WELLOG                                      LOG INTERPRETATION









Interpretation of data from well logs is many times subjective. Depending on the accuracy of the log data and the experience, proficiency, and care taken by the observer in the process of interpreting that data, the possibility for error is very great.  Different approaches to log interpretation many times produce different conclusions based on the use of more data or less data including more or less “good” data. The following information is for informational purposes only. Any application of the following information including equations is the sole responsibility of the user. No representation is made to the accuracy and/or completeness of this information.  If errors are found, the reader is encouraged to contact support@wellog.com




When measurements of physical properties are made, a certain amount of uncertainty prevails. Learn more about uncertainty of measurements at http://www.physics.nist.gov/cuu/Uncertainty/index.html.


Learn more about uncertainty in well log analysis with Monte Carlo simulation.


Here’s a link on the subject of units of measurement.


Links to Petrophysical consultants:


Ron Zittel       www.rjzpetrophysics.com 





WELLOG provides a free online Seminar on log interpretation.  It’s called a webinar. NEW Material added every day!





The purpose of any Geophysical Log is to provide meaningful information about the geological and physical conditions in and around a borehole.  Many books have been written on the subject of log interpretation. Fundamental Log Interpretation has not changed in decades and will probably not change.


Today, logging is most often performed using digital data acquisition platforms. The data stored in a data file may have extensive statistical computation applied to it. Intelligent systems apply the same and sometimes better algorithms than their human counterparts once did.  The result is faster and often times “smarter” interpretation. Taking the additional steps required to apply corrections to raw data and perform ‘sanity’ checks on results adds confidence to any interpretation.




EVERY LOG should contain calibration information.  Interpretation can only be based on accurate and true measurements having a verifiable reference. Ideally, calibration should be performed before and after each log.




Possibly the most important log that can be obtained is an E-log. A properly calibrated E-log will provide important information about formation Electrical Resistivity. In addition to resistivity,


Spontaneous Potential (SP) is obtained. SP shows lithology and type of lithology in terms of sand/carbonate or shale/clay and relative proportion of each.


Electric Log operation is based on ohms law.


Ohms law states:       Resistance = V/I


Apparent Resistivity (ra) takes into account the electrode geometry as follows:


                       ra  = V/I x G




G = Geometric Factor (4pAM) AM is the distance measured (in meters) from A to M electrodes.

V = Measured Voltage

I = Applied Current


View resistivity [Model].


View an E-log tool: [E-log tool]


Learn more about [electric log] applications. 


Resistivity is usually measured in units of ohms – meter2 / meter or; “ohm-meters”.


Electrical Resistivity provides information about the fluid that is in the pore spaces within the rock matrix in oil and water wells.  Because electrical resistivity is controlled by ion flow in liquids, the E-log will provide confirmation of the existence of water, water quality, and/or hydrocarbon content of the rock matrix.  The electrode spacing (A to M) used on the E-log tool is directly related to the depth of measurement.  When multiple spacings are used, resistivities of different depths are measured.  It is possible to form conclusions on invasion and permeability based on resistivity measurements made at two or more different depths into the formation. See a tornado chart. If no invasion has occurred, then both shallow and deep curves will read the same resistivity. If invasion has occurred, then the shallow resistivity will reflect the resistivity of the invading mud filtrate and the deep resistivity will reflect the formation fluid resistivity.  Resistivity curves should read the same and depart only where invasion occurs.


In a water well, higher resistivity in a saturated zone implies higher quality water. Total Dissolved Solids in water is related to the resistivity of water. Although certain conditions apply, as Total Dissolved Solids decrease, water resistivity increases. (Turcan, 1966) 


In wells having hydrocarbons, increasing resistivity in sandstone or carbonate zones may be an indication of increasing hydrocarbon content.


The amount of fluid contained in a formation is directly related to porosity. Porosity affects formation resistivity. In water filled pore spaces, as the volume of water increases, the capacity for more ions increases. More ions mean more conductivity.


Conductivity and Resistivity are inversely related.


Conductivity is expressed in units of micro-mhos per centimeter.



                        Conductivity ( C, in micro-mhos/cm) =  10,000/ Resistivity (in ohm-meters)


In the SI system of units, Siemens are used to replace mhos. 1 Siemens = 1 Mho.  Learn more about [Siemens and Mhos].



Formation resistivity is affected by three factors: Salt Concentration, Temperature, Pore volume (porosity).


Formation Resistivity Factor (F) is a fundamental concept in log interpretation and analysis. The formation resistivity factor is defined as the ratio of the electrical resistivity of a rock 100 percent saturated with water to the resistivity of the water with which it is saturated, (Archie, 1942).


The equation is:             F = Ro/Rw                  (Referred to as Archie’s Equation)


Given Rw = .05,


If Ro = 5.0 then F = 100


If Ro = 1.25 then F = 25


If Ro = .55 then F = 11




Archie found a relation of Formation Resistivity Factor (F) to Porosity (f) as follows:


                                    F = a / fm


The constants (a) and (m) are related to lithology.


Cementation factor (m) in a consolidated sandstone or a porous limestone is 1.8 to 2.0. In a clean unconsolidated sandstone values for (m) may be as low as 1.3 and the constant (a) is equal to 1.0.


An empirical formula based on studies of core data from numerous localities has resulted in the equation:


 F = 1 / f2


Porosity of 10 percent results in a Formation resistivity Factor of 100


Porosity of 20 percent results in a Formation resistivity Factor of 25


Porosity of 30 percent results in a Formation resistivity Factor of 11



Notice these three Formation Resistivity factors are the same as previously calculated with F = Ro/Rw above.



Ro/Rw = F = 1 / f2





                        f = (1/Ro/Rw)1/2



Requirements for this method are 100 percent water saturation, Rw is known and mineral conduction is not present.



Using Shallow Resistivity from a pad mounted measurement:


Given Resistivity of the flushed zone, Rxo and Resistivity of the mud filtrate, Rmf, porosity may be obtained a follows:




                        f = (a Rmf/Rxo)1/m




where a = .62, m = 2.15 (From Winsauer et al., 1952)




(From Alger 1966, Croft 1971, USGS)


A conclusion may be made that if deep and shallow measurements are the same, that no invasion has taken place.  If deep and shallow measurements are different, then invasion has taken place.  Invasion is an indication that a rock matrix is permeable.  It is because of the ability of the E-log to measure fluid content, fluid quality, lithology, and indirectly permeability, porosity and formation factor that make an E-log potentially the most useful logging tool. 


See the page on permeability.




All logging methods have limitations to consider.


Bed thickness effect: The curves produced by the normal devices are affected by bed thickness and resistivity (Lynch 1962).


Where the resistive bed is more than 6 AM spacings thick, logging up hole, there is a gradual increase in resistivity until the M electrode on the sonde enters the bottom of the bed. This level of resistivity is maintained until the A electrode enters the bed. As the sonde continues there is a gradual increase in resistivity until the midpoint of the bed is reached. Thereafter a gradual reduction occurs in resistivity, which is symmetrical with the curve below the midpoint of the bed, until the sonde passes out of the bed. The recorded resistivity approaches but does not fully equal the true resistivity of the bed. The bed also appears to be 1 AM spacing thinner than it actually is, the major resistivity deflections occurring ½ AM above the bed bottom and ½ AM spacing below the bed top. As the bed thickness decreases, the resistivity peak at the center decreases in amplitude. Further thinning to AM or less than AM causes the resistivity deflection to disappear entirely, and the curve actually reverses. The resistive bed now appears to be more conductive than the surrounding formations.


Although the radius of investigation increases as the electrode spacing increases, the use of AM spacing greater than 64 inches is not practical because thinner beds are not only shown at less than true resistivity but may be recorded as conductive beds if their thickness is less than or equal to the AM spacing.  Focused resistivity tools overcome this limitation.




Recently, software has been developed for improving resistivity log interpretation. Old logs and new are being subjected to inversion processing that removes the effect of surrounding formations. These techniques will make electrical resistivity a more accurate viable logging method well into the future.




The discussion thus far has been related to resistivity using a “normal” electrode array.


Several other tools are available for the purpose of measuring resistivity. Each tool is designed to provide an accurate determination of formation resistivity in various borehole environments.


Lateral resistivity measurements are used when it is necessary to obtain deep formation resistivity measurements. Deep formation resistivity is a close approximation of true resistivity where invasion is small. In cases of deep invasion, interpretation must include a correction for the invading borehole fluid. Note: Due to the larger spacing of electrodes used in this method, thin formations are less noticeable on the log.


Focused electrode resistivity tools are used in boreholes that have low resistivity mud or other drilling fluids. Normal and lateral logging tools tend to conduct current thru the borehole fluid in this case.  Focused electrode systems are designed to reduce or eliminate borehole fluid conduction. The current emanating from the tool therefore flows into the surrounding formation and provides a more accurate measurement of formation resistivity. 


Micro electrode [wall] resistivity tools have small electrodes attached to a non conductive pad that is pressed against the borehole wall while logging. These tools are designed to measure the resistivity of the combined mud filtrate (Rmf) and resistivity of the flushed zone (Rxo). The objective is to obtain information about formation porosity and permeability. The small spacing used in the electrodes make this tool very accurate in establishing bed boundaries.


Induction resistivity tools use electromagnetic induction as a method of measuring formation resistivity. It is important to know that all other resistivity measurements require fluid in the borehole. Induction logging tools provide resistivity measurements in oil/water and air.


Corrections are applied to all of the above resistivity methods.




An Acoustic Log (sometimes referred to as a sonic log) when properly calibrated, will provide important information about the physical structure of a rock matrix.  The ability of sound to travel within and through rock or sand and gravel depends on the physical structure of the matrix.  The amplitude, speed and phase relationships of a transmitted sound wave that returns to an acoustic receiver is a function of all of the combined matrix densities, interconnections, cementation, fracturing, and porosities within the matrix. 


Because the total transit time from the transmitter to the receiver includes the path thru the borehole fluid + formation + borehole fluid, Borehole compensated (two or four receiver) logging tools are used. Borehole compensation is accomplished mathematically by subtracting the borehole transit time. 


Acoustic waveforms provide information related to transit time (density) and amplitude (interconnection) of the material comprising the rock matrix.  Surface Geophysics has for many years used seismic reflection and refraction for determination of subsurface structure.  Transit time (Dt) through sandstone, limestone, water, and other materials have been determined in the laboratory.  Relationships between porosity and transit time are known.  It is possible to determine porosity of a given matrix if the transit time is known.   Beginning with velocity;


The bulk velocity is the sum of the fluid velocity and the matrix velocity.


The relationship between bulk velocity (vb) and fluid velocity (Vf) combined with matrix velocity (Vma) becomes:


Given an equation referred to as the Wyllie “time average equation”:


                                    1/vb = f/vf + 1-f/vma


Transit time (Dt) is the reciprocal of velocity.


The equation for porosity (f) obtained from transit time (Dt) is: 


f = (DtlogDtma) / (Dtf – Dtma)


Where Dtlog = Measured Dt, Dtf = fluid Dt, Dtma = assumed matrix Dt.


Fluid Dt is usually considered 200 microseconds per ft. (Note some sources use 188 microseconds per ft.)


COMMON MATRIX VELOCITIES: (microseconds per ft.)


MATRIX:                                    VELOCITY:


Sandstone, unconsolidated            58.8 or more

Sandstone, semi-consolidated        55.6

Sandstone, consolidated                52.6

Sandstone, shaly                         57 to 70


Limestone                                  47.6

Dolomite                                    43.5

Shale                                         62.5 to 167

Calcite                                       45.5

Granite                                       50.0

Gypsum                                     52.6

Quartz                                       55.6

Salt                                           66.7



Areas having fractures including unconsolidated matrix can be inferred from an Acoustic Log.




Acoustic logging is also used for determination of cement bond in cased wells. This type of log is most often referred to as a Cement Bond Log (CBL).


Acoustic signals propagated in steel casing are observed to have large amplitude in free casing because much of the energy is retained in the casing. Whereas the opposite effect is found in casing that is in contact with a solid such as cement. The casing signal is much smaller because the energy is coupled into the surrounding cement and formation.


The thin plate velocity of sound in steel is approximately 5300 meters per second (188 microseconds per meter).


A receiver having 3 feet spacing will receive the casing signal (first arrival) at 177 microseconds plus a short additional period allowing for transit time thru the borehole fluid.


A receiver signal “time gate” is set at the time of the expected casing signal. The casing signal will be the first arrival at the receiver in free casing. The signal amplitude is recorded. A high signal amplitude indicates poor cement bond. A relatively low signal amplitude indicates good cement bond. Amplitude is normally presented on a scale of 0 to 100 percent amplitude. An area having no cement bond is represented by 100 percent amplitude. Due to the fact that well cemented pipe can never reduce the signal to “zero”, a good reference for zero signal is the best cemented portion of the cased hole. Using information obtained from a Variable Density (waveform) display referred to as a VDL display, it is possible to observe the entire receiver wave train. When cementation is complete ( good bond) from casing to cement to formation, it is possible to observe waveform shift in delta- time in the later arrivals that can be correlated to open-hole acoustic delta-time logs.




The measurement of attenuation measured in decibels (dB) is obtained from the amplitude as follows:


                        Attenuation = 20/D x Log10(A/Ao)




Attenuation is measured in decibels.


Ao is the transmitter amplitude measured in millivolts.


A is the receiver amplitude measured in millivolts.


D is the distance from the transmitter to receiver (spacing) meters or feet as specified.


Note: Attenuation refers to the reduction of amplitude. Therefore, attenuation is measured in terms of - dB.              




Sector bond tools (SBT), Radial bond tools (RBT), and Ultrasonic Imager Tools (USIT) are other options available for Cement bond applications including casing inspection.




Natural gamma radiation occurs in rock formations in varying amounts. Uranium, Thorium, Potassium, and other radioactive minerals are associated with different depositional environments. Sedimentary sandstone and Carbonate environments are low in gamma radiation. Clay and Shale formations exhibit greater amounts of gamma radiation. A log of gamma radiation in “counts” or API units will give a positive indication of the type of lithology. Interpretation of gamma log data is done based on the relative low and high count rates associated with respective “clean” and “dirty” environments. Composition of formations having more clay or shale as indicated by higher gamma count rates generally are more tightly compacted with fine particles and therefore have less porosity and permeability. Formations having high gamma count rates even though they may exhibit low water saturation are generally unfavorable for production in oil and water well environments.  


It is important to be aware that certain areas are known to have sandstone formations with higher than normal levels of radiation. These formations are sometimes erroneously interpreted. Information from an SP log can be used for correlation.


Coal formations normally have very low (almost zero) gamma radiation and contrast quite well with surrounding formations. Knowledge of local “exceptions” is an important aspect of accurate interpretation.




Gamma radiation is detected differently in every logging tool. Due to variation in detector types, tool design, detector efficiency and overall tool response, the American Petroleum Institute (API) standard of API Units is commonly used for calibration. A Test well located in Houston, Texas has been used for many years as the API reference test well. The well is designed with three layers of concrete. The top 8 feet of concrete is low radiation, the middle 8 feet is a mix of radioactive elements designed to closely match a radiation level of twice the mid-continent US shale, and the bottom 8 feet is a low activity concrete zone. A tool is calibrated in the test well by first measuring the gamma radiation counts in the low radioactivity zone which is considered to be 0 API units. A second measurement of gamma counts is the made with the detector centered in the high radioactivity zone. The high radioactivity zone corresponds to 200 API units. Secondary reference calibration jigs containing a low-level gamma radiation source are often used in the field to establish detector calibration. Operation of the detector is confirmed by placing the source at a specified distance from the detector, and then at a distance sufficiently far away to obtain background counts.  




A Neutron Log when properly calibrated (usually to an API standard) will provide important information about the content of the pore spaces within a rock matrix.  Neutrons emitted from a neutron source are slowed down and eventually captured through interaction with hydrogen atoms. Once captured, a gamma ray of capture is created.


Neutron Logging tools are designed to respond to slow Thermal Neutrons or Gamma Rays of Capture.


Since hydrocarbons and water (H20) contain hydrogen a neutron log will provide knowledge of the hydrogen in the pore spaces of the matrix.  When more hydrogen is present, more neutrons are captured, and fewer neutrons reach the neutron detector.  Conversely, lower porosity, neutrons travel farther and reach the detector, increasing neutrons counted at the detector.  In other words, increased fluid filled porosity is indicated by lower neutron count.


Neutron porosity is calculated based on neutron tool response in known lithologies having known porosity.


Tool response is specified in terms of American Petroleum Institute (API) units. The standard unit for neutron logging tools is the “API Neutron Unit”. 1000 API units is assigned to any neutron tool in a water filled hole having 7 - 7/8 inch diameter in Indiana Limestone of 19 percent porosity. One API Neutron Unit is 1/1000 of the difference between tool instrument zero and the log deflection in the Indiana Limestone section. The API test well is located at the University of Houston, Houston, Texas.


When a tool is calibrated at the API test well, its response to a standard neutron calibrator is also determined. The differential deflection produced by this two environment device is compared to the API test well deflection representing 1000 API Units. A definite number of API units can then be assigned to a tools calibrator deflection. This calibration figure must be determined for each model or series of tool.


Each tool supplier develops a transform from API units to porosity for the neutron tools they produce.


            The general equation is:  Porosity (f) = natural log (API Log counts * constant + constant)


Neutron Porosity is based on a Limestone matrix (Indiana Limestone).


A correction to obtain porosity for a sandstone matrix is: Porosity (fss) = 0.95 (f(n)) + .035




A Density Log when properly calibrated will provide reliable information about matrix bulk density.  When density is known and a specific matrix is assumed then porosity of the matrix may be determined.  A mathematical relationship exists between measured density, assumed matrix density with no porosity and the density of the material filling the pore space.  Water has a density of 1 gram per cubic centimeter. Sandstone with no porosity has a density of 2.65 grams per cubic centimeter.  If a sandstone matrix is assumed for example, then a given density of 2.00 grams per cubic centimeter allows calculation of 40 percent porosity.


The equation for porosity (f) obtained from bulk density is:  f = (rma – rb) / (rma – rf)


Where rb = Measured bulk density, rf = fluid density, rma = assumed matrix density.


For reference, Sandstone has a density of 2.65 gm/cc, Limestone is 2.71 gm/cc, Dolomite 2.87 gm/cc.




Combination of data from a Neutron Porosity Log and Bulk Density log can be helpful in identification of Lithology. A chart is used that has the known relationship between Neutron Porosity and Bulk Density for three matrices; Sandstone, Limestone, and Dolomite. It is possible to determine ratio of Sandstone/Limestone and obtain a more accurate porosity using the cross-plot chart. Results from the cross-plot chart should be correlated with known lithological information. 


Neutron porosity and density porosity are often presented in an overlay on the same scale on a log for shale and gas identification.


View a neutron-density cross-plot chart.


Cross plot methods are treated extensively in the WELLOG webinar.




If the Lithology is known to be a Sandstone and the cross-plot shows a Dolomite, then it is possible one or both sets of log data are not properly calibrated. If the cross-plot shows correlation, then it provides a closed loop between logging tool response and lithology.




Porosity data should be corrected for shale content in the zone of interest.  Porosity values are optimistic when shale is present.


Depending on the value of Rmf/Rw, either the natural gamma data or SP data is used to determine shale volume.


Correction for shale is covered extensively in the advanced pages of the WELLOG webinar. 




After the appropriate corrections are applied, a realistic Formation Evaluation can be made. It should not be under-estimated that many corrections are required to properly analyze a well log.




One objective in Log Interpretation is the evaluation of a petroleum formation for water saturation (Sw). If it assumed that only two types of fluid occur in the formation, for example oil and water.


The calculation for water saturation is as follows:       Sw =  (F * Rw / Rt)1/n


Where n is the saturation exponent (usually a value of 2).



 The oil saturation as a percent of the pore space is simply:                So = (1 – Sw)


WELLOG has an extensive log interpretation library and personnel with experience in log interpretation.


WELLOG will provide answers to your log interpretation questions free of charge!


WELLOG will provide training on Logging and Log Interpretation.


WELLOG is currently sponsoring a Web based Seminar called a “Webinar” on Log Interpretation Fundamentals.


As with most of the WELLOG website, improvements and additions occur every day.


Registration in the webinar is voluntary. Email training@wellog.com with Name, Company, and your interest in log interpretation.



If you need more information or links to other resources contact support@wellog.com



REVISED 11-24-2018  © 2003 - 2018 WELLOG  All Rights Reserved