of 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 formation waters of different salinities. There is also a shift when two different salinity waters are 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 upper boundary 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 PET tools.

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 not measure cement bond to formation as well as the CBL.

THEORY OF MEASUREMENT

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 hole and cement is pumped to the outside of the casing to seal the casing to the borehole 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 formation fluids will flow into the casing when the productive zone is perforated and not up or down the outside of the casing.

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

The 3-foot signal from the transmitter to the first receiver, will primarily measure the cement to casing bond. If there is little or no bond the amplitude of the signal will be very large. If there is good bond the amplitude will be very small. This is commonly 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 the transmitter to the second receiver. The signal will however read deeper into the formation. It will predominately measure the cement to formation bond. Again a large signal amplitude indicates a bad cement to formation bond and a small amplitude 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 is measured 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 section through the positive peaks that is displayed on the VDL track as if viewed from the top of the waveform.Depth of Investigation and Vertical Resolution

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


Limitations The borehole must have fluid in the well bore in order for acoustic coupling to occur.

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Presentation

FIGURE 2: TYPICAL CEMENT BOND LOG

PRESENTATION

FIGURE 3: GOOD FORMATION BOND FIGURE 4: FREE PIPE

TT5 signal is displayed in the pseudo standard VDL presentation. This is a 'Bird's eye 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 open hole gamma ray. A casing collar locator is also used to enable correlation of wireline perforating guns.


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

LQC, CORRECTIONS AND INTERPRETATION

Log Quality Control Micro 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 when the wellhead pump pressure is held too long, causing the casing to expand. When the pressure is released the casing retracts and a thin break occurs between the casing and the cement. Holding of wellhead pressure immediately after the cement job should be kept to a minimum.

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

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

Drilling operations can cause micro annulus. A CBL log run soon after the casing is set 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 poorly centralized and the cement bond will not be accurate.

Corrections Micro annulus is noticeable when the CBL signal is approximately 10-20mV. If micro annulus is suspected, the casing should be pressured to 1000psi well head and the CBL survey run again under the 1000psi pressure. If the CBL signal reduces to below 10mV then micro annulus exists. Micro annulus is not usually a problem for zone isolation.Interpretation The purpose of interpreting the CBL log is to ensure good zone isolation over a productive formation. By viewing the CBL log presentation; a qualitative analysis of the cement bond can be determined. Good Bond: CBL signal - The interval 3307.5-3310.5ft has very good bond between cement and casing by virtue of small CBL amplitude in Track 3 of approx. 4mV. Often at these low amplitudes the TT3 travel time will cycle skip.

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

Free Pipe signal:

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CBL signal - Here you can see that the free pipe signal is reaching a maximum of approximately 62mV. There is some cement scattered around the pipe that is reducing the CBL signal in places but essentially this is still free pipe. There is no continuous cement seal to the casing. The TT3 is reading 280usec and the free pipe 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 lines representing casing arrivals. The thicker formation arrivals are also relatively straight 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 pore space on the formation rock which is filled with water, oil or gas. Together with other tools like 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 formation at approximately 4MeV. (Plutonium Berilium sources are no longer used since they can be broken down to create atomic weapons). After collisions with the formation, the neutron energy levels fall to between 0.1 and 10eV. These are known as epithermal neutrons. After further collisions neutron energy levels fall below 0.03eV and these are termed thermal neutrons. By virtue of its similar mass to neutrons, Hydrogen more than any other element in the formation slows down the neutrons dramatically. A useful analogy is a billiard ball interacting with a bowling ball or a ping-pong ball. The billiard ball only loses significant velocity when it hits another billiard ball not when it hits a ping-pong ball or bowling ball. Since hydrogen is primarily only present in water, oil and gas, the neutron tool gives a direct measurement of the fluid in the pore space of clean formations. Two detectors, one short spaced and the other long spaced from the source are used to eliminate some borehole effects and detect the number of neutrons returning back to the tool. A low neutron return count indicates the presence of hydrogen and therefore porosity.

FIGURE 3: NEUTRON ENERGY DECAY

Once the neutrons reach the thermal stage, they are ready to be captured. The presence of strong neutron absorbers like Chlorine have a capture cross section about 100 times that of Hydrogen at the thermal level. Thermal neutrons therefore need to be corrected for fluid salinity and matrix capture cross section effects. Epithermal neutrons do not need to be corrected for capture effects but only have one tenth of the population of thermal neutrons. Some neutron tools like the CNT-GA can detect both epithermal and thermal neutrons giving two different porosity measurements. The standard CNT Tool measures only thermal neutrons.


Halliburton Neutron CNT Tool Schlumberger

Neutron CNT Tool CNT Tool Enhanced

Vertical Resolution 24 inches Vertical Resolution 24 inches 12 inchesDepth of Investigation

8-12 inches Depth of Investigation 9-12 inches 9-12 inches

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FIGURE 4: STANDARD DETECTOR RESPONSE

FIGURE 5: DEPTH-MATCHED DETECTOR RESPONSE

LIMITATIONS, OPERATION AND PRESENTATION

Limitations

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

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

Neutrons travel in a random manner and not in a continuous flow. The neutron measurement is therefore affected by statistical variations. Statistical variations can 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) with software 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 than the 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 tools use 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 with scales, 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 and water in the pore space

LQC/CORRECTIONS

Log Quality Control and Interpretation

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

Using compatible limestone scales for density (1.95 RHOB 2.95) and neutron curves (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 neutron curves (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 measured porosityon both the Density tool and the Neutron tool 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 tool bow spring. Environmental corrections that need to be applied for the Neutron log are:-

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 logging company and the specific correction chart should be used for that specific Neutron tool. The Neutron tool response is dependant upon the source strength and detector spacing.


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Mineral NPHI (%)

100% Limestone 0%100% Sandstone -2%100% Dolomite 1%Shale 30-45%Expected log readings 0-45%

DENSITY LOGAPPLICATION

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 also be 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 photoelectric effect to help distinguish between rock lithologies, recognize presence of heavy minerals, fracture identification when barite is present and additional clay evaluation. In addition the density can be used to determine Vclay and to calculate reflection coefficients to process synthetics.

Figure 1: Gamma ray interactions

A 1.5 Ci Cs137 chemical source bombards gamma rays at 662keV energy into the formation. The high-energy gamma rays interact with the electrons of the formation by way of Compton scattering and lose energy in the process. Other processes also occur namely photoelectric absorption and pair production, although pair production only becomes significant at energies above 1MeV. A low number of gamma rays detected through Compton scattering will indicate a high electron density. The bulk density rB has a close relationship to the electron density as shown by the following experimentally determined equation: -

RHOB = 1.0704*RHOe - 0.1883

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

PEF = (Z/A)3.6

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

The photoelectric effect of absorbed gamma rays is directly related to the Z, the number of electrons per atom, which is fixed for each element. Different values of the PE curve indicate different types of formation rock being measured and are independent 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 Density has 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 Determination Since 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 be determined. 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 curves that can match the exploration seismic.


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Halliburton Density

Standard Density

Litho Density

Schlumberger Density Litho Density

Vertical Resolution 7.5 inches 7.5inches Vertical Resolution

18 inches (Standard) 6 inches (Enhanced)

Depth of Investigation 2 inches 2 inches Depth of

Investigation 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 site verifier with small gamma sources is placed on the density tool and a measurement taken. The PEF curve is also calibrated in a similar manner to read 5.085 in calcite and 1.806 in quartz.

Well site calibration checks are performed before and after each logging suite with the well 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 boreholes with 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 contact against 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. Rough treatment or heavy impacts can crack the crystal and this will need to be replaced before logging.

Measurement of detected gamma rays is averaged over a period of time. The slower the logging speed the more accurate the measurement. Logging speeds of 30ft.min(1800ft/hr) with software averaging, produces accurate results.

OPERATION

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

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

PRESENTATION

Presented in track 5 and 6 by a thin continuous line with the mnemonic RHOB. For sandstone 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 line with 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 read less than the true density in shales and as a result the computed density porosity will be higher in shales than the true porosity. In gas bearing formations, RHOB will show a large drop in densityUsing compatible limestone scales for density (1.95 RHOB 2.95) and neutron curves (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 neutron curves (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 of porosity on the PEF measurement is negligible. Basic lithologies can therefore be interpreted 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 the fractionalvolume 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 on boththe 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)*RHOgand

PHI = (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 5.05Salt 2.06 4.65

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Coal 1.68 0.18Hydrogen -0.61Carbon -0.29Water 1 -0.02

Environmental Corrections Log quality is ensured if good contact is made with the borehole wall. As mud cake builds up on the borehole wall, or the borehole wall is rugose, the density tool measures less than true density because it is also reading the less dense mud. The short and long spaced detectors are affected differently by the mud being measured. The amount of correction that needs to be applied to the raw density reading can therefore be determined via the spine rib plot. The corrected density reading is shown on the log and the amount of correction applied is depicted by the DRHO curve.

If a large DRHO occurs but RHOB follows DT and NPHI then RHOB is considered an accurate reading. DRHO can be small indicating little correction applied but RHOB very 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 caliper measurement. Here the tool is simply reading the borehole mud. It is important to check 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 after corrections. Between 3989m and 4008m the DRHO is still very large but RHOB appears good except for a couple of thin streaks. The zone above at 3972m to 3989m has DRHO < 0.05g/cc and RHOB is very accurate.

N.B. In the case of mud containing barite or high-density mud, a negative correction 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

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

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 of each dipmeter and imaging tool. There are 3 accelerometers, one along the axis of the tool in the "Z" direction and in the "X" and "Y" direction at 90deg to the tool axis. The accelerometers measure the tool acceleration and can determine if the tool is jerking up the hole during logging. By applying these measurement, tool speed corrections can be applied. There are also 3 magnetometer measurements that measure the tool orientation in the X, Y and Z directions with respect the earth’s magnetic field. These measurements help determine borehole inclination and 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 tool hydraulic pressure or mechanical caliper springs. The dipmeter pads attached to each caliper arm, measure the formation micro resistivity that is very similar to the MSFL measurements. The resulting curves are called correlation curves and are used to determine formation dip. The resistivity measurements require conductive borehole muds. If oil based muds exist, then conductivity pad devices are employed using induction type technology.

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FIGURE 2: PAD DIMENSION FOR IMAGING TOOL

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

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Acoustic Imaging

FIGURE 3: TYPICAL ACOUSTIC SCANNING TOOLThe Acoustic scanning tools typically have a single acoustic transmitter that rotates at about 7.5 rps. The acoustic signal requires fluid in the borehole for transmission. The reflected signal from the borehole wall positively interacts with the transmitted signal setting up a standing wave. The wavelength is known and time for the transmission to return from the borehole wall is measured. The borehole diameter can then be determined.

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


Depth of Investigation

FMS 0.2 inchFMI 0.1 inchEMI 0.1 inchUBI 0.4 inch

Specifications

Tool typeFMS

(Schlumberger)

FMI(Schlumber

ger)

EMI(Halliburto

n)

STARBaker Atlas)

# Pads 4 4 6 6# Flaps 0 4 0 0# Rows 2 2 2 2# Buttons 24 48 25 24Button horizontal spacing 0.2 inches 0.2 inches 0.1 inches 0.1 inches

Button vertical spacing 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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spacingFlap spacing 0 6 inches No flaps No flaps


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

Presentation

FIGURE 4: STANDARD

FMI PRESENTATI

ON

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


Log Quality Control The Borehole Azimuth (HAZI) should not change dramatically during logging and PAD1 azimuth (P1AZ) and Relative Bearings (RB) should closely track each other. At all times however HAZI = P1AZ - RB (Relative Bearing) Tool rotation should be kept to a minimum. More than 1 tool rotation per 100ft and the log should be run again.Corrections EMEX Corrections Necessary for STAR tool logs only. Star tool data is recorded in 2 byte words and then converted to 4 byte words after multiplying by 4. The gain of each pad changes when conductivity limits are reached. This needs to be accounted for before processing.De-stripe / button normalise Normalising all buttons on each pad is often required when one pad has a heavy striping effect on the plotted image. Stripping typically occurs when there is a bad contact usually corrosive on one of the buttons connectors. 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 washout or the image tool caliper arms are deployed hard against the borehole wall, the

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tool may stop momentarily and 'jerk' up the borehole. This change in acceleration must be corrected for before any sedimentology interpretation is performed. Apply Accelerometer corrected depths Errors in the accelerometer data can result in an image worse than the original. It is recommended computing the correction but not applying to the image itself. Pad / Button Depth Shifts As can be seen from the tool diagrams above, pads and pad button rows do not measure the formation at the same depth at the same time. 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, the dipmeter image tool is centralized at all times in the borehole. Occasionally due to borehole washout, the tool is tilted and not central in the borehole. In these cases tool tilt corrections must be applied. Borehole size changes will also dramatically affect the dip interpreted by the image interpretation. Swing Arm corrections must also be applied before interpretation.Compute 6 calipers from Sonic image transit times Borehole caliper measurements can be derived from the time taken for Sonic images to reflect off the borehole wall back to the tool.Interpretation Standard Formation Dip Processing Formation dip and direction can be determined from the standard correlation curves using dipmeter correlation programs. Changes in bed boundary resistivity can be matched to opposing dipmeter arms to determine the dip angle and direction of the formation bed. Image Log Interpretation Using the recent image log technology, formation dip and direction can be graphically determined from the image plots. The user interactively generates dips from the image by select 3 points that define a plane from the image plot. This approach has become highly sought after for several reasons.

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 and interpreted. Paleontology of the image can be performed helping to interpret the existence of bugs and fossils. Sedimentology interpretation helps determine the process of deposition and diagenisis or post sedimentology changes. Thin Bed Total Thickness Since the dipmeter imaging tools have a far greater sampling rate and therefore greater vertical resolution than standard logging tools, a more accurate thin bed analysis can be calculated. The detail of the image log makes it ideal for fracture detection both open (sudden low resistivity) or closed or healed (sudden high resistivity).

Tool type

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 arm measurements that determine the existence of any borehole ovality. Borehole ovality helps indicate principle formation stress directions. The direction of breakout is the direction of weakest formation strength and is perpendicular to the primary stress direction.

SONIC LOGAPPLICATION:

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o Porosity PHISo Volume of clay VS

o Lithologyo Time-depth relationshipo Reflection coefficientso Mechanical propertieso VDL/CBL

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

THEORY OF MEASUREMENT:

Transmitter emits sound waves into the formation and measures the time taken to detect at a receiver of known distance from the transmitter. The Sonic tool operates at 20 cycles per second as sounds similar to a pedestrian crossing at a set of traffic lights. The first arrival is the compressional or 'p' waves, which travel adjacent to the borehole as shown in 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 time DT is computed from these travel times as shown in the equation below. This particular arrangement of sonic tool transmitters and receivers is known as the standard BHC Sonic tool and compensates for borehole washouts and also for tool tilting in real time while logging.

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 a Tx-Rx spacing of 3 feet. This results in a DT of 2 feet and is also the vertical resolution of the tool. The shear signal arrives next which usually has a slightly larger amplitude than the 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 interpret the existence of fractures.

Long Spaced Sonic tools

Long spaced sonic tools have a larger spacing between the transmitter and receiver. Tool spacing are 8ft-10ft and 10ft-12ft. This allows a deeper depth of investigation and improves the tool response in larger boreholes or where mud invasion is affecting the standard tool. The DT measurement requires the 8ft-10ft signals to be memorized until the 10ft-12ft signals are recorded and then a DT can be computed. This is known as Depth Derived Borehole Compensation or DDBHC. The long and short spaced sonic tools can 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 entire waveform is digitally recorded for analysis of the individual arrivals. The amplitude as well as 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 of the borehole. This allows eight independent measurements in each direction rather than an average of the borehole.

1. Full wave mode providing a full waveform analysis. Full wave recording in cased hole can produce a compressional Delta-T with comparable results to the open hole Delta-T measurement. 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 foot logs 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 dipole signals. The dipole signal is directional allowing the inclusion of a shear wave to be recorded in slow formations. The DSI tool generates compressional and shear waves from a 12kHz monopole signal, two orthogonal shear waves from 2.2kHz dipole signal and a Stoneley wave from 1-2kHz monopole signal.


Schlumberger BHC Long Spaced BHC SDT

Depth of investigation

5 inches 12 inches 12

inchesVertical resolution

24 inches 24 inches 36

inches

Halliburton BHC Tool

Long Spaced BHC

Long Spaced FWST

Depth of investigation

<3 inches < 8 inches 12 inches

Vertical resolution

24 inches 24 inches 12 inches

LIMITATIONS/OPERATION/PRESENTATION:

Limitations

The borehole must be fluid filled, preferably slightly salty, for acoustic coupling to exist. The sonic tool is usually run centered with centralizers above and below the transmitter receiver section, but if the hole size is > 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 fast signal traveling along the sonde itself. This makes the sonde very flexible and the tool should always be made up or connected vertically at the well site to avoid excessive tool bending and flexing of the fragile internal electronics. Some logging companies insert the Sonic tool into an aluminum sleeve when it is lifted up the rig Vdoor 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 the borehole wall. Standard BHC tools can be affected when zones are altered by borehole fluids. Long spaced sonic tools provide a deeper depth of investigation and are therefore preferred in larger boreholes or where mud invasion is affecting the standard tool.

Cycle Skipping:The problem of cycle skipping occurs if a weak signal is received. The low amplitude first arrival may be skipped over and not detected. The subsequent arrival is usually larger and often detected instead, thus a cycle has been skipped showing a longer than true transit time. Cycle skipping occurs in washed out boreholes and unconsolidated formations.Road Noise:The problem of road noise can occur from tools dragging against the borehole wall. Road noise increases the background amplitude and as a result increases the possibility of detection before the first compressional arrival. Road noise creates a faster than true sonic transit time. Only slowing the logging speed can possibly reduce road noise. Recent advances in Sonic tools lock onto the compressional arrival within a window interval using computer software

27

techniques. Faster noise arrivals are ignored and so are slower shear, mud and Stoneley arrivals.

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 less affected by swelling shales. As a result the standard 3 and 5 foot spacing transit times will read slightly slower in swelling shales than the longer 9 and 11 foot spacing Figures 4 - 8 show examples of cycle skipping, noise and casing signal along 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 the open hole Gamma Ray tool above the Sonic. The resistivity/sonic service is usually the first logging run since the string is cheaper, usually centered and has no radioactive sources.

LQC/CORRECTIONS:

Log Quality Control

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To adequately prepare for the possibility of cycle skipping and/or road noise, each travel time (usually T1, T2, T3 and T4) should be monitored on a screen while logging so the threshold can be lowered to detect low amplitude arrivals but also raised 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 time with the standard BHC Sonic tools.

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


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

Borehole Effects: The presence of gas in the well will severely attenuate the sonic signal and may result in extensive cycle skipping. In altered or invaded zones, employment of a long spaced sonic tool will read deeper into the formation bypassing any swelling shales. Washed-out holes or caves attenuate the sonic signal resulting in cycle skips. Fractures significantly attenuate the shear and Stoneley waves.

. Material Delta-T(us/ft)

Non Porous Anhydrite 50Solids Calcite 49.7. Dolomite 43.5. Granite 50.7. Gypsum 52.6. Limestone 47.6. Quartz 52.9. Salt 66.6. Steel 50. Casing 57.0Water Saturated 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 - 143.0Liquids Water (pure) 208

. Water (100,000mg/L of NaCl) 192.3

. Water (200,000mg/L of NaCl) 181.8

. Petroleum 238.1

. Mud 189Gases Hydrogen 235.3. Methane 666.6

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InterpretationHydrocarbons:It is generally considered that hydrocarbons have no significant effect on the Sonic transit 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 which is less than true total porosity if fractures or vugs exist.An increase in the permeability or in the number of fractures present will attenuate the Stoneley wave. Low frequency Stoneley waves are more sensitive to permeability and fractures. If a low pass 4kHz filter is applied to the sonic signal, the Compressional and shear waves are removed and the remaining Stoneley wave can be analyzed.

Porosity Effects:

The Sonic porosity is used for interpretation to complement the porosity measurements 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 FORMATION TESTER

The Wireline Formation Tester is lowered in the hole until the snorkel is opposite the zone of interest. Tool hydraulics is deployed to open the rubber packer and backup arms and seal against the borehole wall. Hydraulic pressure, 1500psi above hydrostatic pressure is usually sufficient to obtain a good seal. This stops any borehole mud contaminating the formation fluid sample being tested. The snorkel is then deployed or extracted at various rates and volumes, to draw the formation fluid into the pre-test chambers of the tool. Pre-test chambers are typically 0-30cc in volume. After a few moments the snorkel deployment is then ceased and the formation pressure build-up is then monitored and recorded. Further deployment of the snorkel will draw the formation fluid into sample chambers attached at the bottom of the tool. The fluid samples are stored at formation pressures that help in determining hydrocarbon composition.

Depending upon the formation permeability, pressure build-up times can vary from seconds for high permeability (>5mD) to hours for low permeability (<0.1mD). Often tool hydraulic pressure can slowly dissipate if fluid or pressure sampling takes 1 hour or more. This may result in a lost formation seal and formation fluid contamination with the borehole mud.

Some tools require different tool accessories need to be used depending upon borehole conditions. Hard or soft packers, different packer sizes, different sample chambers sizes and types and choke sizes all need to be planned before the logging job.

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

FIGURE 2: TYPICAL PRESSURE PLOT VS. TIME

Advances in Sample Detection

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

FIGURE 3: DISTINGUISHING BETWEEN MUD FILTRATE AND FORMATION FLUIDS

Sample Chambers

Several types of sample chambers are available. Figure 5 shows a multiple sample chamber allowing multiple zones to be sampled during one in the hole. Figure 6 shows a PVT sample chamber, where formation fluids are maintained at reservoir pressures. 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 the formation. Depending upon permeability and mud invasion, the tool ideally reads the virgin formation fluid beyond the zone invaded with mud filtrate.

The snorkel has a diameter of approximately 0.5 inches

Specifications

Petroquartz gauges

Strain gauges

Tolerances

0.5% of full scale

+/- 1psi

Resolution 0.01psi 1psi

Repeatability 1psi 3psi


Limitations

High-pressured borehole mud can cause differential sticking if the tool is sampling a single point for a long period of time. The Wireline Formation tool is the most common wireline tool that becomes stuck in the hole. Sticking occurs since there are very large sample chambers, typically 2.6 and 5 gal (10ltrs and 19ltrs) attached to the tool. Some Wireline Formation tools sample only formation fluids and therefore only require small sample chambers of approximately 600mL. With large sample chamber tools, sampling period greater than one hour should be treated 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 virgin formation fluid or the invaded mud filtrate. Modern tools measure the fluid resistivity and density and display this at the surface for the logging engineer to view. The engineer is then able to make real time decisions as to whether the fluid is 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 logging tools. The sample pressure is displayed in track 1 and also numerically in the usually "depth" track. The remaining tracks display each significant digit of the sample pressure. Track 3 displays units of 1000psi, Track 4 units of 100psi, Track 5 units of 10psi and Track 6 units of 1psi. In this way small pressure changes can be monitored graphically.

TOOL COMBINATIONS

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

Associated Mnemonics

Early Tools

RFT

Repeat Formation Tester

Schlumberger

Fixed pre sample volume

Variable pre sample rate

SFT

Selective Formation Tester

Halliburton

Variable pre sample volume

Fixed pre sample rate

Modern Tools

FET Formation Evaluation Tool Crocker ResearchMDT Modular Dynamics Tester SchlumbergerRDT Reservoir Description Tool HalliburtonRCI Reservoir Cauterization Tool Baker Atlas


The Formation Tester tool can measure pressures up to 10,000psi. Formation pressures 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 for borehole or hydrostatic pressure. If the mud weight is known the hydrostatic pressure at specific depths can be calculated (say every 500m). This gives confidence that the tool is measuring fluid pressure accurately. Hydrostatic pressure 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 feet Mud Weight is in units of lbs/gal

The packer hydraulic pressure should be monitored at all times during sampling to ensure 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 the tool packer is set, the pre sample pressure should be drawn down below the expected formation pressure. If pressure build-up stabilizes but is still below the borehole hydrostatic pressure, then it can be concluded that a sufficient seal from the borehole mud has been achieved and the fluid being pressure tested or sampled is fluid from the formation. If the pressure does not build-up within a reasonable time, then the tool should be reseated and another formation pressure test or sample is performed. At all times the standard wireline log measurements should be viewed to determine if the hole is washed out (creating difficulty obtaining a packer seal) or if a shale zone is being tested (creating tight low permeability tests).

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

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

Corrections

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No environmentally corrections are applied to the Formation tester.

Interpretation Permeability from Pre-test Draw down: Tools that are able to perform draw down at various rates can determine draw 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 = effective drainage 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 PERMEABILITY’S

FIGURE 7: EFFECT OF SATURATION ON RELATIVE PERMEABILITY FOR 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 dominates the formation fluid flow to the probe. The build-up is a function of the horizontal permeability only. If pressure is plotted verses the cylindrical time = 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-in u = fluid viscosity in cp M = slope of Horner plot h = bed thickness in ft

FIGURE 9: CYLINDRICAL PRESSURE VS. TIME PLOT

Spherical Buildup A spherical build-up will exist, with large bed thickness typically greater than 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

36

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 pressure gradients. Different pore fluid density exhibit different pressure gradients. If the pressure gradients are extrapolated and they intersect each other, the water-oil and the oil-gas contact points can be determined.

Hydrocarbon density can be determined since the formation pressure gradients 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 of formation water can be estimated by:

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

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

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

GAMMA RAY LOGAPPLICATION

Standard Gamma Ray Applications:

o Primary depth reference for all logging runso Correlation from well to wello Lithology identificationo Identification of organic material, permeable beds and source rockso Fracture identificationo Calculate clay volumes

37

o Mineral analysis

Natural Gamma Ray Tool (NGT) Applications:

o Detect, identify and evaluate radioactive mineralso Identify clay type and calculate clay volumeso Provides insight into depositional environment and the diagenetic historyo Uranium response of NGT is sometimes useful as a moved fluid indicatoro Permeable beds may have higher Uranium salt content than less

permeable beds.

The Gamma Ray log is typically run with most logging runs as a correlation tool since natural Gamma Rays can pass through casing. Production tools and perforating equipment can be accurately positioned using the Gamma Ray as a correlation tool. Slim hole Gamma Ray tools, 1 11/16", 1 7/16" and 1" in diameter for example, can be run through tubing to correlate TCP (Tubing Conveyed Perforation) guns on depth. A Gamma Ray tool can be run in boreholes with up to 20,000psi, 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 relatively low energy levels. Tools that measure natural Gamma Rays are known as standard and gamma spectrometry tools. Standard Gamma Ray tools measure the occurrence of all Gamma Rays. Spectrometry Gamma Ray tools also measure the Gamma Ray energy levels and therefore determines the concentrations of the three 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 the material being measured.

Induced Gamma Rays:

Tools such as gamma - gamma logs use a high energy Gamma Ray source to measure 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, the Geiger Mueller and Scintillation crystals. The Geiger Mueller is more reliable and robust but the Scintillation is more accurate. When a Gamma Ray strikes the crystal a single photon of energy is emitted. A burst of electrons are then emitted

38

as the photon hits the photocathode. The electrons multiply as they hit several anodes in an electric field until a small electric pulse is produced. Each electric pulse 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. To reduce statistical variation in the Gamma Ray measurement, logging companies take 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 time lag. A logging speed of 30ft/min (1800ft.hr) means that the tool will move 1ft every 2 seconds. Logging too fast will cause the Gamma Ray log to be off depth with 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 closely monitor logging speed as a quality check. The higher the time constant the more accurate the Gamma Ray log since it has a lower statistical variation. A time constant of 4 seconds would be preferable but the 15ft/min (900ft/hr) logging speed 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. Logging speeds of 30ft/min (1800ft/hr) produce accurate results. For quick correlation purposes speeds up to 100ft/min (6000ft/hr) can be used with acceptable accuracy.


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

Vertical resolution of the standard Gamma Ray tool is approximately 10 inches and that 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 less than 24 inch hole diameter.

Gamma Rays travel in a random manner and not in a continuous flow. The Gamma Ray 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 the mnemonic GR or a variation of this. Typically a scale from 0 to 200 with units of API. The right scale can be reduced to 150 or 120 if Gamma Ray activity is low.

39

Alternatively Spectrometry Gamma Ray tools can also present the following curves: -

1. Total Gamma Ray (SGR)2. Uranium free Gamma Ray (CGR) - to distinguish permeable streaks with high Uranium.3. Ratio Th/K - to distinguish between minerals4. 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 5 that Uranium is negative and when removed from SGR, CGR becomes larger than SGR. Although Uranium is actually present in the formation the problem is that the NGT tool is poorly calibrated.

TOOL COMBINATIONS

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

The Gamma Ray tool must be handled gently. Rough treatment or heavy impacts can crack 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, typically around 20-30 API. A shaly formation can have Gamma Ray readings varying between 80 and 300 API

Environmental corrections to be made

Large boreholes and high-density mud's (often containing barite) decrease the Gamma Ray count rate as the mud "shields" some Gamma Rays before reaching the tool. Similarly a tool centered in the borehole receives less Gamma Ray counts than an eccentered tool up against the bore hole wall. An eccentered Gamma Ray is preferred since it requires less correction. A Gamma Ray tool run

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in KCl mud will receive more counts by virtue of the increased Potassium content in the mud.

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-ppm thorium and 6ppm uranium. A high Gamma Ray measurement therefore usually indicates a shale sequence. The Gamma Ray tool is often used as the primary indicator of shale content. The percentage of rock that is considered shale and not rock matrix can be estimated by: -

Vshale = (GRlog – GRclean)(GRshale - GRclean)

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

As stated before, the Spectrometry Gamma Ray tool measures not only the number of Gamma Rays returned but also their individual energies. Each energy level is a characteristic of the type of formation being logged. Analysis of the potassium, thorium and uranium energies can help indicate fractures, mineralogy and 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 determine mineralogy and clay type.

INDUCTION LOGGINGAPPLICATION

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 was developed from mine detector technology developed during the Second World War.

By analysing resistivity measurements, we can differentiate between formations containing conductive and non-conductive fluids. Conductive fluids in the formation usually 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 relative proportions of hydrocarbons and water resident in the formation: -

Rt = aRw /(PHIm Sw2)

Where:-Rt = Formation ResistivityRw = Formation water resistivitySw = Percentage of water in pore space (Water Saturation)

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F = Formation Factor = a/PHIm

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

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, however the 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 to Ohm’s law and is described by: -

V= IR

Resistivity (R) can be defined as the property of a material that resists the flow of electric current, and is the voltage required to pass one amp through a cube with a one meter square 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 resistivity but twice the resistance.

Resistivity = RA/L = KR = KV/IWhere:-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 formation adjacent to the tool by generating an alternating current source in the primary coil. This induced electromagnetic field will produce a measurable current and potential in the receiver coil of the tool proportional to the formation conductivity. The primary and secondary windings of a common transformer are a simple analogy. The measured voltage 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 has the 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 spacing to that of the medium measurement ILM enabling two different depths of investigation into the formation. The standard Induction tool (known as 6FF40/28 series) uses a total of 6 coils, which are used in pairs to improve focusing and thus vertical resolution of the Induction measurements. The deep measurement receives no signal from the first 40 inches surrounding the tool with a transmitter/receiver spacing of 40 inches. The medium measurement has a transmitter/receiver spacing of 28 inches. Ideally the deep measurement will read primarily the uninvaded zone resistivity depending upon diameter of invasion and the medium measurement will read more of the transition and some flushed zone resistivity depending upon diameter of invasion. Usually a small focused laterolog measurement is incorporated in the Induction tool to measure the flushed zone resistivity depending upon diameter of invasion. These measurements require corrections for borehole and invasion effects. This will be described in Section 6.0. MWD logs have less invasion effects since they measure the formation immediately after drilling before the mud cake is formed and invasion has ocurred. The process of giving greater emphasis tothe coils at the centre of the tool in preference to those coils either side is termed deconvolution. Modern Phasor Induction tools use the dielectric or X-signal to make a non-linear deconvolution correction. This X-signal was ignored in earlier tools. An Array Induction tool measures 28 independent signals from 8 arrays.


Halliburton DIL Tool

Deep (ILD)

Medium (ILM)

Shallow (LL3)

Vertical resolution 60 inches 54 inches 6 inchesDepth of investigation 65 inches 30 inches 14 inches

Schlumberger DIT-E Tool ILD IDPH IDER IDVR

Vertical resolution 72-84 inches 72-84 inches 36

inches9-24 inches

Depth of investigation Deep 90 inches

Medium 40 inches

Schlumberger AIT Tool3 Vertical resolutions 12, 24 and 48 inches

5 Depths of investigation

10, 20, 30, 60 and 90 inches

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 corrections and errors occur above 200ohmm (5mmhos). Often the sonde error itself is 3-4 mmhos and if this is removed from a 200ohmm (5mmhos) raw signal, a correction of 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 formation conductivity. As the formation conductivity is reduced (and formation resistivity is increased) the Induction tool will measure more of the relatively conductive

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mud. A Phasor Induction tool will overcome some of the problem. The Induction tool therefore operates best in high resistivity drilling mud (ie fresh water), oil based drilling mud and also in air.

The placement and polarity of the receiver coils effect the depth of investigation and the vertical resolution of the tool.The Induction tool is preferred over the Laterolog tooltypically 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 currents are not able to be induced as efficiently and the Laterolog tool rather than the Induction 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. The is that the strength of the field is reduced resulting in a higher than true resitivity reading. Skin is a inversely proportional to the formation conductivity, magnetic permeability and the transmitter frequency. Thus the higher the transmitter frequency, the less skin effect. Correction for skin effect is usually only performed on the deep measurement. The medium measurement is usually less than 1% as a result of the shorter coil spacing.

Operation

The logging speed is approximately 6000 ft/hr but is usually run at 1800 ft/hr when run in combination with other logging tools. Standoff sizes are critical for determining 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. The following table gives recommended standoff sizes.

Hole Size Standoff Distance

<6.5 inches 0.5 inch6.5-7.75 inches 1.0 inch

7.75-9.5 inches 1.5 inch

>9.5 inches 2.0 inch

Presentation

The deep Induction log is presented in track 3-4 (logarithmic) by a thin dashed line with the mnemonic ILD. The medium Induction log is also presented in track 3-4 (logarithmic) by a thin dotted line with the mnemonic ILM. The shallow focused resistivity log (alternatives are the Short Guard) is presented in track 3-4 (logarithmic) by a thin continuous line with the mnemonics SFLU or some. variation of this. The scale typically ranges 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 with the open hole Gamma Ray tool at the top. The resistivity service is usually the first logging run since the tool is cheaper, usually centered and has no radioactive sources.

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Tool types available

DIT-D Standard Dual Induction Tool containing 6 coils for focusing signals to improve 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 8 arrays. The single transmitter operates at 3 different frequency and the in-phase (resistive) and the quadrature (dielectric) signals are measured. The AIT measures signals AIT10 (10 inches into the formation), AIT20 (20 inches into the formation) etc up to AIT90. A combination of these is used to compute an Rt value, however if one of these readings is affected by micro annulus the computed Rt can be inaccurate.

LQC/CORRECTIONS


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 the invaded zone (Rxo fully flushed by borehole mud), ILM measures the transition zone (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 < Rxo will exist if Rw < Rmf. If no permeability exists and therefore no mud invasion, as typically is the case with shales, the deep, medium and Rxo measurements will overlay unless environmental corrections still need to be applied.

While logging check that SP deflections are normal (to the left if Rxo > Rt) and not noisy. Check that resistivity readings do not flat top in high resistivity beds and that 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 logging runs.

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

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

VRT = (Rsand – RT) / (Rsand - Rclay)

In practice this equation is modified and multiplied by 4*Rclay/RT to avoid giving erratic readings. VRT is usually much too high except when high resistivity formations are present. Since clays are conductive, an Rsand minimum value helps to fix the zero VRT

point.

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FIGURE 3: VRT CLAY INDICATOR

LATEROLOG TOOLAPPLICATION

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

By analyzing resistivity measurements, we can differentiate between formations containing conductive and non-conductive fluids. Conductive fluids in the formation usually 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 of hydrocarbonsand water resident in the formation:

Rt = aRw /(PHIm Sw2)

Where:-Rt = Formation ResistivityRw = Formation water resistivityPHI = Formation PorositySw = Percentage of water in pore space(Water Saturation)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, however the 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 to Ohm’s law and is described by: -

V= IR

Resistivity (R) can be defined as the property of a material that resists the flow of electric current, and is the voltage required to pass one amp through a cube with a one meter square 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 resistivity but twice the resistance.

Resistivity = RA/L = KR = KV/IWhere:-R = resistance

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A = cross sectional areaL = lengthK = Geometric constant

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

FIGURE 2: FOCUSED/UNFOCUSED

CURRENT PATH

The sonde for this resistivity log uses guard or bucking electrodes to focus the current and force the emitted current in a direction approximately at right angles to the sonde. This focused current allows the resistivity reading to measure a more specific region of the formation, thus increasing the Laterologs vertical resolution. The non-focused resistivity tools suffer a distorted current distribution especially when Rt/Rm is high, as the current will try to flow within the borehole.

FIGURE 3: SHALLOW LATEROLOG CURRENT PATH

DIAGRAM

FIGURE 4: DEEP LATEROLOG CURRENT PATH DIAGRAM

In the standard Laterolog tool, constant power (Power=VI product) is supplied to pairs of guard electrodes (A1 and A1*) and to a current electrode (A0) which is positioned between two pairs of potential electrodes (M1-M2 and M1*-M2*). The potential of the current electrode (A0) is in equilibrium with all guard electrodes (A1 and A1*). Thus the current from the current electrode (A0) will not flow to the guard electrodes and is therefore focused radially into the formation. Potential electrodes (M1-M2 and M1*-M2*) measure the change in potential between the guard and the current electrodes. The potential will vary depending upon the formation resistivity and each electrode potential will be adjusted until the guard and current electrodes are once again in equilibrium.

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By varying the distance of the return electrode with respect to the tool, the depth of penetration can be changed. The shallow laterolog (LLS) has a return electrode immediately above and below the sonde whereas the deep Laterolog (LLD) has a return electrode at the surface thus the current is forced deeper into the formation.

FIGURE 5: MSFL CURRENT PATH

FIGURE 6: DLT TOOL

FIGURE 7: MSFL TOOL

Figures 8 and 9 show the percentage of tool signals at various distances into the formation. 100% of the MSFL signal for example is acquired within the first 10 inches. The LLD signal on the DLT Tool measures 50% of its reading within about the first 90 inches into the formation, the remainder of the LLD signal is acquired beyond 90 inches and therefore has a deeper depth of investigation than the MSFL or LLS signals. The depth of investigation is considered to be at the 50% point.


Halliburton DLT Tool

Deep (LLD)

Shallow (LLS)

Micro Log (MSFL)

Vertical resolution 24 inches 24 inches 3 inchesDepth of investigation 80 inches 30 inches 1-4 inches

Halliburton DLLT Tool

Deep (LLD)

Shallow (LLS)

Micro Log (MSFL)

Vertical resolution 24 inches 24 inches 3 inchesDepth of investigation

60-84 inches

24-36 inches 1-4 inches

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Schlumberger DLT Tool

Deep (LLD)

Shallow (LLS)

Micro Log (MSFL)

Vertical resolution 24 inches 24 inchesDepth of investigation 90 inches 35 inches 2 inches

Schlumberger ARI Tool

Deep (LLhr)

Deep (LLD)

Shallow (LLS)

Micro Log (MSFL)

Vertical resolution 8 inches 8 inches 8 inchesDepth of investigation 35 inches 45 inches 15 inches 2 inches

CALIBRATION

The Laterolog tool does not require a master or shop calibration like most logging tools but does require an internal well site tool resistance check that is performed before and after each logging suite. This ensures the tool was operating the same from the commencement of logging to completion of the logging operation. Often a surface test box is attached to the tool before running in the hole. This allows a check of the accuracy of the tool against known resistance values in the test box.

LIMITATIONS/OPERATION/PRESENTATION

Limitations

The Laterolog tool is generally run in low resistivity drilling mud and also in highly resistive formations. Low resistivity mud will have minimal affect on the resistivity readings from the formation since the total measurement is added in series.The Laterolog tool can accurately measure formation resistivity in the range of 0.2 - 40000 ohmm. The Laterolog tool is preferred over the Induction tool typically when the following conditions apply:

1. The Rmf/Rw ratio is less than 2.52. When the formation resistivities exceed 200 ohmm3. The bed thickness is less than 10 ft.

When the porosity is below the Rw line but Rmf/Rw is still above 2.5, eddy currents are not able to be induced as efficiently and the Laterolog tool rather than the Induction tool should be used.

Operation

The logging speed is approximately 6000 ft/hr (100 ft/min) but is usually run at 1800 ft/hr (30ft.min) when run in combination with other logging tools like the MSFL and GR which need to be run at 1800ft/hr (30ft.min). A Laterolog electrode is placed in the drilling rig mud pit for the reference and return of the deep laterolog measurement. This electrode is called a 'Laterolog fish' and should be placed in a section of the mud pit away from any moving mud fluids. At no time during tool operation should personnel touch the sonde of the Laterolog. The Laterolog should be centered in boreholes 8.5 inches or less and eccentered against the borehole wall in boreholes larger than 8.5 inches.

Presentation

Presented in tracks 3-4 (logarithmic) by a thin, dashed line with the mnemonic LLD.

Presented in tracks 3-4 (logarithmic) by a thin, dotted line with the mnemonic LLS.

Presented in tracks 3-4 (logarithmic) by a thin, solid line with the mnemonic MSFL.

Typically the scale of the is from 0.20 to 2000 with units of ohmm

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FIGURE 8: TYPICAL LATEROLOG PRESENTATION

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TOOL COMBINATIONS

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

Tool types available

DLT - Standard Dual Laterolog Tool giving a deep and shallow laterolog measurement.

ARI - Azimuthal Resistivity Tool. A small sub is added to the DLT tool and is equipped with 12 equally spaced and independent azimuthal laterolog readings. A deep reading and very shallow reading of tool standoff are produced.

LQC/CORRECTIONS


Permeability can be indicated by the separation of the resistivity readings for LLD, LLS and MSFL. This occurs when the higher-pressure borehole mud invades into the formation displacing the original formation fluid. Depending upon the diameter of invasion, MSFL ideally measures the invaded zone (Rxo fully flushed by borehole mud), the LLS ideally measures the transition zone (partially flushed by mud) and the LLD ideally measures the un-invaded zone (virgin formation fluid) see for invaded, transition and virgin zones.

The Rxo < LLS < LLD profile will exist if Rw > Rmf and the profile LLD < LLS < Rxo will exist if Rw < Rmf. If no permeability exists and therefore no mud invasion, as typically is the case with shales, the deep, shallow and Rxo measurements will overlay unless environmental corrections still need to be applied.

While logging check that SP deflections are normal (to the right if Rxo < Rt) and not noisy. Check that resistivity readings track each other and are 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 different logging runs.

Solid rock and hydrocarbons will have an extremely high resistivity. A good rule of thumb is that hydrocarbons are indicated where the RLLD > RLLS > RMSFL profile exists.

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FIGURE 9: VRT CLAY INDICATOR

The Resistivity can be used as an indicator of clay content.The percentage of rock that is considered clay and not rockmatrix can be estimated by: -

VRT = (Rsand – RT) / (Rsand - Rclay)

In practice this equation is modified and multiplied by 4*Rclay/RT to avoid giving erratic readings. VRT is usually much too high except when high resistivity formations are present. Since clays are conductive, an Rsand minimum value helps to fix the 100% VRT

point.


The resistivity measurement for the formation (Rt) of interest will be influenced by three unwanted elements; the resistivity of the bore hole (Rm), the mud filtrate invasion (Rxo) and the adjacent bed (Rs). The resistivity of the rock unit of interest (Rt) maybe greater or less than that of the measured resistivity LLD and LLS.

FIGURE 10: LATEROLOG ELECTRICAL CIRCUIT

The mud resistivity, the invaded zone resistivity and the true formation resistivity are considered as series resistivities. Figure 13 shows a simple electrical circuit representing the resistivity of the borehole mud - Rm, the invaded zone – Rxo and the uninvaded zone - Rt. If the Laterolog is run in a salty mud, it is evident that the contribution from Rm and Rxo is small compared to the true formation resistivity Rt. The effect of the mud and invaded resistivities must be removed to estimate the true formation resistivity.

The following corrections are applied, and strictly in the order shown. The Laterolog needs to be corrected for:

MSFL Borehole corrections (See Figure 14)Borehole corrections - mud resistivity and borehole size (See Figure 15)Bed Thickness corrections (See Figure 16)Invasion corrections - mud invasion (See Figure 17)

LLD Laterolog Deep ML Micro LogLLS Laterolog Shallow ML1 Micro Log 1 inchLLG Groningen LLD ML2 Micro Log 2 inchHLLD High Resolution LLD MNOR Micro Log normal 2"

HLLS High Resolution MINV Micro Log Inverse 1"

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LLSLL3 Laterolog 3 MLL Micro Laterolog

LL7 Laterolog 7 MSFL Micro-Spherically Focused Log

N16 16 inch short normal

MSFC Borehole corrected MSFL


Resistivity values depend upon the amount of water and its salinity in the pore space of the rock. The water being either formation water Rw or the invaded mud filtrate Rmf. Typically formation rock, oil and gas are considered infinite resistance and any drop in resistivity is from the conductive water or conductive shales. The Laterolog tool can accurately read between 0.2 and 40,000 ohmm.

NUCLEUR MAGNETIC RESSONANCE

HISTORY

Nuclear Magnetic Resonance technology originated in the medical field and is still used as a major diagnostic tool today.

The technology was applied to the oil industry in the early 1990's.

APPLICATION

The NMR measurement is able to measure the fluid volume in the formation, the types of fluids and the size of the pores space containing these fluids.

Volume of clay bound fluids, irreducible fluids and free fluids being water, oil and gas can be determined.

Formation permeability and hydrocarbon density can be determined. Conventional logging tools measure the entire formation and are more sensitive

to the larger volume matrix material rather than the formation fluids. NMR technology only sees the formation fluid and therefore provides a formation porosity independent of formation rock type.

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Operation

FIGURE 1: SCHEMATIC OF THE NUCLEAR MAGNETIC RESONANCE TOOL

The NMR tool uses a large permanent magnet which magnetises the formation for a predetermined period of time. Different transmission frequencies can be used to measure at different depths of investigation as represented by the regular spaced cylinders around the tool. Oil based muds provide a better tool response than water based muds.

FIGURE 2: VECTOR REPRESENTATION OF POLARISATION AND BURST FREQUENCY

Figure 3 shows the vector representation the magnetic polarisation of magnitude Mo. Polarisation is applied for a time TW. The fluid particles (or more specifically the hydrogen atoms or protons) are then exposed to regular bursts of radio-frequency energy (transverse magnetic pulses of frequency fo) transmitted into the formation in the form of an alternating magnetic field. The transverse magnetic pulses are applied at 180deg intervals.

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FIGURE 3: SPIN ECHO TRAINAfter each successive transverse pulse of period TE, the decrease in magnitude is measured. The decay of the spin echo magnitude over the period of the pulse train is given by: -

Mx(t) = Mox e^(-t/T2)

where Mox is the initial magnitude of the transverse magnetisation and Mx(t) after time t. T2 is the transverse relaxation time constant and is representative of the magnitude of the transverse magnetic decay.

FIGURE 4: POLARISATION AND PULSE SEQUENCEAfter a period of decay time equaling several times the T2 value, the measured magnitude is essential zero. Further transverse pulsing will not be possible. Polarisation and pulsing must start again. The photons are therefore polarised again for a period TW (approx. 6-8msec) and pulsed at a period of TE (approx. 1.2msec)

3.2 Depth of Investigation and Vertical Resolution

Depth of Investigation Vertical Resolution

MRIL (Halliburton)

14-16 inches (less hole radius)

approx. 5ft but dependent upon sampling rate and logging speed

CMR (Schlumberger) 0.5-1.25 inches approx. 6 inches but dependent upon

sampling rate and logging speed

Specifications

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FIGURE 5: SCHLUMBERGER CMR TOOL Magnet length = 2ft, tool is eccenterred. Pulsing rate = 0.2msec.

FIGURE 6: HALLIBURTON MRIL TOOL Magnet length = 7ft, tool is centralised. Pulsing rate = 0.6 and 1.2 msec but up

to 9 readings simultaneously.Pros Cons

Halliburton MRIL More reliable in rugose Poor vertical

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hole resolutionSchlumberger CMR Thin bed analysis Affected by bad hole

CALIBRATION

The NMR tool requires a monthly calibration using a calibration tank. Before and after survey calibration checks are also required.


Limitations Nuclear Magnetic Resonance tools where initially used to measure bound fluid volumes. The T2 decay times for clay bound fluids is in the vicinity of 3msec and 10msec for capillary bound fluids. This requires a very small polarisation time. Logging speeds therefore are not restricted. Free fluids however have a far greater T2 decay time and require a far greater polarisation time. This restricts the logging speed considerably to less than 10ft/min. Stationary readings are often required over very porous, large porosity zones.

The Halliburton MRIL tool has a larger permanent magnet than Schlumberger's CMR allowing it polarise formation fluids faster. The larger magnet however is approximately 7 feet in length compared to the CMR at approximately 2feet. The CMR therefore has a superior vertical resolution. The MRIL is a centred tool and the depth of investigation is reduced as the hole size increases. The CMR is an eccenterred tool and is not as badly affected by hole size.

Presentation

FIGURE 7: TYPICAL NMR PRESENTATIONTrack 1: Various T2 bin cut-offs representing pore sizes. Bin 1(black) is the smallest pore size up to Bin 6(green) the largest pore size. Track 2: Depth

57

Track 3: Various fluid volumes. TFV - total fluid volume, BFV - bound fluid volume. Track 4: Permeability calculations and T2 averages. KCMR - perm from CMR, PKEN - perm from PETROLOG, T2LM - Logarithmic of T2, T2AV - Average T2 Track 5: T2 wave train trace amplitude representation. Track 5: Colour image representation of T2 wave train


Log Quality Control Logging speed is critical to the correct operation of the NMR tool. Depending upon the tool gain and the TW wait times being used, the logging speed and vertical resolution are determined. Curves can be displayed in real-time on the logging run, showing signal to noise ratios and ringing. The MRIL tool has a log called the CHI that is a measure of the quality of the calculated T2 decay curves determined from the echo decay amplitudes.

Short polarisation times (TW) will underestimate porosity. If the TW is increased and porosity increases then the tool should operate at this new TW. The correct TW is critical since hydrocarbon bearings zones are usually where porosity is underestimated.

Other checks are: -

NMR Effective porosity < NMR Total porosity Clean water filled formation MPHI = Cross plot porosity

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Corrections

No environmental corrections are applied to the NMR tool.

Interpretation

FIGURE 8: HIGH AND LOW PERMEABILITY ECHO TIMES Each pore size has different decay times and a specific T2 time constant. High

permeability large pores have slow echo times and high T2 values. Low permeability small pores have fast echo times and low T2 values.

FIGURE 9: THE T2 RELAXATION TIME Figure 10 show the conversion from multiple pore sizes in the echo decay time

plot to the T2 distribution plot.

FIGURE 10: ECHO TIMES DEPENDS UPON PERMEABILITYAlthough porosities are the same, pore size is different and therefore echo decay

times are different and permeability significantly different The T2 value is proportional to the surface to volume ratio of the pore space which is a measure of the size of the pore space. Low T2 values occur in low permeability formations

and high T2 values occur in high permeability formations.

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Permeability from NMR

FIGURE 11: BOUND FLUIDS AND FREE FLUIDS ON THE T2 SPECTRUM

Kenyon permeability: k = aPHI^4(T2,log)^2 where a = 4mD/(ms)^2 for sandstone a = 4mD/(ms)^2 for carbonates PHI = porosity T2,log = the logarithmic mean T2 in msec

Timur/Coates permeability: k = a'PHI^4(FFI/BFV)^2 where a' = 1000mD for sandstone PHI = porosity FFI = Moveable fluid volume BFV = Bound fluid volume

Water saturation from NMR

FIGURE 12: T2 REPRESENTATION OF VARIOUS FLUID TYPESBy selecting different T2 cut-offs, the various bins can be applied to clay bound water (MCBW), capillary bound water (MBVI), free movable water, light oil, heavy oil and gas (MBVM).

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Bound Water Saturation: Swb = (MCBW+MBVI) (MCBW+MBVI+MBVM)

Hydrocarbon Saturation: Shc = (Vol. oil and gas) (MCBW+MBVI+MBVM)

The bottom part of Figure 13 shows how a long wait time TW will increase the volume of oil and gas determined from the NMR. Also a long TE will move the free water volume to the left.

The correct TW and TE values are clearly critical to distinguishing the different fluids in the formation. Zones of interest should have multiple passes to confidently establish what values should be used.

Caution: The volume of hydrocarbon using the above mentioned method is highly dependant on the residual hydrocarbon. Since the tool measures in the invaded zone, this method is less effective where Swirr is high and hydrocarbons have been flushed out.

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Petrophysics logging tools