Ancient logs are a great mystery to most people because they are not seen often and are usually discarded as useless. This latter opinion is far from the truth. Modern computer software for petrophysical analysis can glean considerable amounts of reservoir property data from these old logs, especially when the work is calibrated with core data and modern logs in nearby offset wells.

The term "ancient logs" is usually applied to the electrical survey (ES), microlog (MLC), and gamma ray neutron (GRN) that became available in the early 1930's and were in common use well into the late 1950's. At this time, induction (IES) and sonic (SL) logs gradually supplanted the ES and GRN. Early forms of the laterolog (LL7 and LL3) and microlaterologs (MLLC) were also developed to replace the ES and MLC in salt mud environments. In the early 1960's, induction, sonic, and density log presentations were fairly primitive by today's standards, and some people consider them to be ancient logs also. A brief description of all logging tools, including ancient logs, can be found in the Tool Theory section of this Handbook.

By the mid 1960's, compensated neutron and density logs (scaled in porosity units), as well as borehole compensated sonic logs, were beginning to augment porosity determination. By the mid 1970's, "ancient" logging tools disappeared from most parts of the World, but ancient tools are still run in China, the former Soviet Union republics, and other areas that could not afford newer technology.

To put this in perspective, here is a brief history timeline.




1869 First temperature log Lord Kelvin
1883 Single electrode resistivity log patented by Fred Brown
1912 First surface resistivity survey (Conrad Schlumberger)
1927 First multi-electrode electrical survey in a wellbore (in France)
1929 First electrical survey in California (also Venezuela, Russia, India)
1931 First SP log, first sidewall core gun
1932 First deviation survey, first bullet perforator
1933 First commercial temperature log
1936 First SP dipmeter
1937 First electrical log in Canada (for gold in Ontario)
1938 First gamma ray log, first neutron log
1939 First electrical log in Alberta
1941 Archie's Laws published, first caliper log
1945 First commercial neutron log
1947 First resistivity dipmeter, first induction log described
1948 First microlog, first shaped charge perforator
1948 Rw from SP published
1949 First laterolog
1952 First microlaterolog
1954 Added caliper to microlog
1956 First commercial induction log, nuclear magnetic log described
1957 First sonic log, first density log
1960 First sidewall neutron log (scaled in porosity units)
1960 First thermal decay time log
1961 First digitized dipmeter log
1962 First compensated density log (scaled in density/porosity units)
1962 First computer aided log analysis, first logarithmic resistivity scale
1963 First transmission of log images by telecopier (predecessor to FAX)
1964 First measurement while drilling logs described
1965 First commercial digital recording of log data
1966 First compensated neutron log
1969 First experimental PE curve on density log
1971 First extraterrestrial temperature log Apollo 15
1976 First desktop computer aided log analysis system LOG/MATE
1977 First computerized logging truck
1982 First use of email to transmit data via ARPaNet (predecessor to Internet)
1983 First transmission of log data by satellite from wellsite to computer center
1985 First resistivity microscanner

Many newer tools have evolved from the older ones since 1985. Various authors have specified alternate dates for these events - I have usually chosen the earliest.

Since the well files of the world are full of these ancient logs, we must learn to glean what we can from them. This article is a self contained coverage of how to analyze ancient logs to obtain shale volume, porosity, water saturation, permeability, and average reservoir properties. Methods that were once common in pre-computer days have been excluded because we now have better ways to do the same job.

The names and curve complement on older logs take a little study. The table below lists the curves available and a useful name for each. The illustrations following the table show typical log presentations from this era. Presentations were far from standard and it may take a little research to sort out who is where.

Schlumberger and Lane Wells
Curves Units Abbreviations
16" normal ohm-m R16, SN, or RESS
64" normal ohm-m R64, LN, or RESD
18' 8" lateral ohm-m R18, LT, or RLAT
* 32" limestone ohm-m R32 or RESM
spontaneous potential mv SP
10" normal ohm-m R16, SN, or RESS
40" normal ohm-m R64, LN, or RESD
15' 0" lateral ohm-m R18, LT, or RLAT
spontaneous potential mv SP
Halliburton and Welex    
* Point Source ohm-m Z, or POINT
* 16" normal ohm-m 2Z16", SN, or RESS
* 57" normal ohm-m 2Z57", 2Z5', SN, or RESS
* 64" normal ohm-m 2Z64", SN, or RESS
* 81" normal ohm-m 2Z81", 2Z7', LN, or RESD
* 16' 0" lateral ohm-m 3Z16', LT, or RLAT
* 9' 0" lateral ohm-m 3Z9', LT, or RLAT
* 16' 0" inverse lateral ohm-m 3iZ16, LT, or RLAT
* 9' 0" inverse lateral ohm-m 3iZ9', LT, RLAT
* 32" limestone ohm-m 4Z32" or RESM
* spontaneous potential mv SP
Note: Halliburton inverse lateral is same electrode configuration as Schlumberger lateral (blind spot at bottom of zone). Lateral and normal spacings could vary. Point resistivity is un-calibrated (even though a scale is shown) and cannot be used quantitatively.

Restrictions: Hole fluid should not be extremely resistive or extremely conductive. Fresh muds, little invasion, hole size constant are best.

Special Features: No longer available. Replaced by generations of induction logs. Lateral is not usually used for quantitative work. 16" normal is used as a shallow resistivity in conventional log analysis math, and 64" normal is used as a deep resistivity. Both can be corrected manually for borehole and bed thickness effects if desired. A "Limestone curve" is a symmetrical lateral curve, usually 32 inch spacing. Curve complement, electrode spacing, and log layout varied considerably between service companies, location, and era. All ES logs could have an amplified short normal, usually 5 times more sensitive than main curve.

Schlumberger ES Log from 1953. Note neat scale and curve name section (10inch and 40 inch normals and 18'8" lateral)

Halliburton ES logs from 1954 (left) and 1949 (right). Note curve names buried in body of header or in depth track, odd scale on Point Resistivity, and varying curve complement and spacings.

GeoAnalyzer Log from 1937 (left0 has unscaled SP in left track and unscaled single-point resistivity in righthand track. The curves were never named on the log heading to avoid prosecution for patent infringement.   Lane Wells Electrolog from 1948 (right) has scaled SP in righthand track and 9 foot lateral with single-point resistivity in left track. Lateral curve is scaled 0 to 40 ohm-m and single-point is 16 ohms across the track, with no zero value. Single-point resistivity cannot be used quantitatively but is useful for bed boundaries and relative resistivity values (high vs low).

ES Normal curves are symmetrical; Lateral curves are not and have a “blind spot” equal to the electrode spacing AO (usually 18’8”). This blind spot occurs at either the top or the bottom of a resistive reservoir, depending on the electrode arrangement.

Lateral curve in resistive bed, solid line is original electrode arrangement; dashed curve is inverse arrangement with blind spot at base of reservoir

Note: Halliburton inverse lateral is same electrode configuration as Schlumberger lateral (blind spot at bottom of zone). Lateral and normal spacings could vary. Point resistivity is uncalibrated (even though a scale is shown) and cannot be used quantitatively.

Bed boundaries on ES Normal curves must be adjusted for the electrode spacing. Resistive beds appear too thin and conductive beds too thick by an amount equal to the AM distance (16”, or 64”) as shown below.


Bed boundaries on 64 inch normal ES curve shows that bed thickness is short by a distance equal to AM (64 inches) on resistive beds and too thick by 64 inches in conductive beds. Note that resistive beds thinner than the tool spacing look conductive and vice versa for conductive beds.

Laterolog (LL7 or LL3)
Curves Units Abbreviation

deep laterolog resistivity ohm-m RLL or RESD
* gamma ray API GR
* spontaneous potential mv SP

Restrictions: Needs conductive mud, preferably very salty, The mud resistivity should be less than formation resistivity. SP is recorded 28 feet off depth - it may or may not be spliced on depth - if it is, 10 foot and 50 foot grid lines will not line up with rest of log. Note hybrid scale on resistivity is common.

Special Features: Good in salty mud systems. No longer available. Replaced by newer generations of laterologs. Also called Guard Log or Focused Log. RLL curve is used as a deep resistivity.


Laterolog with three linear resistivity scales

             Laterolog with hybrid scale

Microlog (MLC)
Curves Units Abbreviation
one inch lateral resistivity ohm-m R1  
two inch lateral resistivity ohm-m R2
* caliper in or mm CAL
* gamma ray API GR

Restrictions: The MLC is severely affected by mud cakes thicker than 2 inches, and by rough or large hole.

Special Features: Still available. Combinable with microlaterolog. The microlog and microlaterolog electrode pads are mounted on opposing arms of the two-arm caliper linkage. The microlog shows permeable zones by positive separation of R1 and R2 - dashed curve reads greater than solid curve - except in heavy oil and tar sands. Both tools can be run separately if requested. Used primarily in fresh mud. Can also be run with density log. R1 and R2 can be used as shallow resistivity (RESS) in computer programs.

Microlog showing positive separation
(R2 > R1. dotted curve > solid curve) indicating permeable zones.








Comparison of ES, IES, and MLC in sand - shale sequence (shaded areas are relatively clean sandstones) - note separation between curves on MLC. Colour the separation bright red and count your net sand. Compare to net sand from SP or resistivity.

Microlaterolog (MLLC)

Curves Units Abbreviation
microlaterolog resistivity ohm-m RMLL or RESS
caliper in or mm CAL
* gamma ray API GR

Restrictions: The MLL is severely affected by mud cake thicker than 3/8 inch.

Special Features: The microlog and microlaterolog pads are mounted on opposing arms of the two-arm caliper linkage. Both tools can be run separately if requested. Used primarily in salty mud. RMLL can be used for a shallow resistivity curve (RESS). Newer tools are proximity log or micro-spherically focused log.


Microlaterolog on linear scale. Low resistivity indicates porosity, shale, fractures or rough hole.



Gamma Ray Neutron (GRN)

Curves Units Abbreviation
* neutron counts api or cps NCPS or NEUT
* gamma ray api or ug Ra equiv/ton GR
* casing collar mv CCL

Restrictions: Neutron count rate affected by borehole fluid, hole size, centering, and rock type. Porosity derivation is therefore approximate and charts used must be specific to the tool type and borehole environment.

Special Features: Gamma ray and neutron curves could be run separately or combined on same log. Still used for cased hole depth control. Replaced by compensated neutron logs scaled in porosity units. This tool is not normally used for quantitative porosity although it is used when no other logs are available in the well. Can be used in air, gas, or liquid filled holes and can be logged through casing. Older logs were very insensitive and suffered from large statistical variations (poor repeatability).

Logarithmic scaler for reading porosity from an un-scaled neutron log. Draw vertical line on log at low porosity point (say porosity = 0.05) and another line at high porosity point (usually a shale - say porosity is 0.30). Align scaler between the two lines, setting 0.05 on scaler at low porosity line, and 0.30 on scaler on high porosity line. Skew scaler to obtain good fit. Mark other porosity points on log. Enlarge or reduce scaler in copier to fit smaller or larger logs. High and low porosity points are a matter of good judgment tempered by core or log analysis results from modern wells.

Typical GRN log with gamma ray (GR) and un-scaled neutron log (NEUT). Use the scaler to draw a porosity scale on this log.




ES and GRN in gas over oil over water - Note 18'8" blind spot on lateral curve, which explains why we
don't use it for quantitative work in computer programs. The blind spot on this lateral curve is at the
top of the zone. This is the original electrode arrangement. It was soon inverted to put the blind spot
on the bottom of the zone (inverse lateral arrangement). Also note backup scale on 16" and 64"
normal. Draw oil-water contact on this log.

Laterolog (LL3), old style sonic (SL), and microlaterolog (MLLC) - note hybrid resistivity scale on LL and thin porosity streaks on MLLC not seen by other logs. Colour shale beds grey, colour porous streaks red.

There are special rules for picking the formation resistivity from the long normal (RESD in this book, Rt in most of the literature). These are empirical rules that work reasonably well and circumvent the need for bed thickness and borehole corrections. The rules are shown in the top half of of the illustration below..

Rules for estimating RESD (Rt) from long normal (R64) and lateral (R18)

The lateral curve on an ES log is not symmetrical and leaves a blind spot at the top or bottom of a resistive bed (pay zones). The normal practice in most parts of the world is to run the electrode arrangement, called the inverse lateral, that puts the blind spot on the bottom of the reservoir. The blind spot is the thickness of the tool spacing, 18'8" for typical tools. The blind spot shows low resistivity when it ought to show high resistivity, so the bottom 19 feet of the pay zone looks wet. If the other electrode arrangement is used, the top 19 feet look wet, as illustrated at right.

Inverse lateral (dotted curve) and original lateral (solid curve)
 showing blind spot at bottom and top of reservoir respectively.

The lateral curve can be used for handpicked data by following the special rules shown above. Because the lateral curve has a blind spot over the top or bottom of every resistive zone, it cannot be used in computer aided log analysis unless it is pre-processed with resistivity inversion software. However, even this sophisticated software is a poor solution, as it tends to draw a straight line through the blind zone, which you or I could do faster and cheaper with a red pencil.

 Shale Volume
Shale is an imprecise term used to describe a rock composed of clay, silt, and bound water. The clay type and silt composition can vary considerably from one place to another. These can be determined from appropriate cross plots of PE, thorium, and potassium logs. The bound water volume varies with clay type, depth of burial, and burial history. Some shales have not lost as much water as others at similar depths and are called over-pressured shales. Most shales are radioactive due to potassium and thorium, and sometimes due to uranium.

In ancient wells, the logs available for shale calculation are more limited than in modern wells. The usual curves are gamma ray, spontaneous potential, and shallow resistivity. Many ancient wells have been re-logged through casing with gamma ray, neutron, and thermal neutron decay (TDT) logs. There may even be modern logs such as spectral gamma ray, sonic (compressional and shear), compensated neutron, even resistivity. There may be a large number of suitable curves to choose from. Density logging through casing is exceedingly rare, so the density neutron crossplot method for shale volume will be unavailable.

Shale volume estimation is the first calculation step in a log analysis. All other calculations depend on the shale volume being known from this step.

STEP 1: Calculate shale volume from all available methods:
      1: Vshg = (GR - GR0) / (GR100 - GR0)
      2: Vshs = (SP - SP0) / (SP100 - SP0)
      3: Vshr = (logRESS - logRMAX) / (logRSH - logRMAX)

NOTE: Trim values between 0.0 and 1.0. If too many values fall outside this range, check the clean and shale parameters. Do not calculate methods which fail to pass all usage rules listed below.

STEP 2: Adjust gamma ray method for young rocks, if needed:
      4: Vshc = 1.7 - (3.38 - (Vshg + 0.7) ^ 2) ^ 0.5

STEP 3: Take minimum of available methods:
      5: Vsh = Min (Vshg, Vshs, Vshr, Vshc)

If SP is missing, flat, or noisy, we can calculate a replacement SP.  In hydrocarbon bearing sand shale sequences ONLY,:
       6: SPpseudo = - 50 * log (RESS / RSH)

And in water zones ONLY:
      7: SPpseudo = - 20 * log (RESS / RESD)

Both constants can be varied. Note the negative sign. By taking the most negative answer from both equations, a continuous SPpseudo can be generated without zoning.

RESD must be from a 64 inch normal or a laterolog (or an old induction log) which are symmetrical curves, and NOT from a lateral curve, which has a blind spot on top or bottom of pay zones, depending on electrode arrangement and spacing.

RESS is usually a 16 inch normal.

Neither technique is useful in salt mud systems.

Use uranium corrected gamma ray (CGR) in preference to uncorrected GR
Do not use GR in radioactive sandstones or carbonates. Use Thorium curve from NGT for radioactive sandstone, and uranium corrected GR (CGR) curve for radioactive carbonates.
Do not use SP in fresh water formations, salt mud systems, high resistivity zones, or in carbonates.
Do not use the nonlinear young rock model unless there is some evidence that it is needed.
Resistivity method only works in hydrocarbon zones
On older gamma ray logs with no numerical scale, or logs scaled in ug Ra eqiv/ton, choose an arbitrary scale to match offset logs (eg 0 to 150 API units).
For SP logs, it is convenient to use a scale of 0 to 100 across the track, or any arbitrary scale (minus 80 to plus 20 is widely used).
GR and SP may need bed thickness corrections - see service company chartbooks.

If log analysis porosity is too low, calculated shale volume may be too high (or vice versa).

The shale in the zone may not have the same properties as nearby shales seen on the log. Therefore, some adjustments to shale properties might be necessary.

Shale can be structural, dispersed, or laminated. Shale volume calculations give averages over several feet. Different distributions will affect resistivity, porosity, and permeability differently, so these calculations will be affected by assumptions about distribution. Special rules for laminated shaly sands are required and are covered elsewhere.

Ancient sonic logs are those with one transmitter and 1 or 2 receivers, run from about 1957 to about 1966 when borehole compensated (BHCS) tools were put into service.

The Wyllie equation is used to find total porosity. For a dual receiver tool:
      8: PHIS = (DTC - DTCMA) / (DTCW - DTCMA)

OR For a single receiver tool:
      8a: PHIS = ((DTC / SPAN) - DTCMA) / (DTCW - DTCMA)

  SPAN = distance between transmitter and receiver (plus a fudge factor of 10 to 20% to account for the slower sound velocity of the mud between transmitter and borehole wall and from borehole wall to receiver). Calibrste to core or offset wells with better data.

NOTE: See CASE 1 below for lack of compaction correction.

Correct sonic porosity for shale
       9: PHISSH = (DTCSH - DTCMA) / (DTCW - DTCMA)
       10: PHIsc = PHIS - Vsh * PHISSH
       11: PHIe = PHIsc

  CASE 1: Correct each layer for lack of compaction, ONLY IF DTCSH > 328 (Metric) or DTCSH > 100 (English)
    12a: KCP = Max(1, DTCSH / 100)  English Units (usec/ft)
OR  12b: KCP = Max(1, DTCSH / 328)  Metric Units (usec/m)
OR  12c: KCP = PHIsc / PHItrue
    13: PHIe = PHIsc / KCP

PHItrue PHIcore  or PHIe from shale corrected density neutron complex lithology porosity model in an offset well.

  CASE 2: Correct each layer for gas effect, ONLY IF PHIsc > PHItrue and gas is known or suspected:
    14 PHIe = PHIsc * KS

NOTE: It may be necessary to combine Cases 1 and 2 to obtain a single correction factor.

Ancient sonic logs are recorded in microseconds per foot. The oldest tools are single receiver, recorded in microseconds The total travel tine is usually too high because of the travel time through the mud. Some present total travel time from transmitter to receiver, so this value must be divided by the tool spacing to get usec/ft.

Comparison of single receiver sonic (Y-axis) with 2-receiver sonic log, showing higher DTC of single receiver version

Many ancient sonic logs give unrealistic porosity values, others have chronic cycle skips, mostly to high values.

Changes in borehole size also cause spikes on the log, to both the high and low travel time directions. These are not cycle skips, but are due to the unequal travel time to each detector through the mud in the brehole.

Example of single transmitter sonic log with spikes (crosshatched areas) caused by variations in hole size. These should be edited or trimmed off before using the log data for porosity calculations.




 Porosity FROM anCiENT DENSITY logs
Ancient density logs are recorded in counts per second. You get to work out the transform to density using a semi-logarithmic High - Low porosity technique as described for the neutron log. Here, high count rate = low density = high porosity. Semi-log crossplots of count rate versus core density or core porosity will calibrate the method. Charts for some specific tools can be found in the literature, such as the one shown below.

Counts per second to density transform for a Schlumberger PGT-A density tool. Each tool iteration and each service company requires a specific chart. Density varies with hole size  mud weight, and  , An equation for the 8 inch borehole case is DENScps = -0.88 * LOG(CPS) + 4.71

      13: PHID = (DENS - DENSMA) / (DENSW - DENSMA)

Apply density shale correction:
      15: PHIdc = PHID - Vsh * PHIDSH

These tools are severely affected by hole size, mud weight, mud cake thickness, source type and strength, source detector spacing, and detector efficiency. The High-Low calibration method compensates for all these problems, but available charts do not. In the earliest versions of these tools, the source strength decayed  rapidly, so count rates definitely need to be normalized on a well by well basis.

Most density transforms never made it into published chart books. This one did - Schlumberger PGT-C or D density count rates to porosity. Additional charts are available to correct for mud cake thickness and mud weight, and for air-filled holes. The count rate charts appeared in 1966 chart books, well after they were no longer needed, and disappeared after 1968. Most density count rate charts are very hard to find unless you have a good supply of ancient chart books from 1958 through 1968 - a 10 CD set of ancient chart books was published by Denver Well Log Society and sold through SPWLA.

An alternate to the semi-log High-Low method was used with early neutron and density logs. This involves "relative count rate excursions" and service company charts of these values versus the desired rock property (porosity, density). The problem, of course, is that you need the chart unique to each tool and sufficient patience to do the constructions. Below is the instruction set developed by Lane Wells from their 1964 Technical Bulletin on their Densilog Tool.

Instructions for the "relative deflection" method for transforming density log count rates to density, from the 1964 Lane Wells Densilog Technical Bulletin.  Full size response charts are in the same book.

Old style gamma ray neutron (GRN) logs are un-scaled neutron logs recorded in counts per second or API units. They are common in ancient wells. The log carries a gamma ray curve (GR) in the left hand track and a neutron curve (NEUT) in the right hand track. No borehole or casing corrections have been applied to these logs. Neutron log deflections to the left (lower count rate) represent higher porosity.

A large number of charts for specific tools, spacings, borehole conditions and rock types were available from service companies, such as the one shown below. These may no longer be easily found today, and the semi-logarithmic approach described below works well except in very low porosity .

GNT-F or G neutron porosity interpretation chart. Hundreds of such charts exist for dozens of tools for a large range of hole sizes, mud weights, and casing sizes. most are not contained in conventional chart books. Some are available on the Denver Well Log Society CD set sold by SPWLA.

There were three source types used (RaBe, PuBe, and AmBe) and several source - detector spacings (15.5 and 18.5 inches were common), combined with hole size, mud weight, and casing variations, leading to a plethora of transforms. Some service companies didn't have a lot of faith in their charts - one used the term "Strata Index" instead of "Porosity" on the Y-axis.

If no appropriate chart exists, or if you don't believe in them, it is expedient to use the "High porosity- Low porosity" method.

  1. Select a high porosity point on the log, usually a shale, and assign it a porosity based on offset wells with scaled logs or a local compaction curve. This is PHIHI.

  2. Pick the count rate on the neutron log at this point - this is CPSHI, even though it is a low numerical value.

  3. Choose a low porosity point on the log. Assign this a porosity value, again based on offset scaled porosity logs or core porosity. This is PHILO. Tight lime stringers or anhydrite are best but you need some imagination if there are no truly low porosity streaks.

  4. Pick the corresponding count rate on the log. This CPSLO, even though it is a larger number than CPSHI.

  5. Plot these points on semi-log graph paper as shown below. Read porosity for any other count rate from the graph.

Example of Porosity from Neutron Counts per Second - no shale correction

To use this plot in a calculator or computer instead of on a graph:
      16: SLOPE = (log (PHIHI / PHILO)) / (CPSHI - CPSLO)
      17: INTCPT = PHIHI / (10 ^ (CPSHI * SLOPE))
      18: PHIn = INTCPT * 10 ^ (SLOPE * NCPS)

Correct scaled neutron porosity for shale effect
      19: PHInc = PHIn – Vsh * PHINSH

Semi-log crossplot of count rate versus porosity for a group of Russian log data

Use only if sonic and density log are unavailable or unusable.
Do not use in gas zones - very pessimistic results, correction for gas difficult.
The neutron log corrected for shale is one of the least accurate methods in shaly sands and should only be used if no other porosity data is available. This is common for wells drilled prior to 1957 or for wells logged through casing or drill pipe.

To calibrate to core porosity, adjust PHIHI, PHILO, PHINSH or Vsh to obtain a better match by trial and error. Appropriate crossplots may assist.

Scaled neutron logs are also common in ancient wells, having been run through casing sometime after the original logs were run. They will have a GR curve and a neutron porosity curve (PHIN in this Handbook), the latter may have lithology, borehole, or casing corrections already applied. If it does not have these corrections, service company charts are used to apply the corrections. Read the log heading carefully to determine what has already been done.

CAUTION: In dolomite zones, many so-called compensated cased hole neutron logs did not present a rational value for porosity. This appears to have been fixed in recent years. Always compare results in carbonates with offset open hole logs or core data.

 Porosity FROM ES and Micrologs
There are a number of techniques for handling ancient logs like the old electrical survey (ES) and microlog (MLC). The ES log has 3 resistivity curves, the long normal or 64 inch normal (LN), the short normal or 16 inch normal (SN), and the 18' 8" lateral curve (not to be confused with a laterolog). The SN curve can be used as a shallow resistivity log (RESS in this Handbook) and the LN can be used as a deep resistivity (RESD in this Handbook). The ES log also has a spontaneous potential (SP) curve used to find shale volume or water resistivity in sand-shale sequences.

There are hundreds of charts used to perform borehole and bed thickness corrections to these curves. For typical fresh mud in an 8 inch (200 mm) borehole in a bed thicker than 8 feet, these corrections are small enough to be ignored. Charts for these corrections can be obtained on request from service companies.

The simplest porosity from resistivity method is to use the shallow resistivity and assume that the flushed zone water saturation is near 1.0.
      20: PHIxo = (A / ((RXO / RMF@FT) * (SXO ^ N))) ^ (l / M)

RXO is taken equal to the 16 inch normal (R16 or SN) or the microlog R1 value.
Use only if no other porosity log is available.
Not recommended in heavy oil or tar sands because SXO is low due to lack of invasion by mud filtrate.

Sandstones A= 0.62, M = 2.15, N = 2.00
Carbonates A= 1.00, M = 2.00, N = 2.00
Water Zone SXO = 1.00
Oil / Gas Zone SXO = 0.70 - 0.90
Heavy Oil / Tar Sand SXO = 0.10 - 0.35

The microlog has two very shallow resistivity curves, the 1 inch (R1 - solid line) and 2 inch (R2 - dashed line). This data can also be used in the following:
      21: IF R2 > R1 (dashed curve is right side of solid curve)
      22: THEN PHIml = 0.614 * ((RMF@FT * KML) ^ 0.61) / (R2 ^ 0.75)
      23: OTHERWISE PHIml = 0

Use only if no other porosity log is available.
Not recommended in heavy oil or tar sands because of lack of invasion by mud filtrate.

Mud Weight KML
lb/gal kg/m3 frac
8 1000 1.000
10 1200 0.847
11 1325 0.708
12 1440 0.584
13 1550 0.488
14 1680 0.412
16 1920 0.380
18 2160 0.350

Maximum Porosity Method
In ancient wells, there may be no porosity logs of any kind. In addition, resistivity methods may be ineffective due to lack of invasion (heavy oil) or thin bed effects. The maximum porosity method is quite useful in shaly sands, but may not be helpful in a carbonate sequence.

Choosing PHIMAX from a plot of Vsh vs PHIe from offset well - high porosity at high Vsh on this plot is from bad density data in rough borehole .

Calculate PHImx
      24: PHImx = PHIMAX * (1 - Vsh)

If there is no other porosity calculation method that works, then PHIe = PHImx.

Bad hole, bad cement, high shale volume, and statistical variations can cause erratic results when a scaled or un-scaled neutron log is used, Values of porosity from any method should be trimmed by the following:
      25: IF PHIe < 0
      26: THEN PHIe = 0
      27: IF PHIe > PHIMAX * (1 - Vsh)
      28: THEN PHIe = PHIMAX * (1 - Vsh)

Use always to trim excessive porosity due to wet shales or bad hole conditions.
Use as a porosity method in shaly sands.

This material balance prevents the sum of shale volume, porosity, and rock matrix from exceeding 100%, and prevents porosity in the sand fraction of a shaly sand from reaching ridiculous values. It is useful for estimating porosity in shaly sands where only an SP or gamma ray log is available.

CAUTION: Bear in mind that this approach provides a porosity value based only upon the shale content and the analyst's assumed maximum possible porosity. With offset well data for control this is not a bad approach for wells with a very limited log suite. It is often used in computer analysis of ancient logs. Because of its gross assumptions, a warning note should be annotated on the results, if the method is used in this manner.

The third step in a log analysis is usually a lithology calculation. The log suite in an ancient well does not provide data suitable for such a calculation, unless some modern tools have been run through casing (such as the dipole shear sonic with a compensated neutron, or an induced gamma ray spectral log (GST) or equivalent. In most cases, the lithology description comes from core and sample descriptions, core analysis grain density, or log analysis in offset wells.

All the usual water resistivity and water saturation methods covered elsewhere in this Handbook can be used once shale volume and porosity have been determined. You can chose from anyone of more than 20 possibilities. I prefer to use the 64 inch Normal curve in sand shale sequences, as it sees deep enough as a rule, has sharp bed boundaries in fresh mud and has symmetrical curve shape. In salt mud or any mud system with high resistivity rocks, use the laterolog (not the lateral curve) as your deep resistivity. The laterolog has about a 3 foot bed resolution compared to 5 feet for the 64" Normal, so use the laterolog if you have a choice.

Prior to about 1950, there were no laterologs, so you are stuck with ES curves. In large boreholes or salty mud, environmental corrections could be large and necessary. You will need appropriate service company chartbooks or resistivity inversion software. I recommend the latter, using SP and 16" Normal and the tool dimensions, to correct the 64" Normal.

If porosity is still doubtful, try the model in the next Section.

Water Saturation and Porosity from Ratio Method
When no porosity data is available, saturation can be obtained by comparing the shallow and deep resistivity logs. This formula is not shale corrected but the chart below is.

Calculate water saturation
      29: SWrt = SXO * ((RXO / RESD) / (RMF@FT / RW@FT)) ^ (1 / N)

SWrt becomes SWe if there is no other method available.

Calculate porosity
      30: PHIrt = (A / ((RESD / RW@FT) * (SWrt ^ N))) ^ (l / M)
      31: PHIxo = (A / ((RESS / RMF@FT) * (SXO ^ N))) ^ (l / M)

Use 64 inch normal or laterolog as RESD, use 16 inch normal or microlog as RESS.
Do not use lateral as RESD.
Use only if no other porosity log is available.
Do not use in heavy oil or tar sands because SXO is difficult to estimate.
See below for a graphical solution to this formula, with additional shale correction if needed.

Sandstones A= 0.62, M = 2.15, N = 2.00
Carbonates A= 1.00, M = 2.00, N = 2.00
for water zone SXO = 1.00
for hydrocarbon zone with high porosity SXO = 0.60
for hydrocarbon zone with medium porosity SXO = 0.70
for hydrocarbon zone with low porosity SXO = 0.80
for heavy oil and tar sands, SXO = SW = 0.10 to 0.30

Graphical solution for Ratio method (with shale correction from SP)

Modern Resistivity Inversion Software
In the last few years, there has been a strong trend towards inverse modeling of all forms of resistivity logs (including the SP curve). This is due to the availability of computer code that performs an exact inverse solution to model the resistivity, similar to that in use for focusing the array induction log. By programming the tool geometry and extracting bed boundary data from a shallow, thin bed resistivity log, the inverse model of deep resistivity can be extracted from all older logging tools. This includes dual induction and dual laterologs (which are still being run today) as well as the more ancient ES log.

An example of resistivity inversion results for a 18'8" lateral curve (left) and an older style induction log (middle ) compared to an array induction log (right). The SP is modeled in all three cases, and may be the most useful curve of the bunch. The modeling of the lateral curve gives a straight line through the blind zone. Modeling the 64 inch normal would probably give more realistic results.

 Case Histories
Once shale volume, porosity, and water saturation are determined from conventional or ancient methods, permeability, productivity, net pay, and reserves are found by the normal methods outlined elsewhere in this Handbook.

Calibrating Ancient to Modern Logs (Shaly Sand)
One way to test the techniques for ancient logs is to run the math on a modern log suite and compare results to the same logs after eliminating all the curves that would not have been available in ancient times. In this well, we have conventional induction-electrical and density-neutron logs in a heavy oil well. By assuming that the induction resistivity is similar to a 64 inch normal and that the only shale indicator is the SP, we can compare this "ancient" log suite with the modern version in the identical rock/fluid sequence using standard computer-aided log analysis.

IES and CNL FDC for heavy oil case history 1978

Conventional log analysis using GR, CNL, and FDC. Pick water contact in GP sandstone. Is there a contact in the Sparky sandstone? Compare your answer to resistivity log.

Same well computed with IES, SP, and PHIMAX = 0.34. Compare to results in previous illustration.

Although the induction resistivity is focused better than a 64 inch normal, this example shows that the PHIMAX method is quite suitable in a shaly sand sequence.

Lake Maracaibo (Shaly Sand)
This case history is taken from "Quantitative Analysis of Older Logs For Porosity and Permeability, Lake Maracaibo, Western Flank Reservoirs, Venezuela" by E. R. (Ross) Crain, P.Eng. Manuel Garrido, Craig Lamb, P.Geol., Philip Mosher, P.Eng. presented at GeoCanada 2000, Calgary, AB, May 2000.

During a project to analyze the log and core data on 150 wells in the Western Flank Reservoirs offshore in Lake Maracaibo, we developed a technique to determine accurate values of porosity, water saturation, and permeability from old ES logs. The depositional environment is a complicated sequence of superimposed fluvial channels, resulting in many isolated channels that were not fully drained by nearby wells. It was therefore necessary to obtain a quantitative reservoir description for all wells in the project area, even if the log suite did not lend itself to direct calculation with traditional log analysis methods.

These highly detailed reservoir properties from log analysis were augmented by similarly detailed seismic and stratigraphic correlations, and integrated together in a reservoir simulator to provide an accurate historical and predictive model for production optimization. We would not have been able to do this to a useable level if only the wells with full porosity log suites were used.

The method used requires calibration to conventional and special core data and/or modern porosity log suites. Conventional core analysis data, electrical properties, and capillary pressure data was provided in paper form. This data was entered into a spreadsheet database for processing and was placed in each well file for depth plotting with the log data. Core data was depth shifted to match well log depths.

Our objective was to define a method that would utilize all available log and core data while providing the most consistent results between old and new well log suites. A detailed foot-by-foot analysis was required to allow summations of reservoir properties over each of many stratigraphic horizons.

Shale volume (Vsh) was calculated from the gamma ray (GR), spontaneous potential (SP), and deep resistivity (RESD) responses. The minimum of these three values at each level was selected as the final value for shale volume. A unique clean sand and pure shale value for GR, SP, and RESD were chosen for each zone in each well. A linear relationship was applied to the Vsh from GR. The resistivity equation for Vsh is similar to the GR equation, but uses the logarithm of resistivity in each variable.

Where a full suite of porosity logs was available, effective porosity (PHIe) was based on a shale corrected complex lithology model using PEF, density, and neutron data. The method is quite reliable in a wide variety of rock types. No matrix parameters are needed by this model unless light hydrocarbons are present. Shale corrected density and neutron data are used as input to the model. Results depend on shale volume and the density and neutron shale properties selected for the calculation. Therefore, the porosity from this stage is compared to core porosity where possible, and parameters are revised until a satisfactory match is obtained.

In wells with an incomplete suite of porosity logs, we used a model based on the shale corrected density log, shale corrected neutron log, or the shale corrected sonic log. Again, a comparison with core or nearby offset wells with a full log suite is necessary to confirm shale and matrix parameters.

In wells without any porosity logs, porosity was based on the shale corrected total porosity model, where total porosity (PHIMAX) was derived from offset wells with porosity logs or from nearby core analysis. The equation used was PHIe = PHIMAX * (1 - Vsh). This step was the most important contribution to the project as it integrates all available data in all wells in a consistent manner.

The value for PHIMAX was derived from a map of the average of the total porosity of very clean sands in modern or cored wells. The map was inspected and a transform created which varied the PHIMAX value from south to north through the project area. The effectiveness of this method is demonstrated by the close match between core and log analysis porosity in well LMA 11, shown in Figure 1. Another way to see this relationship is in a crossplot of log derived shale volume versus core porosity as in Figure 2.

In modern wells, PHIMAX is also used to limit the porosity results. This limit is needed because rough hole conditions or sonic cycle skips can cause erroneous porosity values to be computed. PHIMAX is computed as above, but modified by adding 0.03 to the result. This higher value for PHIMAX prevents the reduction of those few legitimate porosity results which are slightly higher than usual on the logs.

From this stage onward, both old and new wells were treated identically, with water saturation, permeability, and mappable reservoir properties being derived in a uniform and consistent manner.

Water resistivity (RW) was varied with depth to account for the temperature gradient over the computed interval. These values were confirmed by the obvious water zones in the lower sands in a number of wells. Care must be taken to segregate swept zones from original water zones when checking the RW value. Swept zones show residual oil on log analysis of between 20 and 60 percent. Back calculation of RW in a swept zone will lead too high a value for RW.

Water saturation (Sw) was computed with a shale correction using the Simandoux equation and with the Waxman-Smits equation. Both equations reduce to the Archie equation when shale volume is zero. Simandoux and Waxman-Smits methods gave very similar results in this project area. The resistivity curves used were the long normal from ES logs, the deep induction, or the deep laterolog.

The shale resistivity (RSH) needed for these equations was chosen by observation of the logs and crossplots. RSH was varied from well to well to account for differences in response between electrical logs, induction logs, and laterologs in shale. Resistivity anisotropy and hole size or mud resistivity effects cause these differences. The range of values used is small, between 4.0 and 5.0 ohm-m.

Values of A, M, and N of 1.00, 1.80, and 2.00 were input, based on special core analysis crossplots. The effect of overburden pressure on M and N was compared to non-overburden data on the plots where such data was available. The regression lines for M were pinned at A = 1.0 because the free regression lines vary too much, due to the small range in porosity of the core plugs.

Saturation results were confirmed by comparison to porosity vs capillary pressure water saturation crossplots derived from the special core data (Figure 3). When this data is missing in a project area, it is very difficult to refine the saturation calculation. If a mismatch does occur, the electrical properties and/or RW and temperature data must be reviewed and modified if possible, to obtain a better match to capillary pressure data.

Zones swept by production from older offset wells are evident on all newer wells in this project. These zones should not be confused with the original water zones. Swept zones will produce water if perforated, but contain 20 to 60 percent residual oil. On raw logs, the difference in resistivity between a swept zone and an original water zone may be very small (eg 0.4 vs 0.2 ohm-m in an extreme case).

An irreducible water saturation (SWir) was calculated based on a curve fit to the capillary pressure data, using the following: IF PHIe > 0.10 THEN SWir = 0.20 / (PHIe - 0.10) ELSE SWir = 1.00. This equation represents a skewed hyperbola through the porosity vs saturation data.

SWir was also limited by the Simandoux water saturation such that SWir could not exceed the Simandoux result. This means that SWir is the lower of the actual log derived water saturation and the SWir calculated above. The swept zones are most easily seen on depth plots by comparing SWir to the Simandoux or Waxman-Smits water saturation. Where large differences occur, the zone is likely swept.

Crossplots of core porosity vs core permeability (Figure 4) gave: Perm = 10 ^ (23.0 * PHIe - 3.00). Detailed crossplots of each zone in each well, composite plots of each zone for all wells, and a composite plot of all zones in all wells were made. Differences between zones and between wells were negligible. Regression analysis to predict permeability from porosity produces a good average permeability within a zone. It may not always honour every peak and valley seen on real cores.

Crossplots of permeability vs capillary pressure water saturation were also made. These show a semi-logarithmic straight line relationship. The plots show that water saturation and permeability are closely related. High water saturations indicate fine grained, more poorly sorted, lower permeability, and often shalier zones.

Crossplots of permeability vs residual oil saturation also show a semi-logarithmic straight line relationship with higher permeability having lower residual oil saturations. This is a normal occurrence, and allows a check of the residual oil saturation seen in swept zones by log analysis.

Results of analysis on ancient logs, Lake Maracaibo, Venezuela. Compare core porosity (black curve in left track) with porosity from PHIMAX (red curve).

On older wells, previous work used a two step correlation of oil saturation (So) times porosity (PHI) to the short normal resistivity (SN) and mud resistivity (RM), of the form:
      1. ln(RT/RM) = A + B * ln(SN/RM)
      2. SOPHI = C + D * ln(RT)

This method was developed by Dr Ovidio Suarez and is documented in internal reports provided by the client. The parameters A through D were derived from correlations with hydrocarbon pore volume (HPV) estimated from core analysis. The method does not account for borehole effects, invasion, or variations in grain size, sorting, or shaliness, all of which influence HPV from this type of correlation. It also does not generate a porosity value, so results cannot be compared easily to core data and cannot be used to calculate permeability. Large differences in results between adjacent wells were noted, leading to the conclusion that these inconsistencies should be addressed in our new work.

In the porosity track of Figure 37.17 (above), the green line is porosity from SOPHI based on the SWe derived in our study: PHIrt = SOPHI / (1- SWe). This well shows a good agreement between the two methods but others do not, because the short normal is not always a good indicator for RT.

It should be noted, however, that at the time the method was invented, it was the best approach available for un-cored intervals, since modern porosity indicating logs had not yet appeared on the scene.

The results of this study will lead to a significant change in original oil-in-place compared to the value determined from a strict use of the prior petrophysical analysis. In addition, all by-passed pay zones are identified and can become targets for specific in-fill wells. The reservoir simulation based on this new reservoir description will have greater predictive power and will be easier to history match because both reservoir volume and flow capacity are better defined.

Page Views ---- Since 01 Jan 2015
Copyright 2023 by Accessible Petrophysics Ltd.
 CPH Logo, "CPH", "CPH Gold Member", "CPH Platinum Member", "Crain's Rules", "Meta/Log", "Computer-Ready-Math", "Petro/Fusion Scripts" are Trademarks of the Author