Crain Book

CRAIN’S PETROPHYSICAL POCKET PAL

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 ISBN 0-9734171-1-0

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

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SAMPLE REFERENCE MANUAL 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/00orders.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, nononsense, 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. FREE Sample Lecture (17 MB) You can run the slide shows at your own speed, repeat individual slides, pause to read more in the supplied Reference Manuals, have a coffee, feed the baby, or check your email - you can plan your time to suit your personal situation. The material is also suitable for a structured environment such as In-House Training or Tech School / University settings. Unlimited Worldwide Multi-Student Corporate and Academic Licenses Are Available. Contact us by email for details. Put 50 yrats of continuous practical experience to work for you!

THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

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CRAIN’S PETROPHYSICAL POCKET PAL 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 7.03 Water Resistivity From Spontaneous Potential 75

Crain’s Petrophysical Pocket Pal

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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

CONVERSION FACTORS Feet = 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)

ABOUT THE AUTHOR: E. R. (Ross) Crain, P.Eng. is a Consulting Petrophysicist 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

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

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CRAIN’S PETROPHYSICAL POCKET PAL 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 highgrade 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.

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

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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.

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

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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.

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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 The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm

Crain’s Petrophysical Pocket Pal

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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

Often Called Detail scale or large scale Correlation scale or small scale Super detail scale * Dipmeter scale

English Terminology

Metric Terminology

5" = 100 ft 2" = 100 ft 1" = 100 ft 10" = 100 ft 25" = 100 ft 60" = 100 ft

1:240 1:600 1:1200 1:120 1:48 1:20

1:200 is also very common 1:500 is also very common 1:1000 is also very common 1:100 is also very common 1:50 is also very common

8 pages omitted 

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

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CRAIN’S PETROPHYSICAL POCKET PAL 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 Crain’s Petrophysical Pocket Pal

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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. Nonpermeable 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.

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Copyright 1978 – 2012 E. R. Crain, P.Eng.

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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.

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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 Crain’s Petrophysical Pocket Pal

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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).

OR

PHIe = PHIt – CBW 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. Nonuseful 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 Crain’s Petrophysical Pocket Pal

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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. Crain’s Petrophysical Pocket Pal

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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 + PHIe * (1 – Sxo) * Lh + Vsh * Lsh + (1 – Vsh – PHIe) * Lma)

(water term) (hydrocarbon term) (shale term) (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.

4 Pages Omitted 

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CRAIN’S PETROPHYSICAL POCKET PAL 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 Petrophysical Pocket Pal

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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 The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm Crain’s Petrophysical Pocket Pal

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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”.

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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 Crain’s Petrophysical Pocket Pal

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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!

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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 seen in Figure PP3.07.

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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.

The photoelectric effect is often a direct mineralogy indicator. (PE is invalid on Figure PP3.08). Crain’s Petrophysical Pocket Pal

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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 (SS) (LS) SAND 0 -7 LIME 7 0 DOLO 15+ 8+ ANHY 22+ 15+ SALT - 37 - 45 SHLE 20+ 13+

PE

GR

2 5 3 5 4.5 3.5

LO LO LO LO LO 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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CRAIN’S PETROPHYSICAL POCKET PAL 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. Crain’s Petrophysical Pocket Pal

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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.

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CRAIN’S PETROPHYSICAL POCKET PAL 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.

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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 •

KS is never greater than 1.0. Crain’s Petrophysical Pocket Pal

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•

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 usec/ft

Metric usec/m

DTCSH (choose from log) KCP KS

60 - 150

190 – 480

1.0 - 1.4 0.7 - 1.0

1.0 - 1.4 0.7 - 1.0

DTCW Fresh drilling mud Salty drilling mud

200 188

656 616

DTCMA Clean Quartz Calcite Dolomite Anhydrite Gypsum Mica Muscovite Biotite Clay Kaolinite Glauconite Illite Chlorite Montmorillonite Barite NaFeld Albite Anorthite K-Feld Orthoclase Iron Siderite Ankerite Pyrite Evaps Fluorite Halite Sylvite Carnalite Coal Anthracite Lignite

55.5 47.3 44.0 50.0 52.4 47.3 55.5 64.3 55.5 64.6 64.6 64.6 69.8 47.3 45.1 68.9 44.0 45.7 39.6 45.7 67.0 73.8 78.0 105 160

182 155 144 164 172 155 182 211 182 212 212 212 229 155 148 226 144 150 130 150 220 242 256 345 525

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.

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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

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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. Crain’s Petrophysical Pocket Pal Copyright 1978 – 2012 E. R. Crain, P.Eng. Page 31 of 54

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 PHINSH

-0.06 - 0.15 (choose from log) 0.15 - 0.45 (choose from log)

See Section 5.02 for matrix density (DENSMA) if needed for gas correction.

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FIGURE PP5.13: Density neutron crossplot for porosity with gas in heavy minerals (eg dolomite)

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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 Crain’s Petrophysical Pocket Pal

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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

PARAMETERS Mud Weight lb/gal Kg/m3 8 1000 10 1200 11 1325 12 1440 13 1550 14 1680 16 1920 18 2160

KML frac 1.000 0.847 0.708 0.584 0.488 0.412 0.380 0.350

6 Pages Omitted  THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm Crain’s Petrophysical Pocket Pal

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6.03 Lithology From PE Density Neutron Data This is the best method for calculating lithology if the data is available. This method provides two different two-mineral and one three-mineral models. YOU must choose the model which gives the best resolution for the mineral end points you have chosen. Resolution is better when the values for the end points have the largest absolute difference.

NORMAL CASES: STEP 1: Calculate shale density and shale capture cross section (a constant for each zone): 1: DENSSH = PHIDSH * KD1 + (1 – PHIDSH) * KD2 2: USH = PESH * DENSSH STEP 2: Translate density porosity to density units for each layer: 3: DENS = PHID * KD1 + (1 – PHID) * KD2 Where: KD1 = 1.00 KD2 = 2.65 for Sandstone scale KD2 = 2.71 for Limestone scale NOTE: Density data is needed in English units (gm/cc). STEP 3: Calculate matrix capture cross section for each layer: 4: Uma = (PE * DENS – Vsh * USH) / (1 – PHIe – Vsh) STEP 4: Calculate two mineral rock volumes from UMA: 5: Min1 = (Uma – UMA2) / (UMA1 – UMA2) 6: Min2 = 1.0 – Min1 STEP 5: Calculate two mineral rock volumes from PE: 7: Min1 = (PE – PE2 – PESH * Vsh) / (PE1 – PE2) 8: Min2 = 1.0 – Min1 STEP 6: Calculate three mineral rock volumes from Uma and DENSma: 9: D = (Uma * (DENS2 – DENS1) + DENSma * (UMA1 – UMA2) + UMA2 * DENS1 – UMA1 * DENS2) / (UMA1 * (DENS3 – DENS2) + UMA2 * (DENS1 – DENS3) + UMA3 * (DENS2 –DENS1)) 10: E = (D * (DENS3 – DENS1) – DENSma + DENS1) / (DENS1 – DENS2) 11: Min1 = MAX(0, 1 – D – E) / (MAX(0, 1 – D – E) + MAX(0, D) + MAX(0, E)) 12: Min2 = MAX(0, E) / (MAX(0, 1 - D - E) + MAX(0, D) + MAX(0, E)) 13: Min3 = 1 – Min1 – Min2

SPECIAL CASES: Only the PE 2 mineral model can be used in gas zones. To use DTCma instead of Uma, replace all Uma terms with DTCma terms in Equations 9 and 10. Equations 1 thru 8 are not needed, but DTCma and DENSma must be derived as shown in Section 6.01.

USAGE RULES: •

If Min1 and Min2 are to be plotted in a volumetric track with Vsh and PHIe, multiply by Vrock before plotting, where Vrock = 1 - PHIe – Vsh.

•

Use the Uma method any time data is available, but not in bad hole conditions or when gas is present.

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CRAIN’S PETROPHYSICAL POCKET PAL 8.00 Water and Hydrocarbon Saturation The fifth step in a log analysis is to find water saturation. Water saturation is the ratio of water volume to pore volume. Water bound to the shale is not included, so shale corrections must be performed if shale is present. We calculate water saturation from the effective porosity and the resistivity log. Hydrocarbon saturation is 1 (one) minus the water saturation.

All methods rely on work originally done by Gus Archie in 1940-41. He found from laboratory studies that, in a shale free, water filled rock, the Formation Factor (F) was a constant defined by: 1: F = R0 / Rw He also found that F varied with porosity: 2: F = A / (PHIt ^ M) For a tank of water, R0 = Rw. Therefore F = 1. Since PHIt = 1, then A must also be 1.0 and M can have any value. If porosity is zero, F is infinite and both A and M can have any value. However, for real rocks, both A and M vary with grain size, sorting, and rock texture. The normal range for A is 0.5 to 1.5 and for M is 1.7 to about 3.2. Archie used A = 1 and M = 2. In fine vuggy rock, M can be as high as 7.0 with a correspondingly low value for A. In fractures, M can be as low as 1.1. Note that R0 is also spelled Ro in the literature. For shale free rocks with both hydrocarbon and water in the pores, he also defined the term Formation Resistivity Index ( I ) as: 3: I = Rt / R0 4: Sw = ( 1 / I ) ^ (1 / N) Archie used an N of 2 and the usual range is from 1.3 to 2.6, depending on rock texture. It is often taken to equal M, but this is not supported by core data in all cases. Rearrangement of these four equations give the more usual Archie water saturation shown in the next section. Shale corrections are applied by adding a shale conductivity term with an associated shale porosity and shale formation factor relationship. Numerous authors have explored this approach, leading to numerous potential solutions for water saturation. Two of the most common are given in Section 8.03 and 8.04.

*** PLEASE NOTE *** Again, YOU must choose an appropriate method from one of the following: ** Section 8.02: Water Saturation from Archie Method - use in clean (non-shaly) zones. ** Section 8.03: Water Saturation from Simandoux Method - use in shaly zones, simpler math than Dual Water Method. Crain’s Petrophysical Pocket Pal

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** Section 8.04: Water Saturation from Dual Water Method - use in shaly zones, preferred when shale resistivity is very low (less than 2 ohm-m). ** Section 8.05: Water Saturation from Buckles Number Method - use when water resistivity is not known, or for rough approximations. If you want to estimate moveable hydrocarbon, as opposed to hydrocarbons in place, you will have to calculate water saturation in the invaded zone. Water cut is derived from the differences between actual water saturation and irreducible water saturation.

Water saturation can be calibrated by comparing log analysis results with water saturation from capillary pressure data on core samples, and in some cases from oil base cores.

8.01 Determination of Saturation Parameters A, M, and N Archie initially proposed that A = 1.0, M = 2.0, and N = 2.0; later it was found that these values varied with rock type. When electrical properties are available, they should be used, provided they fall within reasonable ranges and the data set is large enough to be valid. Data is usually presented in tabular as well as graphical form, as in Figures PP8.23 and 8.24. In Figure PP8.23, the slope of the best fit line through the formation factor data is the cementation exponent, M. The best fit line can be forced through the origin (a pinned line) which makes the tortuosity factor A = 1.0 exactly. The intercept of the best fit (un-pinned) line will give A; in this example A = 0.60. Data should be grouped by rock type, porosity type, or mineralogy before the best fit lines are determined. A cross plot of the deep resistivity versus porosity on a log-log scale made in a clean “obvious” water zone will provide the slope M. The intercept of the line at PHIe = 1.0 is A * RW. This is called a Pickett Plot and is often a product of computerized log analysis. Shaly zones should be excluded because the shale corrected water saturation equations correct automatically for varying A and M.

 Figure PP8.21: Pickett plot showing different slopes (M) for dolomite (red) and limestone (blue) in a single reservoir

The M value in fractured rock can be quite low and compensates for the invasion of drilling fluid into the fractures. These plots are also made with shallow resistivity versus porosity. All zones are assumed to be wet due to invasion, but of course this is not true. The slope M may still be valid but the intercept is no longer A * RW, and is generally meaningless. Figure PP8.22: Pickett plot showing low values of M in fractured reservoir and higher values in un-fractured  intervals M can be varied for every depth level by computing it from the position of the data point on the Pickett plot. This is usually done in carbonates or fractured reservoirs, using shallow resistivity. This “variable M” is then used with the deep resistivity to calculate water saturation.

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In water zones: 1: log(RESD) = – M * log(PHIe) + log(A * RW@FT) 2: M = (log(A * RW@FT) – log(RESD)) / log(PHIe) In hydrocarbon zones we assume the flushed zone is nearly 100% wet: 3: log(RESS) = – M * log(PHIe)+log(A*RMF@FT) 4: M = (log(A*RMF@FT) - log(RESS)) / log(PHIe) The M value can be varied zone-by-zone or for every data point. This is especially useful in fractured reservoirs or carbonate reservoirs with varying pore geometry.

FIGURE PP8.23: Formation Factor versus Porosity plot to find saturation parameters A and M The value for the saturation exponent N is usually found in the laboratory as in Figure PP8.24. It is a plot of resistivity index ( I ) versus water saturation. Several partial saturations are taken on each core plug and N is determined from the slope of the line through these points. N can be varied by defining lithofacies for each core plug and relating this to some log signature. There is no equivalent crossplot to find N from log data. The best fit line on this plot is always pinned at the origin, since resistivity index must equal 1.0 when SW = 1.0 by definition. Crain’s Petrophysical Pocket Pal

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Figure PP5.24: Resistivity Index versus Water Saturation to determine saturation exponent N

VARIABLE "M" METHODS FOR CARBONATES The cementation exponent M is more difficult to assess in carbonates - it varies with pore geometry, and with porosity in some pore types. Typical rock types in carbonates are intergranular (clastic texture), intercrystalline (fine, medium, or coarse), vuggy (fine, medium, or large), microporosity (unconnected pores), oomoldic, and fractured zones (with any other rock type). Rock typing is usually done from sample or core description. M can be made to vary by solving equation 1 or 2 for each data point instead of fitting a line through the average of the data set. Various authors have proposed specific solutions, as illustrated below:

Shell Method Analysts at Shell Oil proposed a formula to vary M in carbonates with porosity. Other relationships could be found by fitting non-linear curves to the data used Crain’s Petrophysical Pocket Pal Copyright 1978 – 2012 E. R. Crain, P.Eng.

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for the Pickett plot or by plotting individual M values versus porosity: 6: M = 1.87 + 1.9 * PHIe

Focke and Munn l Method The Focke and Munn paper referred to earlier shows a variety of data sets, in which M increases with porosity, as shown below: 7: M = 1.20 + 12.76 * PHIe (perm < 0.10) 8: M = 1.40 + 6.57 * PHIe (perm = 0.1 - 1.0) 9: M = 1.20 + 6.29 * PHIe (perm = 1.0 - 100) 10: M = 1.22 + 3.49 * PHIe (perm > 100) WHERE: M = cementation exponent (unitless) PHIe = porosity from any source (fractional

Nugent Method An equation proposed by Nugent uses the secondary porosity concept: 11: M >= 2 * log(PHIsc) / log(PHIxnd) PHIsc represents the matrix porosity and PHIxnd represents the effective porosity in the carbonate rock. Both should be shale corrected as described in Chapter Seven. Use Nugent's method in intergranular, intercrystalline, vuggy, and fossilmoldic rock types. Results are too low in oomoldic rock type. PHIsc must be calculated with a matrix value (DELTMA) that varies with the rock lithology. This can be derived from the results of a two or three mineral model or sample description with DELTMA = V1 * DELTMA1 + V2 * DELTMA2 + V3 * DELTMA3.

Nurmi Method In oomoldic porosity, Nurmi proposed the following: 12: PHIvug = 2 * (PHIxnd - PHIsc) 13: PHIma = PHIxnd - PHIvug 14: M >= 2 * log(PHIma) / log(PHIxnd) Use Nurmi method in oomoldic rock type. PHIsc must be calculated with a matrix value (DELTMA) that varies with the rock lithology. This can be derived from the results of a two or three mineral model or sample description.

Rasmus Method The same techniques used to derive M for various carbonate rock types can also be used to find M in fractured carbonates. A standard Pickett plot in water zones, or a Pickett plot using a shallow resistivity log in the invaded zone, will usually suffice. The M value so derived will be the result of BOTH fractures and the rock type in the zone covered by the crossplot. Normally, M is chosen once for each fractured interval from Pickett plots over well-defined rock type zones or layers. However, there is no reason to believe M is a constant in a zone because fracture intensity probably varies dramatically from foot to foot within the layer. A method proposed by Rasmus, based on secondary porosity concepts, solves this problem: 11: Md = log((1 - (PHIxnd - PHIsc)) * (PHIsc^Mb) + (PHIxnd - PHIsc)) / log(PHIe) Mb is the formation factor exponent for the bulk matrix (un-fractured) rock and Md is the value for the combined matrix plus fracture, or double porosity, porosity. Mb should be determined separately in unfractured zones if possible.

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8.02 Water Saturation from Archie Method The most common saturation method was developed by Gus Archie in 1941. It is widely used in all parts of the world and is suitable for carbonates, clean sands, and shaly sands where RSH is above 8 ohm-m. Where shale resistivity is low, the Archie method will be pessimistic in shaly sands. STEP 1: Calculate water saturation: 1: PHIt = (PHID + PHIN) / 2 2: Rwa = (PHIt ^ M) * RESD / A 3: SWa = (RW@FT / Rwa) ^ (1 / N) The term (1/N) is usually ½ or 0.5, which represents the square root. Hence: 3A: SWa = Sqrt (RW@FT / Rwa) The water saturation from the Archie method (SWa) is called the effective water saturation, Sw. To calculate Sxo, replace RESD with RESS and RW@FT with RMF@FT.

USAGE RULES: •

The Archie method should only be used when Vsh < 0.20 and RSH > 8.0. If Vsh is high or RSH is low, then SWa is too high and a shale corrected method should be used.

•

A quick look version of the Archie formula sets A = 1.0, M = 2.0 and N = 2.0.

3: SWa = (RW@FT / (PHIt ^ 2) / RESD) ^ 0.5 •

This formula can be calculated by mental arithmetic or on a scratch pad when needed, and is accurate enough for quick look work.

•

Calibrate water saturation to core by preparing a porosity vs SW# graph from capillary pressure data. Adjust RW, A, M, N, PHIe until a satisfactory match is achieved.

PARAMETERS: for sandstone for carbonates for fractured zones

A = 0.62 M = 2.15 N = 2.00 A = 1.00 M = 2.00 N = 2.00 M = 1.2 to 1.7

NOTE: A, M, and N should be determined from special core analysis if possible.

THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm

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CRAIN’S PETROPHYSICAL POCKET PAL 9.00 Permeability The sixth step in a log analysis is to estimate permeability and productivity. These values determine whether a zone is commercially attractive. There are a number of methods for calculating matrix permeability. *** PLEASE NOTE *** You must choose a method appropriate to the available data: ** Section 9.01: Permeability from the Wyllie-Rose Method - use if no core data is available. ** Section 9.02: Permeability from Porosity - use if core data is available. ** Section 9.03: Permeability from the Coates Method - use in place of Wyllie-Rose, more optimistic in low porosity. Although it is not a quantitative measure of permeability, the separation between the two microlog curves is an excellent indicator. The log can still be run today as part of a density log survey.

Log analysis matrix permeability is calibrated to maximum core permeability (absolute permeability or air permeability). Allowance must be made to eliminate fractured samples from the core data set. Permeability to liquids is lower than absolute permeability. Flow capacity from logs (KH) can be compared to pressure buildup analysis. Again fractures will cause a difference.

9.01 Permeability From the Wyllie-Rose Method The general form of this equation has been used by many authors, with various correlations between log and core data. Individual analysts routinely calibrate their core and log data to this equation. STEP 1: Calculate permeability 1: PERMw = CPERM * (PHIe ^ DPERM) / (SWir ^ EPERM) If we recall that SWir = KBUCKL / PHIe, we see that this equation is strictly a function of porosity if KBUCKL is a constant. However, KBUCKL varies with shale volume and grain size, so Perm will vary also. The permeability from the Wyllie method (PERMw) is called the effective permeability, Perm. The result is in millidarcies. It can be calibrated to air, absolute, maximum, or Klinkenberg corrected permeability from core analysis, You should state which type of core analysis you calibrated to.

USAGE RULES: •

Use anytime, usually when no core data is available.

•

Not reliable in fractures or heterogeneous reservoirs.

•

Calibrate to core by adjusting CPERM, DPERM, and EPERM. Sw, PHIe and Vsh should have been accomplished earlier.

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PARAMETERS: RESEARCHER *

CPERM OIL or WATER GAS

DPERM

EPERM

Morris-Biggs Timur

65000 6500

6.0 4.5

2.0 2.0

6500 650

Values of CPERM as low as 10 000 and as high as 1 000 000 have been used in the Morris - Biggs equation. It is also called the Tixier equation.

9.02 Permeability From Porosity Permeability is often a semi-logarithmic function of porosity, unfortunately with a fairly large deviation. Core data is usually plotted to determine the equation of the best fit line: it can be calibrated to air, absolute, maximum, or Klinkenberg corrected permeability from core analysis,

STEP 1: Calculate permeability 1: PERMp = 10 ^ (HPERM * PHIe + JPERM) The permeability from the Porosity method (PERMp) is called the effective permeability, Perm. The result is in millidarcies.

USAGE RULES: •

Use anytime that parameters can be calibrated to core, especially in low porosity.

•

Not reliable in fractures or heterogeneous reservoirs.

•

A best fit line of the logarithm of core permeability vs. core porosity is often used to obtain this relationship for a particular zone.

PARAMETERS: Sandstones Carbonates Very fine grain Chalky Fine grain CryptocrystallineMedium grain Intercrystalline Coarse grain SucrosicConglomerate Fine vuggy Unconsolidated Coarse vuggy Fractured Fractured

JPERM –3.00 –2.50 –2.20 –2.00 –1.80 –1.50 –1.00

HPERM 16 18 20 22 24 26 30

The medium grain parameters approximate the Wyllie - Rose equation. These parameters should be calibrated to core data whenever possible.

29 Pages Omitted  THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm

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12.03 Case History – Devonian Carbonate Reef This example is more complex than first appearances would indicate. Initially, the resistivity and porosity logs show a 70 meter pay zone, but study of tests, production history, and workover history on this and adjacent wells paint a different story. Water break through has begun in the lower portion, defined by lower resistivity values at 2158, 2166, and 2173 meters. The extra high resistivity from 2108 to 2115 meters is a gas cap, which probably extends down to 2130 meters. Since production rates are severely penalized by government regulations when GOR is too high, this interval cannot be completed, leaving only a short interval between 2138 and 2174 meters available for production – about half the “net pay” interval. Completing too close to the water contact is also unwise, further restricting the completion interval. The PE curve indicates clean dolomite, while the density neutron shows little separation for dolomite in the gas zone at the top. The raw logs indicate limestone with 8 % porosity when the zone is really dolomite with 10 – 12% porosity. This is caused by gas effect canceling the dolomite effect. Porosity must be computed from the special "Gas in Heavy Minerals" algorithm over this interval or the results will be far too pessimistic. Many computer aided log analysis programs cannot do this without some help from you. Beware of underestimating porosity in the “Gas in Dolomite” environment. Although visual observation would provide good porosity values in the oil and water zones, it is completely inadequate in the gas and solvent zones.

FIGURE CH3.01: Induction and sonic logs on dolomite reef. Spikes on deep and shallow resistivity and poor quality sonic (shaded red) suggest fractures, confirmed in the core and production rates. Sonic log from offset well is shown in red to assist in editing the log. Deep induction sonde error was poorly set and curve pegs at 2000 ohm-m, so medium induction should be used instead.

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FIGURE CH3.02: Density neutron PE log on the dolomite reef. Limestone scale log (left) shows reduced separation in top 15 – 20 meters, suggesting limy dolomite, but PE confirms pure dolomite, so it must be gas. Dolomite scale presentation shows gas crossover at top of reef, minor crossover for 42 API oil, and no crossover in water zone (so logs are properly calibrated for dolomite).The gas-oil contact is not perfectly clear based on crossover. Test shows G/O below 2125 and residual oil in core suggests 2127 to -2130. A depth plot of the density neutron log on a dolomite scale helps point this out by creating the gas cross over effect. Beware of dolomite scales in a limestone rock – the crossover on the density neutron DOES NOT indicate gas in this situation. Some very expensive mistakes have been made by inappropriate use of dolomite scale logs. There is also a small amount of crossover on the dolomite scale log in the oil zone caused by the light gravity crude. Notice that there is no crossover in the water zone, demonstrating that the dolomite scaling is correct. Although not shown on any of the depth plots, the porosity from the sonic log would be very optimistic in some levels, caused by cycle skipping in fractured rock. In other levels, the porosity would be several percent too low due to the sonic's inability to see all vuggy porosity. These observations indicate how difficult it is to analyze older carbonate wells where the sonic may be the only porosity log. Fractures are indicated by skips on the sonic log and spikes on the density log, as well as low resistivity spikes on both the deep and shallow resistivity curves. These are also the most likely places for water break through. The lithology crossplots show the effect of vugs, fractures, and gas on the sonic log, as well as confirm the dolomite lithology. Some of the density spikes caused by hole breakout at fractures still show up on the final results. These could have been edited to reflect reservoir conditions instead of borehole effects Crain’s Petrophysical Pocket Pal

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Below are the well history and core data for this well. A detailed match to porosity from core is usually not possible due to heterogeneity of the reservoir and the difference in rock volume seen by logs compared to the core. A good match to average porosity and total pore volume can be achieved by adjusting the target matrix density in the computer program. A permeability match may be possible if pore geometry is uniform throughout the interval. Heterogeneity, fractures, and vuggy porosity usually prevent a reasonable permeability from log analysis.

WELL HISTORY Fossil Joffre 15-22-39-26W4 Twin Well in 10-22-39-26W4 KB Elev: 908.1 m Logs: DIL-SP, FDC-CNL-GR, BHCS-GR, GR (COMPL) Log depths in METERS Formation Tops 15-22 Name

meters

feet

Calmar

2012.5

6603.0

Nisku

2018.5

6622.7

Ireton

2058.0

6752.3

Leduc

2106.0

6909.8

Cooking Lake

2304.5

7561.1

Total Depth

2366.0

7762.8

Core Record 15-22 2150.0 – 2186.0 Not Analyzed 2110.0 – 2157.4 from 10-22 Twin Well Analyzed Completion Record 15-22 Size/Depth mm Surface Casing: 219.1 Production Casing: 139.7 Perfs: See Testing Record

meters 385.0 2365.3

inches 8.63 5.50

feet 1263.2 7760.5

Testing Record 15-22 DST #1 2120.0 – 2130.0 m Inflate Straddle VO: 1.0/2.0 SI: 28.0/27.0 min FP: 6550.0/6223.0 kPa SIP: 16410.0/16410.0 kPa HP: 23718.0/23063.0 kPa High permeability; No formation damage; Blow description: none given, closed chamber. Recovery: 188m clean condensate 192m mud. Perf #1 / Acid Squeeze 2138.5 – 2145.0, 2150.0 – 2155.0, 2158.0 – 2161.6 m Prod Test 2138.5 – 2161.6 m VO: 24.0/24.0 No Shut In, No Pressures Recovery: 447.2 m3 clean uncontaminated oil Perf #2 2107.5 – 2111.0 m Swab Test Recovery: 5.7 m3 Unknown recovery, Perfs Ineffective???

Perf #4 2171.5 – 2176.5, 2178.0 – 2179.0 Production Test No Pressures Gas 9600 m3/d (0.339 mmcf/d) Perf #5 2166.0 – 2170.0 m Production Test No Pressures “not set” Perf #6 2166.0 – 2174.6 m Production Test No Pressures Recovery: 52.6 m3 clean uncontaminated oil

0 .35

Core Porosity - fractional

Perf #3 2121.0 – 2125.0 m Production Test No Pressures Recovery: 13.5 m3 Unknown recovery; Gas 67 600 m3/d (2.387 mmcf/d)

10223926W4 Kmax vs Core Porosity 0 .30 0 .25 0 .20 0 .15 0 .10 0 .05 0 .00 0 .01

1

1 00

M a t r ix P e r m = 1 0 ^ ( P H I e * 1 8 . 5 - 2 . 0

NOTE: Bridge plugs between these tests were not reported. FIGURE CH3.05: Well history listing for Carbonate Reef Example, Crain’s Petrophysical Pocket Pal

1 00 00

H o r i z o n t a l P e r m e a b il it y - m D

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CUMMULATIVE PRODUCTION STATISTICS Cum’l Gas Oil Water Inj CO2 10-22 8.4 Bcf 3.6 MM bbl 1.4 MM bbl 15-22 1.9 Bcf 1.4 MM bbl 0.07 MM bbl 5.5 Bcf Log analysis production predictions in carbonates are difficult, and may be impossible, as in this case. Most computer software does not handle gas in dolomite very well and underestimate porosity and over estimate water saturation. The illustration on the next page show the difference between no gas correction and a reasonable gas correction. The math is given earlier in this Handbook in Section 5.05.

Figure CH3.03: Computed results over gas interval. Results on left underestimate porosity in dolomite with gas due to a conflict between gas crossover and dolomite separation. Results on the right uses the gas correction given in Section 5.04. Black dots show core porosity. Some more sophisticated programs can handle this problem, but only if you allow gas to be present.

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FIGURE CH3.04: Final petrophysical analysis of the dolomite reef. Black dots are core data., showing heterogeneous nature of the reservoir (and the difficulty in comparing the beer-can-sized core sample to a barrel-sized log reading).

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CORE ANALYSIS DATA FOR 10-22-39-26W4 10223926W4 S#

Top Base Len Kmax K90 Kvert Porosi GrDen BkDen Soil Swtr Lithology meters meters meter mD mD mD frac Kg/m3 Kg/m3 frac frac 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58

2122.00 2122.28 2122.64 2122.86 2123.05 2123.47 2123.67 2124.10 2124.53 2124.80 2125.18 2125.44 2125.70 2126.00 2126.21 2126.42 2126.75 2126.95 2127.19 2127.38 2127.70 2127.94 2128.09 2128.38 2128.79 2129.26 2129.76 2130.32 2130.83 2131.14 2131.60 2131.94 2132.15 2132.54

2122.28 2122.64 2122.86 2123.05 2123.47 2123.67 2124.10 2124.53 2124.80 2125.18 2125.44 2125.70 2126.00 2126.21 2126.42 2126.75 2126.95 2127.19 2127.38 2127.70 2127.94 2128.09 2128.38 2128.79 2129.26 2129.76 2130.32 2130.83 2131.14 2131.60 2131.94 2132.15 2132.54 2132.67

Arithmetic Averages

0.28 0.36 0.22 0.19 0.42 0.20 0.43 0.43 0.27 0.38 0.26 0.26 0.30 0.21 0.21 0.33 0.20 0.24 0.19 0.32 0.24 0.15 0.29 0.41 0.47 0.50 0.56 0.51 0.31 0.46 0.34 0.21 0.39 0.13

120.00 11.30 547.00 2110.0 5350.0 560.00 16.00 15.90 5.27 267.00 192.00 421.00 572.00 10000 2.49 55.60 82.20 196.00 8.35 1840.0 23.60 27.90 107.00 533.00 40.20 2340.0 1670.0 62.30 2110.0 226.00 37.50 90.40 30.80 81.90

50.70 5.64 82.00 2110.0 2880.0 166.00 11.30 14.20 3.36 113.00 130.00 95.50 572.00 10000 2.12 30.80 17.00 48.10 7.63 1700.0 20.50 21.00 8.50 338.00 11.30 1800.0 708.00 19.80 1770.0 20.90 16.30 36.40 16.60 48.10

28.80 8.23 92.20 2110.0 32.70 443.30 12.00 11.06 1.02 11.70 11.80 25.90 1282.0 5.81 0.81 2.12 1.88 0.44 0.06 0.21 0.23 0.96 0.07 102.00 5.19 99.70 532.00 6.16 698.00 6.76 5.62 7.00 1.92 88.90

0.101 0.064 0.105 0.147 0.146 0.148 0.074 0.104 0.048 0.129 0.079 0.071 0.129 0.116 0.070 0.097 0.144 0.133 0.118 0.103 0.117 0.153 0.130 0.075 0.068 0.097 0.122 0.086 0.142 0.075 0.075 0.062 0.073 0.129

2810 2830 2830 2810 2810 2790 2820 2840 2890 2830 2840 2830 2830 2830 2830 2840 2840 2840 2840 2830 2830 2830 2830 2840 2830 2820 2820 2810 2820 2830 2840 2830 2830 2840

2627 2713 2638 2544 2546 2525 2685 2649 2799 2594 2695 2700 2594 2618 2702 2662 2575 2595 2623 2642 2616 2550 2592 2702 2706 2643 2598 2654 2562 2693 2702 2717 2696 2603

0.001 0.001 0.106 0.000 0.087 0.080 0.001 0.000 0.000 0.001 0.113 0.001 0.001 0.001 0.000 0.053 0.043 0.062 0.077 0.047 0.001 0.108 0.000 0.000 0.046 0.068 0.055 0.000 0.000 0.121 0.118 0.204 0.261 0.180

0.412 0.182 0.212 0.103 0.174 0.353 0.247 0.205 0.133 0.290 0.271 0.410 0.560 0.273 0.250 0.191 0.072 0.198 0.196 0.207 0.182 0.432 0.285 0.504 0.130 0.370 0.398 0.427 0.534 0.338 0.037 0.082 0.104 0.072

0.36

875.1

672.8

165.8

0.104

2830

2640

0.054

0.260

DOL I VUG CARB VFRAC DOL I PPV LV VFRAC DOL I VUG STY VFRAC DOL I PPV SV CARB DOL I VUG CARB STY VFRAC DOL I MV LV CARB VFRAC DOL I VUG CARB VFRAC DOL I VUG DOL I PPV SV ANHY DOL I VUG DOL I VUG STY DOL I VUG STY VFRAC DOL I VUG DOL I VUG DOL I VUG DOL I VUG DOL I VUG DOL I VUG DOL I VUG DOL I VUG DOL I VUG FOSS DOL I VUG DOL I VUG DOL I PPV MV DOL I VUG STY VFRAC DOL I VUG DOL I VUG CARB VFRAC DOL I VUG CARB VFRAC DOL I VUG CARB DOL I VUG DOL I VUG DOL I VUG DOL I PPV LV VFRAC DOL I PPV SV VFRAC

FIGURE CH3.05: Core data listing for Carbonate Reef Example – partial listing over gas-oil contact

15-22-39-26W4 Production History Normalized Rate - Bbbl/d (mcf/d)

2 50 0 2 00 0

Notice the high permeability streaks caused by fractures. Lower values show matrix permeability. Vuggy porosity is mentioned often, suggesting that it would be difficult to obtain a good porosity analysis from the sonic log. Use the Oil Saturation column (Soil) to pick the gas-oil contact. Compare to the crossover on the dolomite scale density neutron log. On the core porosity versus permeability plot, the data scatter is large due to natural fractures. The high porosity – low perm data points represent matrix permeability. The lower porosity – high perm points indicate the fracture permeability.

1 50 0 1 00 0 5 00 0 1

4

7

10

YEAR S

A solvent flood was begun after Year 3 to maintain pressure in the twin well, then production was resumed during Year 6. IPR was 2100 bbl/day but declined very steeply and continued to decline on the same trend after the solvent flood was terminated. We also need the production graph for the twin well to see the overall performance.

24 Pages Omitted  Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

Page 50 of 54

CRAIN’S PETROPHYSICAL POCKET PAL EXERCISE #1: Shaly Sand – Thick Beds – Log Depths in Meters Page 1 of 4 Your Name_____________ VISUAL ANALYSIS Draw shale and clean lines on SP and gamma ray logs. Estimate approximate shale volume and porosity for these 3 layers by observation of the logs: Shale Volume (Vsh) A: _____ B: _____ C: _____ Effective Porosity (PHIe) A: _____ B: _____ C: _____ Based on the resistivity log, which layer is most likely to produce water? ________ Based on the approximation that water saturation (Sw) = 0.0400 / PHIe in clean hydrocarbon bearing zones, 0.0600 / PHIe in shaly hydrocarbon zones, estimate Sw in all zones: Water Saturation (Sw) A: _____ B: _____ C: _____

SHALE PROPERTIES:

Gamma Ray clean line (GR0) Gamma Ray shale line (GR100) SP clean line (SP0) SP shale line (SP100) Density shale line (PHIDSH) Neutron shale line (PHINSH) Sonic shale line (DTCSH) Resistivity shale line (RSH) Resistivity of Water Zone (R0)

__________ ___________ _________ _________ _________ _________ ___NA___ _________ _________

LOG DATA VALUES FOR LAYERS NOTE: Convert depths to feet by multiplying meters by 3.281. Work this exercise in feet, barrels, and psi.

Layer Top Layer Bottom Deep Resistivity Neutron Porosity Density Porosity Sonic Travel Time Gamma Ray Spontaneous Potential Photo Electric Effect Caliper

RESD PHIN PHID DTC GR SP PE CAL

A: Sh Sd

B: Oil

C: Water

________ ________ ________ ________ ________ __NA____ ________ ________ ________ ________

______ ______ ______ ______ ______ __NA__ ______ ______ ______ ______

_______ _______ _______ _______ _______ __NA___ _______ _______ _______ _______

COMMENTS: This exercise illustrates a straight forward clean sand with oil over water and a shaly sand with oil. The standard visual and quantitative rules apply. Water resistivity is calculated from the water zone. These are thick beds for porosity analysis but the clean oil and water zones are thin beds as far as the conventional induction log is concerned. Extending the conventional analysis to include reserves and productivity gives a better understanding of the relative and absolute quality of the two oil zones. This case history is described starting on page 92.

THIS IS A SAMPLE – FOR ILLUSTRATION PURPOSES ONLY The complete manual is 193 pages, available at www.spec2000.net/00-orders.htm Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

Page 51 of 54

CRAIN’S PETROPHYSICAL POCKET PAL EXERCISE #1: Shaly Sand – Thick Beds – Log Depths in Meters Page 2 of 4 Your Name_____________ A: Sh-Sd

B: Oil C: Water

Shale Volume

1: Vshg = (GR - GR0) / (GR100 - GR0) 2: Vshs = (SP - SP0) / (SP100 - SP0) 3: Vshx = (PHIN - PHID) / (PHINSH - PHIDSH) 4: Vsh = Minimum of above in each zone Porosity 1: PHIdc = PHID – (Vsh * PHIDSH) 2: PHInc = PHIN – (Vsh * PHINSH) 3: PHIe = PHIxdn = (PHInc + PHIdc) / 2

_____ _____ _____ _____ _____ _____ _____ _____ _____ _____ ____ ______

_____ _____ _____ _____ _____ _____ _____ _____ _____

Water Resistivity from Water Zone Use A = 0.62, M = 2.15, N = 2.00 for Sandstone 1: PHIwtr = (PHID(wtr zone) + PHIN(wtr zone)) / 2 _______ 2: RW@FT = (PHIwtr ^ M) * R0 / A _______ Water Saturation 1: PHIt = (PHID + PHIN) / 2 2: Rwa = (PHIt ^ M) * RESD / A 3: Sw = SWa = (RW@FT / Rwa) ^ (1 / N)

_____ _____ _____ _____ _____ _____ _____ _____ _____

Irreducible Water Saturation 1: KBUCKL = PHIe(oil zone) * Sw(oil zone) _________ 2: SWbuckl = KBUCKL / PHIe / (1 – Vsh) 3: SWir = Min (1, Sw, SWbuckl)

____ ____ _____ ____ ____ _____

Permeability – Assume CPERM = 65 000, DPERM = 6.0, EPERM = 2.0 1: Perm = PERMw = CPERM * (PHIe ^ DPERM) / (SWir ^ EPERM)

_____ _____ _____

Reserves – Assume Bo = 1.25, RF = 0.40. 1: THICK = Layer Base – Layer Top 2: PV = PhiH = PHIe * THICK 3: HPV = HydH = PHIe * (1 – Sw) * THICK 4: Kh = Perm * THICK 5: NetH = THICK 6: Roil = RF * KV3 * HPV * AREA / Bo

_____ _____ _____ _____ _____ _____ _____ ______ _____ _____ _____ _____ _____ _____ _____ _____ _____ _Wtr_

KV3 = 7758, AREA = 160 acres, Roil in stock tank barrels. Productivity – assume (PF – PS) = 1000 psia, VISO = 2.0 cp 1: Qo = KV1 * Kh * (PF – PS) / VISO

_____ _____ _Wtr_

KV1 = 0.0001, Depth in feet, Qo in bbl/day.

Show units of measurement for permeability, reserves, and productivity.

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

Page 52 of 54

CRAIN’S PETROPHYSICAL POCKET PAL EXERCISE #1: Shaly Sand – Thick Beds – Log Depths in Meters Page 3 of 4 Your Name_____________

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

Page 53 of 54

CRAIN’S PETROPHYSICAL POCKET PAL EXERCISE #1: Shaly Sand – Thick Beds – Log Depths in Meters Page 4 of 4 SANDSTONE SCALE LOG Your Name_____________

42 Pages Omitted 

Crain’s Petrophysical Pocket Pal

Copyright 1978 – 2012 E. R. Crain, P.Eng.

Page 54 of 54