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THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
The complete manual is 193 pages, available at
www.spec2000.net/00-orders.htm
By E. R. (Ross) Crain, P.Eng.
www.spec2000.net Phone: 1-403-845-2527 ross @ spec2000.net Copyright: E. R. Crain, P.Eng. All Rights Reserved Updated Nov 2011
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This document is intended as a sample of the presentation quality and technical content of the Petrophysical Referemce Manuals offered in “Crain’s Petrophysical Series”. The full version of this Manual is more than 190 pages and a few selected pages are shown here to illustrate the style of writing and the quality of the
illustrations. There are 9 other manuals in the Series. Orders can be placed at www.spec2000.net/00-orders.htm .
Compare this sample to course handouts provided elsewhere and decide for yourself which is easier to read and refer to in the future.
We offer practical, no-nonsense courseson a variety of petrophysical topics. Each seminar is supported by a full colour Reference Manual and visual presentation with practical exercises. We sell solutions, not logging tools.
As a low cost alternative to In-House courses, “Crain's Integrated Petrophysics AV Courses” include narrated PowerPoint slides, exercises, and full colour PDF Reference Manuals, and Excel Spreadsheets. Narration simulates a live, in-house course presentation. A Certificate of Proficiency is awarded upon completion of assignments.
These lectures and reference manuals are time-tested in major and independent oil companies, service companies, and government agencies around the world, and are backed by 50 years of worldwide experience. These practical, no-nonsense, courses are intended for personal study at work or at home. Workload is at 3rd or 4th year University level. No
prior knowledge of logs is required, but some facility with basic math is an asset.
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TABLE OF CONTENTS
Restrictions on reproduction 2
Special Copyright Notice 2
Trademarks 2
Warranty 2
About the Author 4
1.00 Introduction Quantitative Log Analysis 5
1.01 What Is Well Logging? 6
1.02 Organizing Your Work 15
1.03 Calculators and the Math Hierarchy 17
2.00 The Step by Step Procedure 18
2.01 The Analysis Model 19
2.02 The Formation Rock Model with Definitions 20
2.03 The Log Response Equation 24
2.04 Using The Log Response Equation – Seismic Modeling 25
2.05 Integration – Calibrating to Ground Truth 27
3.00 Eyeball Analysis Of Logs - Crain’s Rules 29
3.01 General Rules For Picking Log Data 38
3.02 Selection of Log Interpretation Parameters 38
4.00 Shale Volume 40
5.00 Pore Volume 42
5.01 Porosity From The Sonic Log 43
5.02 Porosity From The Density Log 45
5.03 Porosity From The Neutron Log 47
5.04 Porosity From The Complex Lithology Density Neutron Crossplot 49
5.05 Porosity From The Dual Water Density Neutron Crossplot 54
5.06 Porosity From The Photoelectric Density Neutron Crossplot 55
5.07 Material Balance for Porosity (Maximum Porosity) 56
5.08 Useful Porosity 57
5.09 Porosity From The Nuclear Magnetic Resonance Log 58
5.10 Fracture Porosity 59
5.11 Porosity from Old ES Logs 60
6.00 Lithologic Analysis of Matrix Rock Volume 61
6.01 Two Mineral Lithology From Matrix Density 62
6.02 Lithology From Sonic Density Neutron Data 63
6.03 Lithology From PE Density Neutron Log 64
6.04 Lithology From Spectral Gamma Ray Log 66
6.05 Lithology From Vp/Vs Velocity Ratio 68
6.06 Elastic Constants / Mechanical Properties From Logs 69
7.00 Formation Water Resistivity 71
7.01 Water Resistivity From Catalog or DST 72
7.02 Water Resistivity From Water Zone (Rwa) 74
TABLE OF CONTENTS - Continued
8.00 Water and Hydrocarbon Saturation 76
8.01 Determination of Saturation Parameters A, M, N 77
8.02 Water Saturation from Archie Method 81
8.03 Water Saturation from Simandoux Method 82
8.04 Water Saturation from Dual Water Method 82
8.05 Water Saturation from Buckles Number 83
8.06 Irreducible Water Saturation 85
8.07 Moveable Oil Saturation 86
9.00 Permeability and Productivity 87
9.01 Permeability from the Wyllie-Rose Method 87
9.02 Permeability from Porosity 88
9.03 Permeability from the Coates Method 89
9.04 Fracture Permeability 89
10.00 Summarizing Results 90
10.01 Cumulative and Average Reservoir Properties 91
10.02 Fluid Properties and Reserves 91
10.03 Productivity Index and Water Cut 93
11.00 Beyond Log Analysis 95
11.01 Productivity From Drill Stem Tests 95
11.02 Production Projection and Cash Flow 98
12.00 Case Histories 101
12.01 Cretaceous Glauconitic Sand 101
12.02 Triassic Dolomitic Sand 111
12.03 Devonian Carbonate Reef 118
12.04 Tar Sands 124
13.01 List of Abbreviations 126
Appendix: Fractured Reservoirs 130
Exercjses 145
ABOUT THE AUTHOR:
E. R. (Ross) Crain, P.Eng. is a ConsultingPetrophysicist and a Professional Engineer with 50 years of experience in reservoir description, petrophysical analysis, and management. He has been a specialist in the integration of well log analysis and petrophysics with
geophysical, geological, engineering, and simulation phases of oil and gas exploration and exploitation, with worldwide experience. His textbook, "Crain's Petrophysical Handbook on CD-ROM" is widely used as a reference to practical log analysis. Mr. Crain is an Honourary Member and Past President of the Canadian Well Logging Society (CWLS), a Member of Society of Petrophysicists and Well Log Analysts (SPWLA), and a Registered Professional Engineer with Alberta Professional Engineers, Geologists and Geophysicists (APEGGA).
THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
The complete manual is 193 pages, available at
www.spec2000.net/00-orders.htm
CONVERSION FACTORSFeet = Meters * 3.281 Meters = Feet = 0.3048 Inches = Millimeters / 25.4 Millimeters = Inches * 25.4 Barrels = Cubic meters / 0.159 Cubic meters = Barrels * 0.159 (100 bbl/d = 15.9 m3/d) (100 m3/d = 629 bbl/d) PSI = KPa / 6.894 KPa = PSI * 6.894 Mcf = Cubic meters * 35.3 Cubic meters = Mcf / 35.3 (1 mmcf/d = 28 262 m3/d)
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1.00 Introduction To Quantitative Log Analysis
This Handbook is designed to give you a starting point for learning quantitative log analysis methods. It is a condensed version of Chapters 4 through 11 of Crain’s Petrophysical Handbook on CD-ROM, avail able at
www.spec2000.net. When log analysis is combined with sample, core, test and production data, it is called Integrated Petrophysics or just plain “petrophysics”.
You can use this book as a quick reference to quantitative petrophysical analysis or as a self-directed study guide. If you wish to take the exam at the end of this book to earn a certificate of proficiency, please go to my website at www.spec2000.net. To get maximum benefit from available well data, you must integrate logs, cores, samples, tests, seismic, geological, and engineering concepts into a coherent picture. Log analysis performed in isolation is pointless and can be a career-buster. However, learning log analysis methods can be done in relative isolation, as long as we appreciate the contributions available from other disciplines. It is really important to temper, and sometimes completely revise, the results of your log analysis by comparison to other sources of “ground truth”.
Using productivity analysis based on accurate shale, porosity, lithology, saturation, and permeability calculations from log data, you can compare the quality of a zone with known production in your area. From this, you can decide if the well is worth completing or whether to drill more similar wells. You can also high-grade your drilling or completion prospects based on estimated flow capacity as well as the more usual net pay figures. This handbook provides the methods to extend conventional well log analysis to cover
productivity and cash flow analysis.
The real question you must answer is not "What is the porosity and water saturation?" but "Will the zone produce economically and at what rate?" This goes considerably beyond conventional log analysis. That’s why my petrophysical software is called Meta/Log (Meta = Beyond). There are cases where you cannot get this far, either for lack of corroborative data or narrow-minded job
descriptions, but it never hurts to try. The full spectrum techniques described here will help you find oil and gas more effectively from logs, complete discoveries more economically, and work-over wells with more confidence.
Crain’s Petrophysical Pocket Pal provides quantitative log analysis methods suitable for use by most geologists, engineers, and geophysicists who need to perform quick, complete, and accurate calculations of reservoir properties. The formulas presented are simple but adequate for all but the most detailed work. Usage rules for each method are described, based on the log suite available
and the rock/fluid mixture expected. More complex methods are contained in Crain’s Petrophysical Handbook, the “big brother” to the Pocket Pal.
Although visual analysis, crossplots, and log overlay techniques have been widely used, this handbook provides a step by step numerical method which has worked reliably in most formations in many parts of the world. This computational approach minimizes the risk of bypassing lower quality zones, and improves your ability to estimate the quality of a zone. Finding zones of interest on a long log does require some form of visual scanning. This topic is covered in Section 3.00, after we review the details of our log analysis model.
1.01 What Is Well Logging?
A log is a record of measurements or events recorded versus time or distance, such as a ship’s log ot travelog. Truckers, pilots, doctor, and lawyers keep logs of their activities. In the case of well logging, the ship is a measuring instrument of some kind, and the trip is taken into and out of a wellbore.
Well logging is the process of recording various physical,
chemical, electrical, or other properties of the rock/fluid mixtures penetrated by drilling a well into the earth's mantle.
In its most usual form, an oil well log is a record displayed on a graph with the measured physical property of the rock on one axis and depth (distance from the surface) on the other axis. More than one property may be displayed on the same graph.
None of the logs actually measure the physical properties that are of most interest to us, such as how much oil or gas is in the ground, or how much is being produced. Such
important knowledge can only be derived, from the measured properties listed above (and others), using a number of assumptions which, if true, will give reasonable estimates of hydrocarbon reserves.
Thus, analysis of log data is required. The art and science of log analysis is mainly directed at reducing a large volume of data to more manageable results, and reducing the possible error in the assumptions and in the results based on them. When log analysis is combined with other physical
measurements on the rocks, such as core analysis or petrographic data, the work is called petrophysics or
petrophysical analysis. The results of the analysis are called petrophysical properties or mappable reservoir properties. The petrophysical analysis is said to be “calibrated” when the porosity, fluid saturation, and permeability results compare favourably with core analysis data. Further confirmation of petrophysical properties is obtained by production tests of the reservoir intervals.
The use of well logs for evaluating mineral deposits other than oil and gas, such as coal, potash, uranium, and hard rock sequences has been practiced since the early 1930’s and is widespread today. Although the vast majority of logs are run to evaluate oil and gas wells, an increased number are being run yearly for other purposes, including evaluation of geothermal energy and ground water. A large portion of this handbook is aimed at oil and gas, but the other topics are not ignored. Most Chapters apply to both hydrocarbon and mineral exploration.
When logs are used for purposes other than evaluation of oil and gas, they are often called geophysical logs instead of well logs. The science is called borehole geophysics instead of petrophysics. This difference is merely a matter of semantics and training. The theory doesn't change - just the nomenclature, and sometimes the emphasis.
To perform a logging operation, the measuring instrument, often called a probe or sonde, is lowered into the borehole on the end of an
insulated electrical cable. The cable provides power to the downhole equipment. Additional wires in the cable carry the recorded
measurement back to the surface. The cable itself is used as the depth measuring device, so that properties measured by the tools can be related to particular depths in the borehole.
The Well Logging Operation =
A logging tool is made up of a sonde and a cartridge. The sonde is the portion of the tool which gives off energy, receives energy, or both. The cartridge contains the electrical circuitry or computer components needed to control the downhole equipment, and to transmit data to and from the surface.
Combination logging tools consist of more than one sonde and cartridge, so that more than one log can be recorded on a single trip into the wellbore.
Surface equipment is mounted in a logging truck, van, or skid unit from which all logging operations are controlled. The logging unit contains hoisting equipment for lowering and raising the tools in the hole, and electronic or computer equipment for controlling and recording the downhole measurements.
Recording the Well Log
Measurements are recorded in two forms, analog and digital. The analog data may be recorded on photographic film, electronic plotter, or chart recorder. The same data are captured in digital form on magnetic tape or disc for later use in computer aided analysis. Many instrument control and calibration functions are now handled by the same computer used to record the digital data, with some human control. The result is a log, as seen below.
THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
Example of a Well Log, with a standard 3-track presentation on the left and an image log on the right. Curve names and scales in the scale heading help identify which curve is which.
Logs can be run on a number of vertical (depth) scales and quite a variety of horizontal (curve value) scales.
Common Logging Scales
English Metric Often Called Terminology Terminology Detail scale or
large scale 5" = 100 ft 1:240 1:200 is also very common Correlation scale or 2" = 100 ft 1:600 1:500 is also very common small scale 1" = 100 ft 1:1200 1:1000 is also very common Super detail scale 10" = 100 ft 1:120 1:100 is also very common * 25" = 100 ft 1:48 1:50 is also very common Dipmeter scale 60" = 100 ft 1:20
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2.00 The Step By Step Procedure
Log analysis involves a series of logical steps, each necessary to proceed to the next step. Like an athlete running to win the 100 meter sprint, log analysis requires training, planning, focus, and concentration before the race starts. At race time, we proceed to the starting line, get Ready, Set, Go, and Finish. Then we critique the results – did we win or finish last?
CRAIN’S STEP LADDER TO SUCCESS
A. Prepare For The Race:
1. Learn and understand the methods and their limitations 2. Plan your approach to this project
3. Focus on the results required
4. Concentrate on the important issues, reduce the noise B. Get Ready:
1. Review local well histories and regional geologic information 2. Correlate offset logs and pick formation tops
3. Mark all known data on logs or data sheet 4. Edit the logs
C. Get Set:
1. Find clean zones and shale zones 2. Pick shale base lines on all logs 3. Find porous zones that are fairly clean 4. Find obvious water zones, if any 5. Look for hydrocarbon indications 6. Identify coal or salt beds
7. Identify the matrix rock from the log response 8. Look for signs of permeability
9. Estimate depositional environment 10. Check for indications of fractures D. Go:
1. Subdivide cleaner zones into horizontal layers 2. Pick log values in each layer
3. Choose computation method 4. Calculate results
E. Finish:
1. Check results against samples, cores, and tests 2. Rework problem areas
3. Think to a conclusion - IS THE ZONE ANY GOOD? 4. Write a report, present results and conclusions F. Critique Your Work:
1. Could the job be better organized or simplified? 2. Did the results satisfy the end-user?
3. What else is needed (data, tools, time) to do a better job?
Log analysis also may be circular, or at least iterative, since the results from each step can often be compared to other sources of data and corrected if differences are found.
This list looks pretty imposing, and a few steps might be skipped from time to time, but a consistent, step by step procedure will produce more reliable results. It tends to remove some of the mystery involved in log
analysis, and reduces effort in the long run. You might consider the procedure to be a "Step Ladder to Success". Unfortunately, you may have to climb the ladder more than once if log analysis results do not compare to ground truth, such as core analysis, sample descriptions, or test results.
Review the available data before embarking on detailed analysis. Locate the well history files or well history cards, look at offset logs, review sample descriptions, formation tops, tests, cores, and production histories, and possibly structural or isopach maps of the target formations. Known gas-oil and oil-water contacts must be noted. If seismic maps or cross sections are available, review these as well.
On deep, remote, or offshore wells, a number of logs may be recorded while drilling, such as mud and hydrocarbon logs, or even gamma ray, resistivity, or other quantitative log curves. These should be added to the "Hopper of Knowledge".
Remember, however, that data from a new well may overturn all previous analysis results on older wells. Thus, some critical assessment of the old data is required in addition to that usually accorded the new data. A data retrieval from a computer data base may reduce the labor in locating much of the needed information. Both commercial and in-house databases exist and appropriate software is available for most personal computers and workstations.
2.01 The Analysis Model
Quantitative log analysis is based on a series of mathematical formulas, or models, derived from the experience of many analysts. Thus, literally thousands of methods exist. The most universal applications have been assembled in this handbook. Only a very few of the equations are original to the author.
The Log Analysis Model takes into account two distinct problems:
1. Invasion of the formation by drilling mud filtrate.
2. The complex mixture of rock types and fluids that comprise the formation.
Invasion is a process whereby drilling mud fluid is forced into the rock due to differential pressure. The drilling mud is made up of solid particles and ions dissolved in water. This water displaces the native
formation water to some degree, and mixes with formation water that is not displaced. The distance to which some displacement and/or mixing occurs is called the invasion diameter, and the zone so disturbed is termed the invaded zone.
The zone nearest the borehole, or flushed zone, is the portion of rock where the maximum amount of
displacement and mixing has occurred. The balance of the invaded zone is named the transition zone, where the transition between maximum flushing and no invasion occurs. These definitions are illustrated
schematically in Figure PP2.04.
The invasion process leaves behind the solid particles of the mud, which collect on the borehole wall. The resulting material is called mudcake, and may be anywhere from 3 inches thick to very thin and difficult to detect. The mudcake thickness by definition, is one half the difference between the bit size and the borehole diameter. If the hole is enlarged by erosion beyond the bit size during drilling, the mudcake thickness may be impossible to determine.
Mudcake is the sealing agent which slows down invasion. As a result, high permeability zones which allow quick buildup of mudcake, invade the least, and low permeability zones invade the most or deepest. Non-permeable zones are not invaded. Since the mudcake is scraped off each time a drill pipe joint or the bit passes a formation, invasion of shallow zones may be repeated many times with many different fluids, thus making such zones difficult or impossible to analyze.
Figure PP2.04: The drilling fluid invasion model
Since the depth of investigation of logging tools varies, knowledge of the invasion profile is necessary in making assumptions about log analysis methods or parameters. Resistivity distribution in a radial direction from the borehole is determined by the invasion profile. The resistivity log reading in the formation depends on the response field of the logging tool and varies with the design of each tool. Resistivity logs which measure different depths into the rock can be used to estimate the invasion profile. Results are used to judge the reliability of resistivity data, and to correct the log readings for the effects of invasion.
For example, if the ratio of the deep to medium resistivity log values is between 0.8 and 1.2, invasion effects are minimal and no correction to the deep resistivity is made. If the ratio falls outside this range, corrections should be applied using the appropriate service company "Tornado Chart". These charts are ONLY useful in water zones – they do VERY BAD THINGS in hydrocarbon zones.
Sonic, density, neutron, gamma ray, and spontaneous potential logs see the invaded zone and are thus influenced by those fluids. Most mathematical models include terms which account for invasion of mud filtrate into oil or water zones, but special models are needed for gas zones. These are noted as special cases in subsequent sections of this handbook.
2.02 The Formation Rock Model
All log analysis methods are based on a uniform, industry accepted model of the reservoir rocks and fluids.
FIGURE PP 2.05: The Formation Rock/Fluid Model for Log Analysis Here are the definitions that derive from the rock/fluid model shown above.
DFN 1: The formation rock/fluid model is comprised of: - the matrix rock (Vrock)
- the pore space (or porosity) within the matrix rock (PHIe) - the shale content of the matrix rock (Vsh)
By definition, Vrock + PHIe + Vsh = 1.00
DFN 2: The matrix rock component (Vrock) can be subdivided into two or more constituents (Vmin1, Vmin2, ….), such as:
- limestone, dolomite, and anhydrite or - quartz, calcite cement, and glauconite
The mineral mixture can be quite complex and log analysis may not resolve all constituents.
DFN 3: The shale component (Vsh) can be classified further into: - one or more clays (Vcl1, Vcl2, …)
- silt (Vsilt)
- water trapped into the shale matrix due to lack of sufficient permeability to allow the water to escape
- water locked onto the surface of the clay minerals - water absorbed chemically into the molecules of the clay minerals
The sum of the three water volumes is called clay bound water (CBW). CBW varies with shale volume and is zero when Vsh = 0.
By definition, Vsh = Vcl + Vsilt + CBW
DFN 4: Bulk volume water of shale (BVWSH) is the sum of the three water volumes listed above in the definition of shale and is determined in a zone that is considered to be 100% shale.
By Definition, CBW = BVWSH * Vsh
DFN 5: Total porosity (PHIt) is the sum of: - clay bound water (CBW)
- free water, including irreducible water (BVW) - hydrocarbon (BVH)
DFN 6: Effective porosity (PHIe) is the sum of:
- free water, including irreducible water (BVW) - hydrocarbon (BVH)
DFN 7: Effective porosity is the porosity of the reservoir rock, excluding clay bound water (CBW). PHIe = PHIt – CBW
OR PHIe = PHIt – Vsh * BVWSH
Some of the “free water” is not free to move - it is, however, not “bound” to the shale.
DFN 8: Free water (BVW) is further subdivided into:
- a mobile portion free to flow out of the reservoir (BVWm)
- an immobile or irreducible water volume bound to the matrix rock by surface tension (BVI or BVWir) BVI is sometimes called “bound water”, but this is confusing (see definition of clay bound water above), so “irreducible water” is a better term. Note that BVWm = BVW – BVI.
DFN 9: Hydrocarbon volume (BVH) can be classified into: - mobile hydrocarbon (BVHm)
- residual hydrocarbon (BVHr)
DFN 10: Free fluid index (FFI) is the sum of BVWm, BVHm, and BVHr. It is also called moveable fluid (BVM) or useful porosity (PHIuse).
PHIuse = BVM = FFI = BVWm + BVHm + BVHr OR PHIuse = PHIe – BVI
OR PHIuse = PHIe * (1 – SWir)
This definition is needed for the nuclear magnetic log (NMR, CMR, etc), since it cannot see BVWir. Non-useful porosity also occurs as tiny pores that do not connect to any other pores. They are almost invariably filled with immoveable water and do not contribute to useful reservoir volume or energy. Such pores occur in silt, volcanic rock fragments in sandstones, and in micritic, vuggy, or skeletal carbonates. The NMR may see some of this non-useful porosity – the jury is still out.
DFN 11: Total water saturation (SWt) is the ratio of: - total water volume (BVW + CBW) to - total porosity (PHIt)
SWt = (BVW + CBW) / PHIt
DFN 12: Effective water saturation (Sw) is the ratio of: - free water volume (BVW) to
- effective porosity (PHIe) Sw = BVW / PHIe
This is the standard definition of “water saturation”. Older books use this term to define total water saturation. Since all interpretation methods described here correct for the effects of shale, we are not normally interested in the total water saturation, except as a mathematical by-product. As effective porosity approaches zero, the water saturation approaches one (by edict, if not by calculus).
DFN 13: Useful water saturation (SWuse) is the ratio of: - useful water volume (BVW - BVI) to
- useful porosity (PHIuse) SWuse = (BVW – BVI) / PHIuse
DFN 14: Irreducible water saturation (SWir) is the ratio of: - immobile or irreducible water volume (BVI) to - effective porosity (PHIe)
SWir = BVI / PHIe
DFN 15: Residual oil saturation (Sor) is the ratio of: - immobile oil volume (BVHr) to
- effective porosity (PHIe) Sor = BVHr / PHIe
DFN 16: The water saturation in the flushed zone (Sxo) is the ratio - free water in the flushed zone, to
- effective porosity, which is assumed to be the same porosity as in the uninvaded zone.
The amount of free water in the invaded zone is usually higher than in the uninvaded zone, when oil or gas is present. Thus Sxo >= Sw. The water saturation in the invaded zone between the flushed and uninvaded zone is seldom used.
DFN 17: Further constraints that should be remembered are: PHIt >= PHIe >= PHIuse
SWt >= Sw >= SWuse.
PHIt = PHIe and SWt = Sw when Vsh = 0
All volumes defined above are in fractional units. In tables or reports, log analysis results are often converted to percentages by multiplying fractional units by 100.
DFN 18: Capillary Pressure (Pc) is the force that pulls water up a thin tube (capillary) above the free water level.
The usual assumption for a new reservoir is: SWmin = SWinitial = SWir
DFN 19: Absolute Permeability (Ka) or Intrinsic Permeability is the ease with which air will flow through the effective porosity, also called
Air permeability (Kair) – measured in milliDarcies (mD).
DFN 20: Effective Permeability (Ko, Kw, Kg) is the permeability for a particular fluid, usually less than Kair.
DFN 21: Relative Permeability (Kro, Krw, Krg) is the ratio of the effective permeability of one fluid compared to the second fluid in a two phase system.
DFN 22: Water Cut (WC) is the ratio of water volume produced to the total fluid volume produced at the surface.
2.03 The Log Response Equation
The response of an individual log to the model described above is defined by the Log Response Equation, which takes the form:
THE LOG RESPONSE EQUATION
LOG = PHIe * Sxo * Lw (water term)
+ PHIe * (1 – Sxo) * Lh (hydrocarbon term) + Vsh * Lsh (shale term)
+ (1 – Vsh – PHIe) * Lma) (matrix term) WHERE: Lh = log reading in 100% hydrocarbon
Lma = log reading in 100% matrix rock LOG = log reading
Lsh = log reading in 100% shale Lw = log reading in 100% water PHIe = effective porosity (fractional)
Sxo = water saturation in invaded zone (fractional) Vsh = volume of shale (fractional)
This response equation will work for sonic travel time, density, or density porosity, neutron porosity, gamma ray (and the spectrolog curves - uranium, thorium and potassium), resistivity (if Sxo is replaced by Sw for deep resistivity logs), the electromagnetic propagation log, the thermal decay time log, and the photoelectric effect (if PE * DENS is used). It will also work for various derived logs described in later chapters of this handbook.
The response equations can be used in several ways. One is to find out what a log would read under a hypothetical set of circumstances. This is called forward modeling of log response, and is used to generate synthetic logs or to verify log analysis results. If the reconstructed log doesn’t match the recorded log, then something in the analysis model is wrong and must be fixed.
Another way is to calculate one unknown in the equation, for example porosity or shale volume, by using a log reading and assuming the other terms to be known or derivable from some other response equations. A third approach is to use sets of response equations simultaneously to determine as many unknowns as possible from the available log data.
Some terms in the response equation for certain logs go to zero. This is what makes it possible, for example, to calculate the shale volume from the gamma ray response. Both the water and hydrocarbon terms go to zero, since neither of these components has any gamma ray contribution. By re-arranging terms and further assuming that porosity is small, we get:
The Gamma Ray Response Equation Solved for Shale Volume
VSHgr = (GRlog – GRmatrix) / (GRshale – GRmatrix)
Here GRlog, GRshale, and GRmatrix are read from appropriate places on the gamma ray log to calculate shale volume.
In other cases, we sometimes lump two terms together, as for water and oil in the sonic log equation for porosity. This strategy eliminates the need to know water saturation prior to knowing porosity. This approach will fail if gas is present because the water and gas contributions are too dissimilar. The algorithms in
following chapters attempt to resolve as many of the unknowns as possible using these piecewise
techniques. Where this is inappropriate, sets of two or three simultaneous equations are solved, with the final solution being given. It will not always be obvious that simultaneous response equations were used, but ALL log analysis methods rely on this approach. What we have done here is eliminate the repetitive derivation of the solution, and present instead the finished product, ready for inclusion in a calculator or computer program.
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3.00 Eyeball Analysis Of Logs – Crain’s Simplified Rules
You should know the basic rules for eyeball analysis of log curves to help you climb the “Ladder to Success”. The common rules are described below with reference to Figures PP3.06A through PP3.06D. A more elaborate set of rules follows in Section 3.01. Lets start the race.
Crain’s Rule “Minus 1”:
Identify log curves available, and determine their scales.
FIGURE PP3.06A: The left half of this image shows a resistivity log with spontaneous potential (SP) in Track 1 and shallow, medium, and deep resistivity (RESS, RESM, RESD) on a logarithmic track to the right of the depth track. The right half of the image shows a density neutron log with gamma ray (GR) and caliper (CAL)
in Track 1. Photo electric effect (PE) is in Track 2 with neutron porosity (PHIN) and density porosity (PHID) spread across Tracks 2 and 3.
Crain’s Rule #0:
Gamma ray or SP deflections to the left indicate cleaner sands, deflections to the
right are shaly. Draw clean and shale lines, then interpolate linearly between clean and shale lines
to visually estimate Shale Volume (Vsh).
FIGURE PP3.06B: To find clean zones versus shale zones, examine the spontaneous potential (SP) response, gamma ray (GR) response, and density neutron separation. Low values of GR, highly negative values of SP, or density neutron curves falling close to each other usually indicate low shale volume. High GR values, no
SP deflection, or large separation on density neutron curves normally indicate high shale volume. Very shaly beds are not “Zones of Interest”. Everything else, including very shaly sands (Vsh < 0.50) and even obvious water zones, are interesting. Although a zone may be water bearing, it is still a useful source of log analysis information, and is still a zone of interest at this stage.
THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
Crain’s Rule #1:
The average of density and neutron porosity in a clean zone (regardless of
mineralogy) is a good first estimate for Effective Porosity (PHIe).
Crain’s Rule #2:
The density porosity in a shaly sand is a good first estimate for Effective Porosity
(PHIe), provided logs are on Sandstone Units.
FIGURE PP3.06C: For zones of interest, draw bed boundaries (horizontal lines). Then review the porosity logs: sonic, density, and neutron. All porosity logs deflect to the left for increased porosity. If density neutron
data is available, estimate porosity in clean sands by averaging the two log values. In shaly sands, read the density porosity. IMPORTANT: This is just an estimate and not a final answer.
Scale the sonic log based on the assumed matrix lithology. Mark coal and salt beds, which appear to have very high apparent porosity. Identify zones which show high medium, low, or no porosity. Low porosity, high shale content, coal, and salt beds are no longer “interesting”.
Crain’s Rule #3:
Tracking of porosity with resistivity on an overlay usually indicates water or shale.
OR
Low resistivity with moderate to high porosity usually undicates water or shale.
Crain’s Rule #4:
Crossover of porosity on a resistivity log overlay usually indicates hydrocarbons.
OR
High resistivity with moderate to high porosity usually indicates hydrocarbons.
FIGURE PP3.06D: Raw logs showing resistivity porosity overlay. Red shading indicates possible hydrocarbon zones.
To find hydrocarbon indications and obvious water zones, compare deep resistivity to porosity, by mentally or physically overlaying the density porosity on top of the resistivity log. High porosity (deflections on the
density log to the left) and high resistivity (deflections to the right) usually indicate oil or gas, or fresh water. See cross-hatched area on resistivity track of Figure PP3.06C.
Layer A on Figure PP3.06 is a shaly sand and has medium porosity. Layers B and C are clean sands and have high porosity. All other layers are shale with no useful porosity.
The average of density and neutron porosity in Layers B and C is 24 %. This is close to the final answer because there is not much shale in the zone. The average in Layer A is 16 % - much higher than the truth due to the influence of the shale in the zone. The density porosity is about 11%, pretty close to the core data. Therefore all our analysis must make use of shale correction methods.
Low resistivity and high porosity usually means water, as in Layer C. Known DST, production, or mud log indications of oil or gas are helpful indicators.
Layer B and Layer A show crossover when the porosity is traced on the resistivity log, so these zones remain interesting. In fresher water formations, it is often difficult or impossible to spot hydrocarbons visually. If it was easy, log analysts would be out of work!
Crossover on the density neutron log usually means gas. Watch for rough hole problems, sandstone
recorded on a limestone scale, or limestone recorded on a dolomite scale, which can also show crossover – not caused by gas.
Water zones with high porosity and low resistivity are called “obvious water zones”. Fresh water may look like hydrocarbons, particularly in shallow zones. The lack of SP development will often help distinguish fresh water zones. Low porosity water zones may not be obvious.
Crain’s Rule #5:
Approximate Water Saturation (SWa) in an obvious hydrocarbon zone is estimated
from: SWa = Constant / PHIe
where Constant is in the range from 0.0100 to 0.1200. Use 0.0400 as a first try in clean sands,
0.0600 to 0.0800 in shaly sands, and 0.0250 in intercrystalline carbonates.
Water saturation is usually calculated from the Archie equation or a shale corrected version of it. This is not easy to do with mental arithmetic. An easier estimate of water saturation can be made in obvious
hydrocarbon zones by using a method attributed to Buckles, and it is commonly used by reservoir engineers in a hurry.
Crain’s Rule #6:
On Limestone Units logs, the density neutron separation for limestone is near zero,
dolomite is 8 to 12 porosity units, and anhydrite is 15 or more. Sandstone has up to 7 porosity units
crossover.
On Sandstone Units logs, separation for sandstone is near zero, limestone is about 7 porosity
units, dolomite is 15 or more, and anhydrite is 22 or more.
Visual determination of lithology (in addition to identifying shale as discussed earlier) is done by noting the quantity of density neutron separation and/or by noting absolute values of the photo electric curve. The rules take a little memory work.
You must know whether the density neutron log is recorded on Sandstone, Limestone, or Dolomite porosity scales, before you apply Crain’s Rule #5. The porosity scale on the log is a function of choices made at the time of logging and have nothing to do with the rocks being logged. Ideally, sand-shale sequences are logged on Sandstone scales and carbonate sequences on Limestone scales. The real world is far from ideal, so you could find any porosity scale in any rock sequence. Take care!
FIGURE PP3.07: Sand – shale identification from gamma ray and density-neutron separation. Small amounts of density neutron separation with a low gamma ray may indicate some heavy minerals in a sandstone. Most minerals are heavier than quartz, so any cementing materials, volcanic rock fragments, or mica will cause some separation. Both pure quartz (no separation) and quartz with heavy minerals (some separation) are
FIGURE PP 3.08: Lithology identification is accomplished by observation of density neutron separation and the gamma ray response, along with a review of core and sample descriptions.
Crain’s Rule #7:
PE below 1 is coal, near 2 is sandstone, near 3 is dolomite or shale, and near 5 is
limestone or anhydrite. The high density (negative density porosity) of anhydrite will distinguish
anhydrite from limestone. High gamma ray will distinguish shale from dolomite.
Figure PP3.09: Combine N-D
separation rules and PE rules (N-D in percent). ROCK N–D N–D PE GR (SS) (LS) SAND 0 - 7 2 LO LIME 7 0 5 LO DOLO 15+ 8+ 3 LO ANHY 22+ 15+ 5 LO SALT - 37 - 45 4.5 LO SHLE 20+ 13+ 3.5 HI High GR log readings coupled with density neutron log readings that are close together, are a sign of
radioactive sandstone or limestone. To tell radioactive dolomite zones from shale zones, use a gamma ray spectral log, since the density neutron log will show separation in both cases. The PE value can help differentiate between radioactive dolomite and chlorite shale but not between dolomite and illite rich shale. High thorium values on the gamma ray spectral log indicate the shale.
Crain’s Rule #8:
If it is porous, it is
probably permeable.
To find signs of permeability, look for indications of porosity, mudcake shown by the caliper, separation on the resistivity log curves, known production or tested intervals, sample descriptions, and hydrocarbon shows in the mud.
Crain’s Rule #9:
If the logs are noisy, blame it on fractures.
To check for indications of fractures, look for sonic log skips, density neutron crossover in carbonates, hashy dipmeter curves, hashy resistivity curves, or caved hole in carbonates.
Crain’s Rule #10:
Check your work and revise your assumptions, then refine rules for each
project area.
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4.00 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 overpressured shales. Most shales are radioactive due to potassium and thorium, and sometimes due to uranium.
Shale distribution can vary, as shown in Figure 4.01 above. The shale volume calculations shown below are insensitive to the shale distribution. However, porosity and water saturation are strongly affected by
laminated shale, so the methods shown in Sections 5, 6, 7, and 8 in this handbook do not apply to laminated shaly sands.
*** PLEASE NOTE ***
You must choose the appropriate methods for each zone, but the minimum rule works well in most cases, provided the usage rules have been honored first.
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: Convert density log (gm/cc or Kg/m3) tp porosity units if a density porosity log is not available (skip this step if density data is already in porosity units):
1: PHIDSH = (DENSSH – KD2) / (KD1 – KD2) – do this once in an obvious shale zone 2: PHID = (DENS – KD2) / (KD1 – KD2) – do this for every data level
Where: KD1 = 1.00 for English units KD1 = 1000 for Metric units
KD2 = 2.65 for English units Sandstone scale log KD2 = 2650 for Metric units Sandstone scale log KD2 = 2.71 for English units Limestone scale log KD2 = 2710 for Metric units Limestone scale log KD2 = 2.87 for English units Dolomite scale log KD2 = 2870 for Metric units Dolomite scale log
NOTE: The choice for KD2 must match the neutron log units – if neutron is in Limestone units, KD2 must be 2.71 for gm/cc or 2710 for Kg/m3 log scale.
STEP 2: Calculate shale volume from the three common methods: 3: Vshg = (GR - GR0) / (GR100 - GR0)
4: Vshs = (SP - SP0) / (SP100 - SP0)
5: Vshx = (PHIN - PHID) / (PHINSH - PHIDSH) In tar sands or heavy oil, add the resistivity method:
6: Vshr = (logRESS - logRMAX) / (logRSH - logRMAX)
In radioactive sands, replace the gamma ray method with Thorium method if gamma ray spectral data is available:
7: Vshth = (TH - TH0) / (TH100 - TH0)
NOTE: Trim Vsh 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 3: Adjust gamma ray method for young rocks, if needed: 8: Vshc = 1.7 - (3.38 - (Vshg + 0.7) ^ 2) ^ 0.5
STEP 4: Take minimum of available methods: 9: Vsh = Min (Vshg, Vshs, Vshr, Vshx, Vshc)
Calibration of log analysis shale volume is usually accomplished by comparing it to sample descriptions, core description, thin section point counts, or X-ray diffraction data.
USAGE RULES:
• 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 density neutron crossplot when bad hole, gas, or heavy minerals are present.
• Do not use the nonlinear young rock model unless there is some evidence that it is needed. 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.
Average effective porosity calculated from logs is pessimistic in thinly laminated sand shale series, and unconventional methods should be used to determine porosity and water saturation.
PARAMETERS:
GR0 = 8 to 35 GR100 = 75 to 150 SP0 = -20 to -120 SP100 = +20 to -20 PHIDSH = -0.06 to +0.20 PHINSH = 0.15 to 0.45
All values must be picked from logs or assumed from previous experience.
THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
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5.00 Pore Volume
The second calculation step in a log analysis is to find shale corrected porosity. Pore volume is the space in a rock filled with oil, gas, or water. Total porosity includes the bound water in the shale and is called PHIt. Effective porosity does not include bound water, and is called PHIe. When there is no shale, PHIe equals PHIt. Logs read total porosity. All our analysis methods correct for shale, so the answers from any method
presented below will give effective porosity. Some analysis methods NEED total porosity as an intermediate step, so you may also need to calculate it.
Raw log porosity, as presented in the field by the service company, does NOT take into account shale or lithology effects, so raw log readings should NEVER be used as answers. Log analysis MUST ALWAYS be done to find the correct porosity. All our analysis methods also account for matrix rock (lithology), but YOU may be required to define the rock type for some methods. Other methods will define the lithology for you. YOU MUST choose a method that is appropriate for the available data and for the rock type being analyzed. The easiest methods are:
** Section 5.01: Porosity From The Sonic Log - use if density neutron combination is not available, or in bad hole when density log is no good.
** Section 5.02: Porosity From The Density Log - use in preference to sonic if available, lithology is well known, hole is good, and density neutron combination is not available.
** Section 5.03: Porosity From The Neutron Log - use if both sonic and density are not available.
** Section 5.04: Porosity From The Complex Lithology Density Neutron Crossplot - use in preference to a single log method except in bad hole where density is no good.
** Section 5.05: Porosity From The Dual Water Density Neutron Crossplot – use in quartz sands with no heavy minerals, otherwise use Complex Lithology method.
** Section 5.06: Porosity From The Photoelectric Density Neutron Crossplot - use in preference to complex lithology ONLY if mineral model end points are well known.
In all cases, the results must be trimmed to prevent too high a porosity in shaly zones and in bad hole by using Section 5.07: Material Balance for Porosity (Maximum Porosity). The META/ESP spreadsheet, available on the Downloads tab at www.spec2000.net, handles these models and makes the work relatively painless.
Unfortunately there is no standard logging program, so there is no single foolproof log analysis method. Each method has its own usage rules. These rules may need to be adjusted to suit local conditions. In the classroom or when starting work in a new area, you may want to try several methods, and see which matches core porosity the best.
Calibration of log analysis porosity is usually accomplished by comparing it to conventional core
porosity.
5.01 Porosity From The Sonic Log
The sonic is a simple method and must be employed if more modern density neutron data is not available. The method shown is called the Wyllie time average equation. Other porosity methods are presented in following sections.
Other methods for the sonic have been proposed, but they are really specific to certain areas, although this is not clearly stated in the literature. For example, the Hunt-Raymer transform is appropriate for the US Gulf Coast, but a poor model for the Lower Cretaceous in Western Canada. The Wyllie approach, when calibrated to core, is universally applicable.
NORMAL CASES:
STEP 1: Calculate shale porosity (PHISSH), a constant for each zone: 1: PHISSH = (DTCSH – DTCMA) / (DTCW – DTCMA)
DTCSH is a constant for the zone, chosen from the sonic log in a nearby shale. STEP 2: Calculate porosity from sonic log (PHIsc) for each layer in the zone:
2: PHIs = (DTC – DTCMA) / (DTCW – DTCMA) 3: PHIsc = PHIs – (Vsh * PHISSH)
The sonic porosity (PHIsc), after all corrections are applied, is called the effective porosity, PHIe.
SPECIAL CASES:
CASE 1: Correct each layer for lack of compaction, ONLY IF DTCSH > 328 (Metric) or DTCSH > 100 (English) 4: PHIe = PHIsc / KCP
CASE 2: Correct each layer for gas effect, ONLY IF PHIsc > PHItrue and gas is known or suspected 5: PHIe = PHIsc * KS
USAGE RULES:
• Use when density log is unavailable, or when density log is affected by bad hole.
• Of the three "one-log" porosity methods, the sonic corrected for shale is the preferred one for wells that have no density log. However, crossplot methods or the density log corrected for shale are usually better if the log data is available.
• If lithology is unknown, sonic log corrected for shale is better than density log because the lithology effect on the sonic is smaller.
• Use the compaction correction KCP only if DTCSH > 100 usec/ft (for English units) or DTCSH > 328 usec/m (for Metric units). In western North America, this is normally required when above 3,000 - 4,000 feet (900 – l,200 meters).
8: KCP = DTCSH / 100 (for English units) OR 9: KCP = DTCSH / 328 (for Metric units)
• KCP is never less than 1.0.
• Use the gas correction KS only if PHIsc is too high compared to other sources and if gas is known to be present. The need for this correction is common, but it is unlikely that a gas correction will be needed in very shaly sands since invasion should be relatively deep.
10: KS = PHItrue / PHIsc
• Another way of making gas corrections is to change DTCW to a higher value, representing the travel time of sound in a mixture of gas and water. This value depends on water saturation in the invaded zone, pressure, temperature, and gas compressibility. Values in the range of 600 usec/ft (1900
usec/m) at shallow depths to 300 usec/ft (950 usec/m) at 6000 feet (2000 meters) are recommended as a starting point.
• To calibrate to core porosity, adjust DTCMA, DTCW, DTCSH, KCP, KS, or Vsh to obtain a better match by trial and error. Appropriate crossplots may assist.
• A newer method called the Hunt - Raymer equation has been proposed, but it seems to work well only in the Gulf Coast of USA. Shale corrected data should be entered to this equation (not mentioned in original paper).
PARAMETERS:
* English Metric
usec/ft usec/m DTCSH 60 - 150 190 – 480 (choose from log)
KCP 1.0 - 1.4 1.0 - 1.4 KS 0.7 - 1.0 0.7 - 1.0 DTCW
Fresh drilling mud 200 656 Salty drilling mud 188 616 DTCMA Clean Quartz 55.5 182 Calcite 47.3 155 Dolomite 44.0 144 Anhydrite 50.0 164 Gypsum 52.4 172 Mica Muscovite 47.3 155 Biotite 55.5 182 Clay Kaolinite 64.3 211 Glauconite 55.5 182 Illite 64.6 212 Chlorite 64.6 212 Montmorillonite 64.6 212 Barite 69.8 229 NaFeld Albite 47.3 155 Anorthite 45.1 148 K-Feld Orthoclase 68.9 226 Iron Siderite 44.0 144 Ankerite 45.7 150 Pyrite 39.6 130 Evaps Fluorite 45.7 150 Halite 67.0 220 Sylvite 73.8 242 Carnalite 78.0 256 Coal Anthracite 105 345 Lignite 160 525
For mixtures, take the average of two pure values as a starting point, eg: dolomitic sand, DTCMA = (144 + 182) / 2 = 163 usec/m, or prorate the values in proportion to the described mineral assemblage.
5.04 Porosity From The Complex Lithology Density
Neutron Crossplot
The best method available for modern, simple, log analysis involves the density neutron crossplot. Several variations on the theme are common, but not all models are recommended. A crossplot method, called the shaly sand model was once widely used. It was found to be a poor model for any sandstone that contained other minerals in addition to quartz. The complex lithology model works equally well in quartz sands as in mixtures, so it is the preferred model today. Although the name of the method is complicated, the
mathematics are not.
NORMAL CASES:
STEP 1: Shale correct the density and neutron log data for each layer: 1: PHIdc = PHID – (Vsh * PHIDSH)
2: PHInc = PHIN – (Vsh * PHINSH)
PHIDSH and PHINSH are constants for each zone, and are picked only once.
STEP 2: Check for gas crossover after shale corrections and calculate porosity for each layer from the correct equation:
3: IF PHInc >= PHIdc, there is no gas crossover 4: THEN PHIxdn = (PHInc + PHIdc) / 2
The density neutron crossplot porosity, PHIxdn, after all corrections are applied, is called the effective porosity, PHIe.
Chartbook solutions are provided in Figure PP5.12. Shale corrected data must be entered.
SPECIAL CASES:
CASE 1: IF gas is known to be present AND gas crossover occurs after shale corrections, apply the following gas correction:
6: IF PHInc < PHIdc, there is gas crossover
7: THEN PHIxdn = ((PHInc ^ 2 + PHIdc ^ 2) / 2) ^ 0.5
CASE 2: IF gas is known to be present but no crossover occurs after shale corrections, this usually means gas in dolomite or in a sandstone with lots of heavy minerals, apply the following gas correction:
8: PHIx = – PHIdc / (PHInc / 0.8 – 1) / (1 + PHIdc / (0.8 – PHInc)) 9: PHIxdn = PHIx + KD3 * (0.30 – PHIx) * (DENSMA / KD1 – KD2) Where: KD1 = 1.00 for English units
KD1 = 1000 for Metric units
KD2 = 2.65 for Sandstone scale log KD2 = 2.71 for Limestone scale log KD3 = 1.80 for Sandstone scale log KD3 = 2.00 for Limestone scale log
THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
FIGURE PP5.12: Density Neutron Complex Lithology Crossplot
Do not use Dolomite scale log for this special case. Figure PP5.14 shows the effect of using this gas correction. Notice that computed porosity does not match core porosity unless the correct DENSMA is
chosen. DENSMA should reflect the matrix density of the expected lithology. This can be predicted accurately if the PE curve can be used to determine mineral volumes in a two mineral model. Density and neutron data cannot be used for this purpose because the gas effect masks the mineral effect.
Chartbook solutions are provided in Figure PP5.13 when gas is present. Shale corrected data must be entered.
CASE 3: IF rock is dolomite AND porosity is less than 5%, use the following instead of Equation 4 or 5: 10: E = (4 - (3.3 + 10 ^ (-5 * PHInc - 0.16))
11: PHIxdn = (E * PHIdc + 0.754 * PHInc) / (E + 0.754)
This option can be used instead of equation 4 as long as there is no gas crossover after shale corrections. It is slightly more accurate, but requires a computer or preprogrammed calculator.
CASE 4: IF Archie or dual water model is to be used for water saturation, the following is needed: 12: BVWSH = (PHIDSH + PHINSH) / 2 (a constant for the zone)
13: PHIt = (PHID + PHIN) / 2 (one value for each layer) CASE 5: IF zone is vuggy carbonate, calculate secondary porosity:
14: PHIsec = PHIxdn - PHIsc
USAGE RULES:
• Use in preference to most methods if data is available, even in shaly sands to correct for heavy mineral content.
• Do not use when density is affected by bad hole conditions.
• No correction for log units (eg Sandstone or Limestone units) is needed for most cases, except gas in dolomite and low porosity dolomite. Use Limestone units log ONLY for these two special cases. • Answer porosity is accurate to +/- 1% porosity using the simplified rules.
• For better accuracy, use Equations 10 and 11 with Limestone units logs instead of simpler rules, except gas rules must still be applied.
• The matrix density required for the gas correction must be assumed from the sample descriptions or by calculating the lithology from the PE (photoelectric effect) log if it is available.
• Shale corrections could create apparent gas crossover and this may be real or an artifact of excessive correction. Check against known data from the well if shale correction creates crossover.
• Charts and math for sonic density and sonic neutron crossplots are provided in Chapter Seven of Crain’s Petrophysical Handbook.
• To calibrate to core porosity, adjust DENSMA, PHIDSH, PHINSH or Vsh to obtain a better match by trial and error. Appropriate crossplots may assist, or regression of PHIxdn vs core porosity may be used.
PARAMETERS:
PHIDSH -0.06 - 0.15 (choose from log) PHINSH 0.15 - 0.45 (choose from log)
FIGURE PP5.13: Density neutron crossplot for porosity with gas in heavy minerals (eg dolomite)
THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY
The complete manual is 193 pages, available at
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5.09 Porosity from Nuclear Magnetic Log
The Log Response Equation for modern nuclear magnetic logs is the same as for all other logs. The difference between the NMR and other porosity logs is that the Log Response Equation is solved by the service company at logging time, instead of by the analyst after the logs are delivered. This transform is illustrated in Figure PP5.16.
The matrix and dry clay terms of NMR response are zero. An NMR log run today can display clay bound water (CBW), irreducible water (capillary bound water, BVI), and mobile fluids (hydrocarbon plus water, BVM), also called free fluids or free fluid index (FFI). On older logs, only free fluids (FFI) is recorded and some
subtractions, based on other open hole logs, are required. For modern logs:
1: PHIt = CBW + BVI + BVM 2: PHIe = BVI + BVM 3: PHIuse = BVM
Some or all of the sums defined above may be displayed on the delivered log. Log presentation is far from standard for NMR logs. In some situations, mobile water can be separated from hydrocarbon, and sometimes gas can be distinguished from oil, by further (experimental) processing of the original signal. However, the depth of investigation and measurement volume are tiny, so the hydrocarbon indication is from the invaded zone.
For the same reason, PHIt and PHIe from NMR do not always agree with that derived from density neutron methods, which see much larger volumes of rock.
FIGURE PP5.16: Nuclear Magnetic Resonance Response to Fluids For older logs:
1: PHIuse = FFI
2: SWir = KBUCKL / PHIuse 3: PHIe = FFI / (1 – SWir)
4: BVWSH = (PHINSH + PHIDSH) / 2 5: PHIt = PHIe + Vsh * BVWSH
PHIe and PHIt should be compared to density neutron or other methods defined earlier. KBUCKL is in the range 0.010 to 0.100, with a default of 0.040.
5.10 Fracture Porosity
There are a number of techniques published for calculating fracture porosity from conventional open hole logs. All were developed before the processing of formation micro-scanner data for fracture aperture became common. These older methods over-estimate fracture porosity. The only correct method is to use fracture aperture and frequency data from FMI/FMS processed logs:
1: PHIfrac = 0.001 * Wf * Df * KF1
Where: KF1 = number of main fracture directions = 1 for sub-horizontal or sub-vertical = 2 for orthogonal sub-vertical = 3 for chaotic or brecciated PHIfrac = fracture porosity (fractional) Df = fracture frequency (fractures per meter) Wf = fracture aperture (millimeters)
Fracture porosity is exceedingly small and seldom is larger than 0.25% (0.0025 fractional). This is well below the noise level of conventional open hole logs. Fracture aperture from cores or thin section may be
exaggerated due to stress release, so be cautious using this data. Some “fracture-related” porosity, such as solution porosity near the fracture face, will be seen by conventional logs, which is why some older fracture porosity methods give quite high values for fracture porosity
5.11 Porosity from Old ES Logs
There are a number of techniques for handling ancient logs like the old electrical survey (ES). The simplest is to use the shallow resistivity and assume that the flushed zone water saturation is near 1.0.
1: PHIxo = (A / ((RXO / RMF@FT) * (SXO ^ N))) ^ (l / M)
This is pretty nearly a last resort. Old style neutron logs (Section 5.03) and the maximum porosity methods (Section 5.07) may work better,
The microlog can also be used: 1: IF RES2 > RES1 2: THEN PHIml = 0.614 ((RMF@FT * KML) ^ 0.61) / (R2 ^ 0.75) 3: OTHERWISE PHIml = 0