You will need blank forms or a computer and appropriate software to
write your log analysis report. I currently use a spreadsheet and word processor off the shelf, but corporate policy may force you to use more cumbersome packages. The commentary should be written uniquely for each job, to cover the who, why, what, when, where, results, and recommendations. Some “copy and paste” is allowed but try to provide some original insights into each job.

Illustrative examples of crossplots, raw logs, answer plots, and tables of results, for example net pay summaries, are commonly included. Equations should be used only to explain a concept - the complete computer code is not required. Copies of all depth plots are usually delivered with the report as separate electronic images. Tables are also delivered separately as electronic spreadsheets.

Tables of results and graphs are usually copied to the text document. These should be embedded near the appropriate text, if possible. Large tables may appear at the end of the report.

A typical petrophysics report contains some or all of the following topivs:

1. Introduction or Executive Summary: this should include who the job was done for, the overall objective of the project, names and locations of wells and zones of interest, and a brief geological / mineralogical description of the zones of interest.

2. Data Available; describe log types and ages, core, XRD, petrography, sample descriptions, perforation and test intervals, production histories; comment on quality of each and especially what was missing that could have been useful.

3. Analysis Method; in words, explain the individual method used to calculate shale volume, porosity, lithology, water resistivity, water saturation, permeability, and net pay; describe how parameters were selected, and how well log analysis results match core and lab data; keep equations to a bare minimum. In unconventional reservoirs, describe what factors about the reservoir are unconventional and describe how additional parameters such as TOC weight fraction and kerogen volume were calculated. If mechanical properties were calculated, describe the log reconstruction method, list the basic properties that were derived, and the presence of any lab data that might be used for calibration.

4. Discussion of Results; may be omitted if covered in methodology; compare log analysis results to core and lab data, production history, etc, on a well by well basis.

5. Conclusions and Recommendations; discuss data quality, results quality compared to core, missing data, further lab work needed; come to a conclusion - the well (pool, project) is ......

6. Disclaimer; you were not there, you didn't do it, and it's not your fault anyway.

Your name is on the report, be proud of it. Log analysis reports hang around in well files for years. Don't leave a shoddy product that will come back to haunt you.

Use clear, positive statements. Write as if talking out loud to an equal, but keep it organized and logical. Every sentence needs at least one noun and one verb.

We all learned to do this in high school physics lab, so it's not really that hard.

Keep it short and sweet - most petrophysical reports on small projects are less than five pages of text plus cover page and tables of results.

A full field study may contain hundreds of pages from numerous authors, with geology, geophysics, engineering, and simulation sections, 100's of maps and graphs and well log displays. Keeping all this well organized and useful will take some skill and effort. Short reports don't need an executive summary but long reports definitely do. Long reports also need a table of contents, table of illustrations, and a clearly organized structure.


"Requisite to a clear understanding of the interpretation of mud-gas data is consideration of the source of hydrocarbons as they occur in the drilling mud. To assist in this consideration, a simple drilling model is proposed which illustrates the impact of bit penetration through hydrocarbon accumulations. A series of cases is presented where variations in the configuration of the mud-gas data indicated specific differences in the response of the hydrocarbon bearing zone to bit penetration and subsequent rig operations.

The model will show that the geometry of the gas kick recorded by the instrumentation and plotted with respect to time is directly related to significant characteristics of the hydrocarbon zone as well as the impact of concurrent drilling operations. It will become apparent that the configuration of the gas kick as recorded directly from the drilling mud is of greater interpretive significance than the magnitude of the gas kick. When instrument chart data recorded versus time is digitized and plotted in graph format versus depth, the magnitude of the gas kick may be faithfully reproduced but the configuration of the kick is usually lost.

Thus it becomes obvious that basic and vital interpretation must derive from a detailed analysis of the instrument charts themselves and not solely from a plotted graph. The basic function of the plotted graph should be to collate, according to depth, pertinent data produced from various sources. This graph then provides a broader understanding of the hydrocarbon accumulation and a convenient means for future reference.

To illustrate these concepts, a diagrammatic technique has been employed which graphically relates the gas detector response plotted versus time to the actual penetration of the rock by the drilling bit through the penetration rate curve plotted versus depth. This technique allows direct comparison of the geometry of the gas kick to actual rock penetration."

Scroll down to see four different, easy to read Petrophysical Reports.

Petrophysical Analysis Report - Conventional Reservoir
24 Month 2012

We were requested by Some One of Company A to review the log, core, and test data on the subject well, and to perform an independent petrophysical analysis on the A and T formations.


Available Data
Log data for this project is relatively sparse:

A Fm:
       xxx - xxx m No logs
       xxx - xxx m Induction, SP, Sonic, No GR or Caliper xxx - xxx m As above plus GR, Caliper, poor quality

T Fm:
       xxxx - xxxx m As above

An analyzed core was available just below the main porous interval in the T Fm. Reported depths on this core appear to be 11 meters shallow (approx one pipe joint). A second, deeper core was not analyzed. No core was taken in the A Fm.


The top of the T Fm was tested through perforations and produced some wet gas. Eight separate intervals in the A Fm were tested through perforations, indicating wet gas in the lower 50 meters.

No Rw data was provided, so water saturation values from log analysis are somewhat conjectural. No special core capillary pressure data is available to help calibrate water saturation.


Analysis Method
Digital log curves for the well were provided by the client. These were entered into Spectrum 2000 Mindware Ltd's proprietary log analysis program called Meta/Log.

Shale volume was determined from the gamma ray where possible and from the resistivity log where GR was not recorded (250-550 m in A Fm). The SP is quite flat and too smooth to be a useful shale indicator.


Porosity was determined by the sonic log corrected for shale. The density was also tried, but gave misleading results due to poor borehole condition.


Water saturation was derived with the Simandoux equation which corrects for the effects of shale. An Rw equivalent to 85000 ppm NaCl was used to achieve reasonable water saturations in the T Fm. A value approximating 45000 ppm was used in the A Fm. There are no obvious water zones, no RW data from offset wells, and no capillary pressure data to calibrate water saturation results.


A generic permeability curve using the Wyllie equation was generated but not presented on depth plots, as core permeability is much lower than the estimated values from this method.


Reasonable cutoffs were chosen from experience in tight sands and hydrocarbon summaries were printed. The zones that passed all cutoffs are flagged on the depth plots.


Depth plots at 1:1000 scale, brief summary listings, and this report were FAXed to Some One on 24 Month 2012. Hardcopy with plots at 1:500 scale were delivered by courier.


Results are contained in the depth plots and listings supplied. Briefly these show:


Upper T Fm: xxxx - xxxx mKB Phi = 0.093, Sw = 0.43, Net = 6.4 m

This zone was perforated and tested gas.


Middle T Fm: xxxx - xxxx mKB Phi = 0.121, Sw = 0.27, Net = 6.4 m

This zone is not tested.


Lower A Fm: xxx - xxx mKB Phi = 0.113, Sw = 0.51, Net = 50.4 m

Eight zones within this interval were perforated and tested some gas. Additional intervals are untested and are flagged on the depth plots.

Upper A Fm: xxx - xxx mKB Water saturation is speculative so no summations have been run. Numerous resistivity bumps indicate cleaner sands in thin intervals which might be gas bearing or they might contain fresher water, analogous to the Belly River in Alberta.


There are many unknowns and assumptions in this log analysis, more than in a typical project. Lack of RW data and special core data to calibrate water saturation in any zone is a severe handicap. Results are based on personal experience and the production tests.


The lack of adequate density and neutron log data prevents the calculation of porosity corrected for heavy minerals. Since volcanic rock fragments can occur in large quantities in some sands, the porosity shown here could be several porosity units too low. The sonic log was calibrated to the core porosity in T Fm, but this core is in poor quality rock. This does not calibrate the higher porosities. No calibration was possible in A Fm.


Lack of a uranium corrected gamma ray log (CGR) hampers shale calculations. The overall high GR readings indicate either uranium salt precipitation (usually in fractures), feldspathic sands, or other radioactive rock fragments. It is impossible with this data set to separate these events from the shale content. Porosity calculations are suspect because of this.


Log character and borehole condition indicate a highly stressed, probably fractured, reservoir.


Results show many individual sands that probably contain gas. Any one of these could be leaking through poor cement to surface, or leaking and charging lower pressure water zones uphole.

The recommended logging program for future wells is a multi array induction log with SP and GR, a compensated density neutron log with PEF, GR, and caliper, a natural gamma ray spectral log, and an array sonic log with compressional, shear, and Stoneley curves, with GR and caliper. This suite provides sufficient redundancy to compensate for bad hole conditions, mineral variations, fractures, and radioactive salts.


A study should be undertaken to map water resistivity versus depth in the region, since no RW data was provided for this project.


In future wells, conventional and special core analysis to obtain capillary pressure and electrical properties should be contracted to help calibrate water saturation.


If possible, available core should be re-analyzed, described, and special core analysis properties obtained as soon as possible to allow recalibration of this log analysis.

Respectfully Submitted

E. R. (Ross) Crain, P.Eng.
Consulting Petrophysicist

Petrophysical Analysis Report - Unconventional Reservoir

24 Month 2014

We were requested by A. Person, P.Geol. of PQR Resources Inc. to analyze the log and core data over the B Formation in 3 wells in the subject area.


Final results of the petrophysical analysis will be used to assist in assessment of reservoir quality and to assist in stimulation design.

A comprehensive multi-mineral petrophysical analysis was computed and delivered as electronic images along with this report. Net pay summaries are included in the body of this report. Rock mechanical properties were calculated based on reconstructed logs derived from the petrophysical analysis, for use in stimulation design programs. The reconstructed logs eliminate gas effect and low quality data caused by rough borehole.



The log suite consisted of density, neutron, PE, sonic, GR, and resistivity logs. Two wells had crossed-dipole shear sonic logs and one had a nuclear magnetic resonance log.


No conventional, side-wall, or shale rock core analysis data were provided. Capillary pressure data was provided for three samples. Total organic carbon analysis and X-Ray diffraction mineralogy data was provided for one well.




Digital log data was provided by the client. These data were analyzed with a complex lithology petrophysical model, which accounts for the effects of heavy minerals and gas, using our proprietary META/LOG analysis script, running in the PowerLog software package.


TOC and XRD mass fraction lab measurements were converted to volume fractions based on the component densities. These were used to calibrate the kerogen correction to crossplot porosity and to calibrate clay and mineral volumes in the b-040       -I/094-O-05 well. The parameters and scale factors derived here were used in the other two wells.


Shale volume was calculated from the total gamma ray curve using a Clavier correction. Individual clean and shale lines were chosen for each zone in each well. Because of the effect of uranium on the total gamma ray curve, clean and shale lines were adjusted by comparison with the shale volume calculated from the density-neutron separation method. The final shale volume was calculated from the average of the two methods. Results match the clay volume fraction available from XRD data in well XXX.


Total organic carbon (TOC) was calculated using the Issler method with resistivity and density data, and calibrated to the lab data with scale and offset factors based on the available lab data in well XXX. The log derived TOC mass fraction matches the available lab data extremely well. The mass fraction curve was then converted to volume fraction for use in the porosity calculation.


Porosity was calculated from the shale corrected complex lithology density neutron crossplot model. The results from this model are relatively independent of mineralogy and compensated for gas effects. However, the effect of kerogen volume is included in this initial result, so the kerogen volume is subtracted to obtain the final effective porosity value.


There is no core porosity data to help calibrate this result. However, there is a nuclear magnetic log with effective porosity in d-34-K/094-O-05. This curve matches the calculated effective porosity curve in that well quite closely. The NMR effective porosity is unaffected by kerogen and is the best available check on the final effective porosity in this project.


The PE curve in XXX well was affected by barite weighted mud. It was reconstructed from multiple regression based on data in the other two wells.


The dominant lithology is described as quartz (with clay), some calcite (increasing somewhat with depth), and minor pyrite. This would need a three mineral log analysis model since the effect of pyrite on the lithology calculation can be quite significant. Because of gas effect, lithology models that use the density or neutron log data cannot be used, leaving only a two-mineral model based on PE available.


To account for pyrite, pyrite volume was derived from a multiple regression using all available lithology indicating logs, calibrated to the XRD pyrite volume. This curve was then used to remove the effect of pyrite from the PE curve, allowing it to be used in a 2-mineral model.


Lithology was then calculated with a 2-mineral model using the pyrite corrected PE data, with a mineral mixture chosen as quartz and calcite. The final result is a three mineral model with quartz, calcite, and pyrite (and clay) that matches the XRD data quite well. All TOC and XRD data points are plotted on the log analysis depth plots for comparison.


The Simandoux equation was used for water saturation calculations. This model reverts to the Archie equation in the clean zones.


Water resistivity was set at 0.060 ohm-m at 25C for all zones. Electrical properties were set at A = 1.00, M = N = 1.65. Formation temperature gradient was set at 3.13C / 100 m with a surface temperature of 10C. This gives a formation temperature of 86C at 2430 meters.


No lab measured electrical properties were available; those used are based on prior experience in tight sands.


A permeability index was generated from a standard relationship; the equation is Perm = 10^(20.0 * PHIe – 2.0). There is no core data for calibrating this value so it should be treated as a qualitative guide. The permeability derived from the Coates equation was provided for the NMR log in d-34-K. It has been plotted on the depth plot for comparison to our calculated results. These permeabilities do not include that from natural fractures or stimulation.


We were requested to calculate the acoustic anisotropic coefficient of the interval, based on differences between the X and Y axis crossed-dipole sonic log data. Even on an expanded scale log, there was no significant difference between the two log curves. We conclude that the acoustic anisotropic coefficient (Kani) is zero.


Using the complete petrophysical analysis results described above, reconstructed log curves were generated. This step removes bad hole and gas effects from the logs so that accurate water-filled rock mechanical properties can be calculated. This process is also used to create missing log curves where needed.


Calculated mechanical properties include Biot’s constant, bulk, shear, and Young’s moduli, and Poisson’s Ratio. A brittleness coefficient (Lame’s constant, Lambda) was also calculated. These results are displayed, along with the lithology track, on a separate depth plot.


These results are not calibrated as there is no lab data available. However, all results are within normal limits for water-filled rocks of this type and are suitable for use in stimulation design programs.


Use of the raw log curves instead of the reconstructed logs should be strongly discouraged because the gas effects are quite large and will lead to calculation of erroneous stimulation parameters.



Two sets of net pay flags were generated; one set used a porosity cutoff of 3% and a saturation cutoff of 50%. The second used a more lenient set of values, with porosity cutoff of 2.5% and a saturation cutoff of 65%.. A shale volume cutoff of 45% was used throughout. Both net pay flags are shown on the depth plots of results. Tables of these results are shown on the next page.





All data in the above tables are based on measured log depths.


Free gas in place can be calculated from these data using appropriate gas volume factor, temperature, pressure, and area.


The Trican report provided by the client indicated that adsorbed gas volume would be small. In any case, adsorbed gas volume cannot be calculated from the log analysis as there is no gas content (Gc) versus total organic carbon (TOC) relationship available in the data set provided.


Results of the log analysis of the wells are contained in the depth plots, LAS files, and net pay spreadsheet delivered with this report. All depth plots are measured depth displays.



Petrophysical analysis using the shale and kerogen corrected complex lithology model is believed to be reliable for porosity and saturation, and can be used to determine original free gas in place. There is insufficient data to calculate adsorbed gas in place from this petrophysical analysis.


The permeability index provided in our work should only be used qualitatively.


Mechanical rock properties calculated from these results are believed to be reliable and can be used as input to stimulation design software.


Results match available TOC and XRD data. However, there is no useable porosity or permeability control data from conventional or sidewall cores. Confidence in this analysis could be markedly improved if a cored well was added to the well complement.


Formation tops, formation names, and perforation intervals were provided by the client, and were used on our answer and raw data plots for zone identification purposes only. We express no opinion on the correctness of the name designations or associated depths.


This is not a reserves or resource appraisal report.


Respectfully submitted


E. R. (Ross) Crain, P.Eng.
Principal Consultant
Spectrum 2000 Mindware




All interpretations expressed in this report, and contained in any attachments thereto, are opinions based on inferences from geophysical well logs and/or laboratory measurements provided by the client.

No economic decisions should be made by anyone based solely on the results or opinions expressed in this report or its attachments. The reader should exercise prudent business practices along with sound geological and engineering judgment before any further actions are undertaken.

Spectrum 2000 Mindware Ltd cannot and does not guarantee the accuracy or correctness of any interpretations, and we shall not be liable or responsible for any loss, costs, damages, or expenses incurred or sustained by anyone resulting from any interpretation made by our officers, agents, or employees.

We do not represent that this communication, including any files attached, is free from computer viruses or other faults or defects. We will not be liable to any person for any loss or damage, including direct, consequential, or economic loss or damage however caused, and whether by negligence or otherwise, that may result directly or indirectly from the receipt or use of this communication or any files attached to this communication.


Forensic Petrophysical Report

24 Month 2012


We were requested to review the log, core, and production test information provided by Company B on seven wells in the Dark River area of Country C. The work was performed for Another One of Noisy Petroleum Consultants Ltd, team leader of an integrated study to assess development potential of a deep, tight gas reservoir. Six of the wells penetrated the gas reservoirs to varying depths and one was an off structure exploration well (C-1). The six field wells were N-1, 2, 3, 4, 5, and 6. The zone of interest is the P Formation of middle Jurassic age, between approximately xxxx and xxxx meters below KB.

The P Fm is a thick sand-shale sequence with fluvial braided stream sands in the upper layers, fluvial channel to terrestrial deposits in the middle layers, and marine sands in the basal layers. Considerable volcanic and metamorphic minerals occur in the upper and middle P Fm. The middle sands are moderately over-pressured and the basal sands even more so. Basal sands appear to be more continuous than the middle sands. Upper sands are probably more isolated due to the braided stream environment.

Porosity is typically in the range of 5 to 11 % but permeability seldom exceeds 0.10 md even in the best sands.


Available Data

Raw data depth plots of the well logs for the seven wells were provided. These were re-plots from a log analysis software package and not the original logs. Typical log suite included gamma ray, SP, caliper, deep and shallow resistivity, density, neutron, sonic, and PEF (in newer wells). No spectral gamma ray data was recorded. This would have been very useful in accounting for the feldspar and other possibly radioactive rock fragments in the sands.

Log data quality is reasonably good, with more problems from rough hole conditions in the three older wells (N-6, 2, and C-1). Production test information was posted on these logs, but the information is incomplete. It is not always clear which test results belong to which zone as no depths are recorded here. Perforation depths are contained in other documents but there was no time available during this phase to assemble this information for use in reviewing the logs.

Some flow rates or the fact that there may have been no flow is not consistently noted. Crossflow between zones is evident as some zones produce more when isolated than when co-mingled with other zones.

A composite log with the same raw data plus petrophysical computed results, as well as core porosity and permeability, gas mud log curves, and pressures and permeability from test results were provided. Some of the core data appears to be from sidewall cores. Core data for N-2 was analyzed at surface and at overburden conditions and a listing of this data was provided. No listings for core data in other wells was found but values are plotted on the composite logs.

Data from tests is mostly after fracturing or acidizing. Test results were handwritten on these logs and mimic the information posted on the raw data plots. A graphical presentation of the sample descriptions is included on this depth plot. In the four newer wells, this is an excellent data set and correlates well to the log curves. On the three older wells, the match varies with borehole condition.

A structure map and cross section with the six field wells was provided. A crossplot of core porosity vs core permeability was provided. Data was coded by sand quality but the wells or zones included are not listed. It is not stated whether the data is from whole core, plug, or sidewall samples. It is probably from N-2.

Thin section petrographic analysis data for N-3, 4, and 5 describe the mineral composition and visual porosity for a number of samples. In upper and middle sands, the volcanic rock fragments compose 30 to 60% of the clastic material. These are termed heavy minerals in log analysis and must be accounted for in the log analysis model. The exact definition of which volcanic minerals are present is not given.

No special core electrical properties or capillary pressure data was provided. No water resistivity or water chemistry for the area was provided.


Discussion of Petrophysical Computations

The petrophysical computation and display of results for five of the seven wells (N-3, 6, 7, 5, and 4) is excellent, with one major problem, discussed below.

The model appears to use gamma ray and density neutron separation as shale indicators with the minimum of these two methods being used as the final shale volume.

Porosity is from a shaly sand crossplot of density and neutron data. This model does not account for heavy minerals, such as volcanic rock fragments. Since the PEF curve is available on newer wells, it could be used to generate a heavy mineral correction. Normally, the same result can be obtained from the density neutron crossplot in a complex lithology model, but this is not possible (automatically) in a gas zone due to gas effect masking the heavy mineral effect.

The heavy mineral correction will raise computed porosity compared to the present values. The correction could add 1 to 4 porosity units depending on the existing values of density, neutron, heavy mineral content, and shale volume. Where porosity is low, this is a significant increase in reservoir volume. Where PEF is not available, a zoned approach using a density neutron complex lithology model with a forced matrix density greater than 2.65 gm/cc will achieve similar results.

Since log analysis porosity is significantly less than core porosity in almost every cored well, this correction should be attempted. As noted earlier, some of the core data is from sidewall cores, so core porosity may be a little too high in these cases. The source of the core data should be ascertained before a final calibration to core is attempted.

Data from the thin section analysis shows some limonite, an iron rich mineral. This may affect stimulation success and formation damage while drilling.

Constraints for rough hole effect on the density neutron calculation were very well done. There are very few spikes or anomalously high porosity events on these five wells.

In N-7, the sonic log corrected for shale was used for porosity as the other curves were missing. Results compare favourably to the other four wells in this group.

Water saturation was computed from a shale corrected model, but there is no indication of which model or what RW, temperature, or shale properties were used. The results are reasonable compared to the porosity of these sands but are quite low when compared to the permeability. This may be due to highly deformed pores caused by ductile minerals or infilling with diagenetic minerals. Saturation values will change only slightly if porosity is increased with the heavy mineral correction.

Existing thin section results would have to be studied further to gain a better understanding of the porosity-permeability-saturation relationship. There is insufficient time allocated in this phase for a thorough review of the thin section data. Further special core studies are also needed.

Permeability was calculated from a model that varies with the sample description. It has been calibrated to the core and the plotted log curve matches the core very precisely. If log analysis porosity is raised with the heavy mineral correction, this algorithm will have to be adjusted slightly to retain the excellent fit to the core shown on these wells. The exact nature of the permeability transform is not mentioned.

A water saturation cutoff was used on these wells to mark pay zones. The saturation cutoff varies with the sample descriptions in the range 60 to 80%. There is no evidence that a porosity cutoff was used, but it may have been, as a 5% cutoff was used in N-4. Choosing a net pay cutoff in tight, deep gas sands is very difficult and may be impossible. The cutoffs on these plots are satisfactory for identifying zones of interest, but there is no way to tell at the moment whether they over or under estimate gas in place.

The log analysis in N-4 could be improved. There is no water saturation or permeability curve on the plot. The scale of the BVW curve differs from the PHIe curve, so the visual interpretation of Sw from these curves is misleading. A 5% porosity cutoff was used to identify interesting intervals. This is different than the wells described above. This well should be recomputed with the same model as the previous five. No flows are reported on the log plots, so this may be a very poor well, but for gas in place calculations, it needs to be upgraded.

Well C-1 is off structure and has been computed with somewhat different model and parameters. The shale beds are not shaly enough, so too much porosity shows in the shaly sands. Too much porosity shows in cleaner sands where rough hole conditions affect the results. Permeability is from a different model than other wells and is based on faulty porosity data. It cannot be used in its present form. Sample descriptions are poor due to cavings and there is no core data. These problems make it very difficult to repair this log analysis, but the attempt should be made if the well is needed for aquifer assessment.



1. Assemble all core data, classify as to source (sidewall, whole core, plugs), and review for consistency and usefulness. Re-plot core porosity vs core permeability. List and compare thin section visual porosity to core porosity.

2. Summarize thin section lithology breakdown vs depth to determine the quantity of heavy minerals and feldspar present.

3. Identify which heavy minerals are present and determine their grain density and PEF values. Generate the properties of a generic heavy mineral that is the average of the minerals identified.

4. Re-compute log analysis with a complex lithology model using the PEF curve or a zoned RHOMA value to correct porosity for heavy minerals. Re-compute N-4 and C-1 with the same attention to rough hole as the other wells.

5. Adjust permeability transform to compensate for this change in the porosity model.

6. When better electrical properties or cap pressure data becomes available, recalibrate water saturation model.

7. Run net pay, hydrocarbon pore volume, and flow capacity summations for each individual sand body (do not co-mingle zones) using no cutoffs except shale volume < 50%.

8. Plot these sums vs test results (flow rate) on a crossplot to see if any trend exists. If there is a trend, it will assist in choosing cutoffs for net pay. Since the permeability transform appears to match core very well, the final cutoff may be permeability.

9. In new wells, add the gamma ray spectral log to the logging suite. This will allow a better shale volume calculation and help distinguish feldspathic sands from shaly sands. It will also eliminate the false indication of shale caused by uranium salts in the sands.

10. Additional core should be taken in new wells to cover representative sand bodies from all environments, particularly those with volcanic rock fragments as a major component.

11. Existing core and chip samples should be re-described, and new core and chip samples should be adequately described, to determine which volcanic minerals are present and in what quantities.

12. Special core analysis to determine electrical properties, capillary pressure, and relative permeability should be performed on existing and new core in cores from each depositional environment. This is needed to calibrate initial water saturation and residual gas saturation.

13. New cores should be viewed with SEM and thin section petrography to determine the pore geometry that leads to such low permeability and low water saturation in moderate porosity.

Respectfully Submitted

E. R. (Ross) Crain, P.Eng.
Consulting Petrophysicist

Research Petrophysics Report

24 Month 2012


We were requested to review the log and pressure test data on eight wells and to perform an independent petrophysical and overpressure analysis.

The interval of interest is from sea floor to the top of Chalk or top of Zechstein evaporites if Chalk is not present. The main pay zones are the Montrose sands lying above the Chalk.

The objective of this project is to evaluate the efficacy of the standard overpressure indicator method based on sonic log trend line analysis. The approach is commonly known as the Eaton method, but similar discussions have been published many years earlier.

Available Data

Log and pressure data for this project was provided in digital form. Logs consisted of resistivity, sonic, gamma ray, and caliper over most of the interval, and density neutron over lower portions of some wells. Sonic data was missing in one well and had a large gap in another.

Formation pressure data for the Montrose were provided for six wells.

A report from the client was provided, which contained discussion and results of their analysis using the Eaton method on a number of wells.


Digital log curves, pressure data, and formation tops for the wells were provided by the client. These were entered into Spectrum 2000 Mindware Ltd's proprietary log analysis program called Meta/Log. All log and pressure data were converted to metric units. Data recorded inside casing was eliminated and some editing was done to remove spikes.

Shale volume was determined from the gamma ray log. Porosity was determined by the sonic log corrected for shale. The density neutron crossplot porosity was also calculated where possible. No water saturation calculation was made. The equations used were:

Neutron porosity
PHIN = NPHI : fraction

Density Porosity
PHID = (RHOB-2.65)/(2.65-1.00) : fraction

Sonic Porosity
PHIS = (DELT-182)/(656-182) : fraction

Shale Volume
Vsh = MIN(1,MAX(0,((GR-GRcl)/(GRsh-GRcl)))) : fraction

Effective Porosity
PHIe = MIN(0.3*(1-VSH),MAX(0,0.5*(PHIN-VSH*0.28+PHID-VSH*0.05))) :fraction

GRcl and GRsh were chosen uniquely for each well.

These results were used to determine shale beds suitable for analysis of overpressure by the Eaton method. Data below the zone of interest (Montrose) was deleted from the working files after this analysis step.

The calculation steps for the Eaton method are listed below:

Actual shale travel time
DELTsh = IF(VSH>0.5,DELT,100) : us/m

Normal shale travel time compaction trend line
DTnorm = 10^(Log(3.281*175)-((DEPTH/3000)*(Log(175*3.28)-Log(100*3.28)))) :us/m

Difference between actual and normal sonic values
DTdiff = MAX(0,+DELTSH-DTNORM) : us/m

Overburden pressure
SOV = (Ln(DEPTH-EKB)-0.5185)/3.47 : gm/cc

Shale Pore Pressure as a gradient
SPP = SOV-(SOV-1)*(MIN(1,DTNORM/DELT))^3 : gm/cc

Shale pore pressure as head of water
SPP-M = (SPP-1)*(DEPTH-EKB) : head in meters

Shale pore pressure as a pressure
PRESsh = 9.81*(SPP-M+DEPTH-EKB) : KPa

RFT pressure from lookup table

RFT pressure as a head of water
RFTHEAD = MAX(0,-DEPTH+EKB+RFTPRES/9.81) : head in meters

DTnorm is the sonic trend line chosen in a shallow shale zone to represent the normal compaction trend. The position and slope of this line is very subjective. The line finally chosen is very similar to the line used by the client. My first pick fits the sonic log better but gave less overpressure than my final pick. There is, in fact, very little valid sonic data in the shallow sequence to which a line can be fitted. Depth plots of both my initial and final lines, along with the sonic log curves for 7 wells, are provided under separate cover. The final line was picked to account for actual mud weights used to maintain the holes and to approximate actual Montrose reservoir pressures at the top of the gas/oil column.

SOV is the overburden stress. This equation varies from place to place. It was supplied by the client and is assumed to be suitable for this region of the North Sea. SPP is the shale pore pressure from the Eaton equation. It is converted to meters of head of water (SPP-M) and to pressure in KPa (PRESsh). For comparison, the RFT pressures for any depth were found in a lookup table (psi) and converted to head in meters and pressure in KPa.

Depth plots at 1:10,000 scale were made of all these results plus the raw log data. A lithology track was created from the Vsh curve and a depth function related to the formation name. Thus sandstone, limestone (chalk), anhydrite, and salt were shown where appropriate.


Results are contained in the depth plots supplied under separate cover. There is little difference between this work and the client's work. We have added pressure vs depth curves to the plots as these are sometimes easier to visualize than head of water curves.

The final compaction trend line was chosen as a compromise. The initial choice generated very little overpressure, yet mud weight data supplied by the client suggested higher pressure results were needed to account for the mud weights actually used. The final choice was arrived at after several iterations. The final trend gives shale overpressure values close to actual mud weight gradients and close to actual formation pressures at the top of the Montrose structure.

Matching the actual Montrose pressure is not a requirement of the method. A normally pressured shale is sufficient to act as a seal, even for the relatively high buoyancy caused by the large oil and gas column. It should be noted that none of the Montrose data shows significant overpressure in the reservoir. The pressures are close to those expected for the hydrocarbon buoyancy.


There are many unknowns and assumptions in log analysis for overpressure. These include the subjective nature of the normal compaction trend line, the lack of control on parameters in the SOV and SPP equations, and the variable silt content within the shale itself.

The effect of a gas phase in porosity within the silt component of the shale cannot be accounted for, even if it were known to be present. Invasion by drilling fluid removes most of the gas from the region seen by the sonic log, so the effect should be very small. A well log model study could be undertaken to assess the magnitude of gas effect. Gas leaking through fractures would probably not influence this method. If the other unknowns described in the previous paragraph could be calibrated, it is unlikely that gas in the silt would pose additional problems, but the model study suggested above would quantify this.

It should be noted that the seismic signal may be influenced by gas in porosity in the silty shales or in fractures. Seismic studies for detection of overpressure may be compromised by this effect, while the sonic log is not.

The validity of the Eaton method for calculation of shale pore pressure has not been proven, since there are no actual pressure data points within the shale interval that can be used for calibration.


Results from the Eaton method should be used only as an indicator of possible overpressured shales.

Results should not be used as a quantitative measure of the amount of overpressure.

Further work is required from this specific area to validate the overburden stress (SOV) formula, on which the Eaton method depends.

Pressures must be acquired from stray sands within the overpressured shales to calibrate the terms in the Eaton equation for SPP and to validate the normal compaction curve (DTnorm) for use in this specific area..

There is no reason to believe that the parameters in these equations are universal constants and they need confirmation from this area to be used reliably in this area.

Respectfully Submitted

E. R. (Ross) Crain, P.Eng.
Consulting Petrophysicist

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