Energy and Mineral Resources GEOL...

Energy and Mineral Resources GEOL 2570

Course Manual

2008 Printing

Copyright © 1995 Addendum incorporated in 1998. Revised 2002. All rights reserved. No part of the material protected by this copyright may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or otherwise without the prior written permission from the copyright owner.

University of Manitoba, Distance and Online Education

Acknowledgments

Content specialist: William M. Last, Ph.D., P. Geo. Department of Geological Sciences Faculty of Science and Faculty of Environment University of Manitoba

Bill Last was born in Illinois and immigrated to Canada shortly after receiving his B.Sc. degree in Geology from the University of Wisconsin in 1971. After working four years as a petroleum exploration geologist with Shell Canada Ltd., he moved to Winnipeg where he completed his Ph.D. at the University of Manitoba. He worked as a research officer in the Tar Sands/Heavy Oil Division of the Alberta Geological Survey until 1980, when he joined the faculty at the University of Manitoba in the Department of Geological Sciences.

Professor Last’s main research interests are in the fields of sediment logy, petroleum geology, and environmental geology. With over 150 publications to his credit, he has maintained a long research involvement in western Canada. His research efforts in the area of energy resources are currently directed mainly at organic geochemistry and sediment logy of Cretaceous oil shale in western Canada and porosity genesis and development in Mesozoic oil reservoirs in Manitoba. He is editor-in-chief of Journal of Pale limnology; associate editor of Sedimentary Geology, International Journal of Salt Lake Research, and Prairie Forum and past associate editor of Bulletin of Canadian Petroleum Geology. He has written or edited six books on pale limnology and geolimnology and is the Series Co-Editor of the book series Developments in Paleoenvironmental Research. He teaches undergraduate courses in petroleum geology, environmental geology, well log analysis, sediment logy, energy resources, and basin analysis. His graduate course offerings include advanced sediment logy, petroleum geochemistry, and evaporate sediment logy and geochemistry.

Instructional designer: Cheryl McLean, Ph.D. Distance and Online Education University of Manitoba

Editor: James B. Hartman, Ph.D. Distance and Online Education University of Manitoba

Desktop publisher: Lorna Allard Distance and Online Education University of Manitoba

Table of Contents Introduction to the Course ....................................................................1

Course description.........................................................................1 Course goals ..................................................................................2 Course materials............................................................................3 Going online..................................................................................4 Course content...............................................................................4 Evaluation and grading .................................................................6

Your Course at a Glance .................................................................9

Module 1 Terminology and Basic Concepts...................................11

Unit 1 Energy Fundamentals .....................................................13 Study notes ..................................................................................14 Review questions ........................................................................21

Unit 2 Energy and Mineral Resources: Sources and Terminology..............................................................23

Study notes ..................................................................................24

Unit 3 Fundamentals of Energy and Mineral Crises ...............33 Study notes ..................................................................................34 Review questions ........................................................................39

Module 2 Energy Resources ............................................................41

Unit 4 Oil and Natural Gas: Introduction, History, and Geochemistry............................................................43

Study notes ..................................................................................44

Assignment 1...................................................................................51

Unit 5 Drilling Technology .........................................................53 Study notes ..................................................................................55 Review questions ........................................................................72

Unit 6 The Petroleum Source Rock ...........................................73 Study notes ..................................................................................74

Assignment 2...................................................................................79

Unit 7 Petroleum Migration and the Petroleum Reservoir Rock.................................................................81

Study notes ..................................................................................82

Unit 8 The Big Picture: The Sedimentary Basin and Basin Exploration Philosophy ........................................89

Study notes ..................................................................................90 Review question..........................................................................95

Assignment 3...................................................................................97

Unit 9 Coal and Oil Shales .........................................................99 Study notes ................................................................................100 Review questions ......................................................................109

Unit 10 Canada’s Energy Saviour: The Tar Sands and Heavy Oil ................................................................111

Study notes ................................................................................112 Review questions ......................................................................125

Assignment 4.................................................................................127

Module 3 Mineral Resources .........................................................129

Unit 11 Economic Geology, Iron, Alloy Metals, and Base Metals.....................................................................131

Review questions ......................................................................144

Unit 12 Light Metals and Nonmetallic Minerals......................145 Study notes ................................................................................145 Review questions ......................................................................150

Sample Answers Appendix ................................................................151

Sample Final Examination ................................................................155

Assignment Title Sheets .....................................................................159

Introduction to the Course

Course description The University of Manitoba Undergraduate Calendar describes this course as follows:

An introduction to the geological factors and processes responsible for the origin, concentration and distribution of fuels, geothermal resources, metallic and nonmetallic minerals. Available by correspondence only. Not to be held with the former 007.255 or 007.256. Not for credit in a Major or Honours program in Geological Sciences. Prerequisite: one of GEOL 1340 or GEOL 1440 (or the former 007.123, 007.124, 007.132, 007.133, 007.134, or 007.144).

This course will provide an overview of the salient aspects of geology as it relates to the origin, exploration, and exploitation of energy and mineral resources. The topics of energy and mineral use, energy resources, and mineral resources are and will continue to be very important society concerns for most of this century. The degree of constraint exercised today by energy and mineral consumers, the actions taken now to explore and exploit new deposits of conventional energy and mineral resources, and the present-day rate of development and acceptance of unconventional resources will all be critical in dictating our future.

The energy resources that humans can adapt for their own use are those that result directly from the sun (solar), from the moon (lunar/tidal), from the earth (nuclear and geothermal), and indirectly from the sun in the form of fossil fuels, wind, water, or biota. In all cases the geological sciences are the key point of departure for the research, exploration, evaluation, and exploitation of these energy sources. The same is true of virtually every naturally occurring mineral resource.

The purpose of this course is to introduce you to and outline the basic geological factors that help to control the exploration, discovery, and exploitation of selected energy and mineral resources. Clearly in a one-term (13 weeks) introductory course such as this, we cannot hope to cover or even mention all of the many interesting facets of energy and mineral resources. In fact, most of this term you will examine our energy resources, with specific emphasis on the non-renewable sources—oil, natural gas, and coal. An important aspect of energy and mineral resources in the twenty-first century, namely the topics of environmental constraints and related concerns about exploration and exploitation, will not be covered significantly in this course, although considerable insight into these subjects is provided in your textbook. If you are interested in the geoenvironmental aspects of mineral and energy development, consider taking the sister course GEOL 2390, Environmental Geology.

Energy and Mineral Resources GEOL 2570 1

Course goals Why are we interested in energy and mineral resources? It is clear that the world community is dependent on a cheap and readily available supply of energy and certain minerals. Even as nonspecialists, we must be aware of how and where energy and minerals resources occur and how best to use all possible resources.

This course has three main goals:

• To provide you with a better understanding of the role that modern geoscience and geoscientists play in discovering and exploiting energy and mineral resources.

• To examine the details of the major types of energy resources and discuss how the most common types of conventional and unconventional energy resources were formed, how they are explored for, and how they are commercially extracted.

• To give you a sufficient understanding of the important decisions that must be made very soon by society. As we near the end of the “petroleum era,” we (and our political leaders) will have to be much better informed about the technological options available in order to make acceptable social and political choices. Hard decisions are looming in the realm of mineral and, in particular, energy resources. These decisions will be made either by default and knee-jerk reactions or in full knowledge of the issues and limitations involved; the latter approach will depend on the level of our understanding.

As you systematically progress through the course material during the next thirteen weeks, you will:

• discover the relationship between resource geology and other branches of geology, such as sediment logy, stratigraphy, geochemistry, and structural geology, as well as other physical, chemical, biological, and social sciences;

• demonstrate how near to the end of the “petroleum era” we are in terms of energy resources;

• describe the geopolitics and repercussions of exponential growth in resource demand;

• identify the differences among conventional and unconventional energy and mineral resources;

• identify the differences between a resource, a resource base, and a reserve;

• describe the genesis of the major types of conventional energy resources and how these conventional resources are genetically related to many types of unconventional resources;

• outline how our understanding of basic geological principles and processes can assist in modern exploration and development of a prospect;

• explore the resource setting of Canada’s mature and frontier regions;

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• locate, on a regional and global basis, areas that appear to be most favourable to future conventional energy exploration and development;

• identify the major types of metallic and non-metallic mineral deposits;

• describe how well-explored and well-developed basins, such as those of western Canada and United States, can be further exploited using modern exploration and exploitation techniques;

• outline the genesis and geological setting of Canada’s immense reserves of tar sands;

• show how the source characteristics of conventional and unconventional fossil fuels help control the resulting physical and chemical characteristics of the fuels;

• discover the complex relationship between organic and inorganic sedimentation, chemical setting of the depositional environment, the biological characteristics of the overlying water mass, the post depositional burial history of the sediment, and the resulting coal type and rank; and

• locate, both globally and regionally, classical mineral exploitation areas.

Course materials Required texts The following required materials are available for purchase from the University of Manitoba Book Store. Please order your materials immediately, if you have not already done so. See your Distance and Online Education Student Handbook for instructions on how to order your materials.

Craig, J. R., Vaughan, D. J. and Skinner, B. J. (2001). Resources of the Earth: Origin, use, and environmental impact. Upper Saddle River, NJ: Prentice Hall.

Petroleum Communication Foundation. (2004). Our Petroleum Challenge: Exploring Canada's Oil and Gas Industry. 7th ed. Petroleum Communication Foundation.

The Distance and Online Education Student Handbook The Distance and Online Education Student Handbook is located online in each course site and on the Distance and Online Education website. You can bookmark the site for easy access at your convenience. If you need to order a printed copy, please consult your Distance and Online Education Guide staff directory for the general inquiries contact information.

Accessing both the Handbook and the DE Guide throughout the year provides you with detailed information regarding the management/administrative aspects of this distance education course. The Handbook tells you how to access the following:

• Your instructor;


• Writing your final exam at a location other than the University of Manitoba campus;

• Distance and Online Education Student Services; • Using technology (online access, communication tools); • The University of Manitoba Libraries; • Information on ordering your course materials through the University of

Manitoba Book Store; and • Information on accessing your grades and submitting assignments online.

Going online Interacting with other students Take advantage of communication tools in the course website. The tools include e-mail, discussion, and chat. Post your questions or comments in the discussion area. Activities such as these provide other students with an opportunity to interact with you. Consider creating online study groups.

Interacting with your instructor Questions? Concerns? Discussion? Your instructor is prepared to assist you. Do not hesitate to address any concerns regarding the course and assignments directly with your instructor. Check your instructor’s contact information to determine how best to communicate—not all instructors communicate online.

Using the libraries Additional readings enrich your learning experience and your understanding of your course topics. Textbooks and course materials often contain suggested reading lists, and you can search any library, using online library search tools, to find these and other related materials.

Course content Not so long ago, most people thought that the supply of energy and the availability of minerals were inexhaustible. Oil and gas were so cheap and plentiful that no one was concerned if these products were wasted. Even as recently as a decade ago, the reserves of coal in North America were considered to be so great that they would supply our demand for the next 300 years. This complacency about energy supplies in particular was, of course, abruptly and dramatically shattered with the “energy crises” of the 1970s. A world that had become used to cheap and plentiful supplies of oil was suddenly faced with the combination of a limited supply and a much higher cost for this now essential commodity.

You will spend most of your time in this course exploring and discovering the various geological factors that interact to form viable and commercial energy and mineral resources. Obviously no single, one-term course can fully cover the entire range of energy and mineral resources. The topics you will cover

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represent an overview of selected concepts and principles and will deal mainly with components of conventional and unconventional energy resources. As you read these notes and the textbook, and work your way through the practice exercises and review questions, you will find yourself sharpening your critical faculties. One of the primary goals of this course (and, indeed, any university course you take) is to allow you to distinguish the overstated and the untrue information that is often presented as fact in popular press from accurate information and reasonable interpretations.

Just a word of advice concerning the use of the course materials: these course notes are intended to supplement your textbook reading. Therefore, you should spend as much time (and probably more) reading and understanding the textbook assignments (both books) as you do on these course notes. There are many aspects of the course, particularly in the mineral resources unit, that are not covered in detail in these notes but are discussed at length in the textbook. Conversely, as with most textbooks, the Craig et al. volume deals with a number of topics and areas that we will not address in this course. This is particularly true of the very important areas of environmental impact of resource exploitation (e.g., chapter 4 in Craig et al.), and water and soil resources (chapters 11 and 12 in Craig et al.). Finally, you should have successfully completed one of the introductory “first-year” courses in geological sciences (e.g., Physical and Historical Geology, Earth and Planetary Science, Dynamic Earth, etc.). You will find that you will frequently be using the concepts, information, and techniques learned in the introductory course to better grasp the fundamentals of energy and mineral resources. The introductory chapters in Craig et al. will be useful in helping you review these important concepts from earlier Earth sciences courses.

This course is organized in such a way as to familiarize you first with the basic concepts of energy and mineral resources and reserve terminology, then with the geology of conventional energy resources, followed by unconventional sources, and finally mineral resources. Within this broad framework, specific sections will deal with the following topics (in order of coverage):

Module 1 Terminology and Basic Concepts Unit 1 Energy Fundamentals Unit 2 Energy and Mineral Resources: Sources and Terminology Unit 3 Fundamentals of Energy and Mineral Crises

Module 2 Energy Resources Unit 4 Oil and Natural Gas: Introduction, History, and Geochemistry Unit 5 Drilling Technology Unit 6 The Petroleum Source Rock Unit 7 Petroleum Migration and the Petroleum Reservoir Rock Unit 8 The Big Picture: The Sedimentary Basin and Basin Exploration

Philosophy Unit 9 Coal and Oil Shales Unit 10 Canada’s Energy Saviour: The Tar Sands and Heavy Oil


Module 3 Mineral Resources Unit 11 Economic Geology, Iron, Alloy Metals, and Base Metals Unit 12 Light Metals and Non-metallic Minerals

Evaluation and grading You should acquaint yourself with the University’s policy on plagiarism, cheating, and examination impersonation as detailed in the General Academic Regulations and Policy section of the University of Manitoba Undergraduate Calendar. Note: These policies are also located in your Distance and Online Education Student Handbook or you may refer to Student Affairs at http://www.umanitoba.ca/student.

Assignments Four assignments and/or problems sets will be completed and evaluated during the term. Each assignment is worth 10% of your final mark. There is also a two-hour final exam worth 60% of your final mark. The exam will be written during the exam period. The format of this final examination will be provided to you about midway through the course.

Distribution of marks Item Percentage

1 2 3 4

Final exam Total

10% 10% 10% 10%

___60% 100%

Assignment due dates

Assignment Sept. - Dec. Jan. - Apr. May - Aug.

Assignment 1 Sept. 30 Jan. 30 May 30 Assignment 2 Oct. 15 Feb. 14 June 15 Assignment 3 Oct. 30 Feb. 28 June 30 Assignment 4 Nov. 12 Mar. 12 July 12

If you need to write the final exam at a location other than the University of Manitoba main campus, you must complete an application. Please consult your Distance and Online Education Student Handbook for directions.

Note: If the assignment due date falls on a Saturday, Sunday, or statutory holiday, it will be due on the next working day. If the assignment due date falls during the Mid-term Break in February, it will be due on the Monday following the Mid-term Break. If you are unable to submit an assignment on time, contact your instructor well in advance of the due date, for we cannot guarantee that the instructor will accept late assignments.

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Assignment title sheets are located at the back of the manual.

A word of caution about the assignments and the final examination Some students find that they do very well on the assignments, but they do not do nearly as well on the final examination. While your grades on the assignments will give you some idea of how well you are mastering the material, they may not indicate how well you will do on the examination, because the examination is written under very different circumstances. Because the assignments are open-book, they do not require the amount of memorization that a closed-book examination requires nor are they limited to a specific time period. Some students have told us that, based on the high marks they received on the assignments, they were overconfident and underestimated the time and effort needed to prepare for the final examination.

Please keep all this in mind as you prepare for the examination. If your course has a sample exam or practice questions, use them to practice for the examination by setting a time limit and not having any books available. Pay careful attention to the description of the type of questions that will be on your final examination. Preparing for multiple-choice questions involves a different type of studying than preparing for essay questions. Do not underestimate the stress involved in writing a time-limited examination.

Grading scale Letter grade Percentage range Description

A+ 90-100 Exceptional A 80-89 Excellent B+ 75-79 Very good B 70-74 Good C+ 65-69 Satisfactory C 60-64 Adequate D 50-59 Marginal F 49 and below Failure

Please note: All final grades are subject to departmental review.


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Notes

Your Course at a Glance our Course at a Glance Week 1 Week 1

Topic: Energy Fundamentals Topic: Energy Fundamentals If you live outside Winnipeg and your course has a final examination, please submit the “Application Form for Examination at a Location Other than the University of Manitoba Campus” immediately. It is found in the Forms Appendix in your Distance and Online Education Student Handbook.

If you live outside Winnipeg and your course has a final examination, please submit the “Application Form for Examination at a Location Other than the University of Manitoba Campus” immediately. It is found in the Forms Appendix in your Distance and Online Education Student Handbook. Review the requirements for all assignments. Review the requirements for all assignments.

Week 2 Week 2 Topic: Energy and Mineral Resources: Sources and Terminology Topic: Energy and Mineral Resources: Sources and Terminology

Week 3 Week 3 Topic: Fundamentals of Energy and Mineral Crises Topic: Fundamentals of Energy and Mineral Crises

Week 4 Topic: Oil and Natural gas: Introduction, History, and Geochemistry

Assignment 1 due

Week 5 Topic: Drilling Technology

Week 6 Topic: The Petroleum Source Rock

Assignment 2 due

Energy and M

ineral Resources G

EO

L 2570 9

Week 7 Topic: Petroleum Migration and the Petroleum Reservoir Rock

Week 8 Topic: The Big Picture: The Sedimentary Basin and Basin Exploration Philosophy

Assignment 3 due

Week 9 Topic: Coal and Oil Shales

Week 10 Topic: Canada’s Energy Saviour: Tar Sands and Heavy Oil

Assignment 4 due

Week 11 Topic: Economic Geology, Iron, Alloy Metals, and Base Metals

Week 12 Topic: Light Metals and Non-metallic, Mineral Resources

Week 13 Topic: Light Metals and Non-metallic, Mineral Resources (continued)

Important! Complete and send in the course evaluation.

Notes

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Module 1 Terminology and Basic Concepts


Notes

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Unit 1 Energy Fundamentals

Topics Introduction and communication Work Energy Power

Introduction To begin we will review the physical (and chemical) basics of energy. Energy cannot be discussed without first considering what it is physically. Sources of energy are many, and a basic knowledge of elementary physics is necessary to understand how these various and multiple sources of energy are tapped for use by society.

Learning objectives Definitions are crucial for understanding energy. Much of this section is a review of basic physics, and a summary of the relationships between work, power, and energy. There should be little new material presented here, but it will help refresh your memory about basic physical science concepts regarding energy and the related aspects of work and power.

By the end of this unit you should be able to: • discuss why communication with physical scientists is important; • define “force”; • relate force, distance, and work; • calculate the amount of work done if given the amount of force and the

distance and direction the force is applied; • summarize the various units of work, force, and distance; • define “energy”; • discuss the various types of energy; • identify and be able to convert the various types of units of energy measurement; • compare and contrast the energy level of different common fuels; • define “power” and describe the difference between power and energy; and • discuss the fuel requirements of various types of power generating facilities.


Learning activities 1. If you live outside Winnipeg and your course has a final examination, please

submit the “Application Form for Examination at a Location Other than the University of Manitoba Campus” immediately. It is found in the Forms Appendix in your Distance and Online Education Student Handbook.

2. Read the study notes.

3. Answer the review questions.

Study notes Key terms conservation of energy energy force chemical energy electrical energy joule kinetic energy MKS system mechanical energy nuclear energy power radiant energy thermal energy vector quantity work

Introduction and communication Most of us have some intuitive ideas about what energy is and where it comes from. Qualitatively we understand that today’s world largely runs on oil, gas, and coal and that supplying energy in relatively large amounts is necessary for our everyday living. But the language of energy (and mineral) resources is a speciality language, often filled with jargon and technical notation that, to the lay person, seems unduly complex. However, an understanding of just a few of these technological terms and concepts will enable us to communicate better with energy and mineral resource scientists and to read the appropriate scientific literature.

In the world of energy resources, many problems are encountered in communications between scientists and the public. Many times, these problems are the direct result of laziness on the part of the scientist in assuming that everyone has a detailed understanding of the technological jargon; other times miscommunication results from the fact that there can be different definitions for the same words.

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Unit systems and conversions Two systems of units are in general use within the energy and mineral resources industries. They are the old British system of units, and the International System (or SI, for Système Internationale). SI is now the standard system in most countries with the notable exception the United States. However, because the United States plays such a dominant role in resource exploration and exploitation, it is important that we know both systems and are fluent in both (or at least are able to readily convert from one to another). In most places in these notes SI units are given; similarly, your book Our Petroleum Challenge is mainly “metric.” Your other text (Resources of the Earth), however, is mixed—many of the data are given in, for example, feet, barrels, cubic feet, tons, etc., although the authors do try to give SI equivalents.

As we all know SI units are much easier (once you get to know them). Plus, the energy and mineral business is international. Chances are that should you pursue a career in either of these industries, you will very likely have an international assignment, which will require familiarity with SI.

The SI system has seven basic units (table 1.1), the first five of which are most important for our purposes. From these seven units we can derive other units, some of which have special names. A selection of those that are appropriate to our discussions on energy and mineral resources is given in table 1.2.

The names of the multiples and submultiples of the units are formed by the prefixes given in table 1.3. There are several basic rules we should always observe:

• The names of the units, when spelled out in full, do not take a capital letter. The unit symbols (abbreviations of the units), however, are often named in honour of a scientist and therefore do take a capital letter. Thus, we have newton, but the abbreviation is ‘‘N.’’ This distinction is important; k is kilo but K is degree kelvin. The kilometer is km, not Km (or KM or kM).

• Unit symbols are always given in the singular: 3 km, not 3 kms.

• The symbol for second is s, not sec. The abbreviation of secant is sec.

• There is no period after the symbol (except, of course, at the end of a sentence). In typing, it is best to leave a space between quantity and unit symbol.

• The symbol for gram is g, not gm or gms.

• In SI there is never any confusion between mass and force (or weight). Mass—and only mass—is measured in kilograms. Force—and only force—is measured in newtons. (Some of the old metric systems allowed the use of kilogram for force, and the French still inflate their tires to x kg /cm2.)

• Unit symbols involving a ratio may be written, for example, either as m/s or as ms-1, either as N /m or as N m-2. Indeed, some organizations insist on the latter form.


A selection of conversion factors for the British to the International System is given in both of your textbooks.

Table 1.1 Basic SI units

Quantity Name of unit Unit symbol

Length meter (metre) m Mass kilogram kg Time second s Amount of substance Mole mol Thermodynamic temperature kelvin K Luminous intensity candela cd Electric current ampere A

Table 1.2 Energy and mineral resources units

Quantity Name of unit Unit symbol

Area square meter m2 Volume cubic meter m3 Density kilogram per

cubic meter kg /m3

Speed meter per second rn/s m/s2 Acceleration meter per

second2 N (kg m/s2) Force newton Pa(N/m2) Pressure pascal

Work, energy, quantity of heat

joule J (N m)

Table 1.3 Multiples and submultiples

Factor by which unit is multiplied

Prefix Symbol

1012 tera T 109 giga G 106 mega M 103 kilo k 102 heco h 10 deca da 10-1 deci d 10-2 centi c 10-3 milli m 10-6 micro μ 10-9 nano n 10-12 pico p

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Work We frequently use the term work in everyday conversation: “Reading these notes requires a great deal of work.” Here the term is generally understood to mean toil or labour. However, if we were discussing work with a physical scientist, we would need to define the term more precisely. If you were to pick up your notebook and carry it over to a more comfortable chair across the room, clearly physical work is being done. Gravity is pulling the notebook downward, so when you lift the notebook up you are doing work against the gravitational force. Similarly work is done when you overcome inertia and start (and stop) your walk over to the more comfortable chair. Interestingly, however, if we consider only the part during which you are walking at a steady pace on the level floor toward the more comfortable chair, no work is done in a technical sense. Conversely, suppose that instead of lifting the notebook and carrying it, you push it across the rough, carpeted floor. Work is still being done. In this case you are not working against gravity —the notebook is at the same height throughout the journey—but rather against the frictional force that exists between the moving notebook and the floor.

Thus, an important component of the technical definition of work is that of force. Again, we readily recognize this term and intuitively realize that a force is a push or a pull: to force someone to do something implies that you change his or her state of rest into a state of motion (or vice versa). Thus, in a technical sense, an existing system will continue to exist as it currently is unless an outside agent affects the components of that system. Such an outside agent is known as a force. Because there is always a direction associated with a force, the force is referred to as a vector quantity.

Finally, the concept of distance is important to our technical definition of work. The amount of work done in any situation depends not only how much force was exerted but also on how far the object moved.

We can now define work: the work done by any force is the product of the force and the distance moved in the direction of the force or simply:

W = F x d

where F is the applied force measured in units called newtons, d is distance measured in meters, and W is work and is measured in units of joules. The unit of newton is derived from Newton’s law of dynamics, which says that force is equal to mass times acceleration or, in other words, the force necessary to give a body of mass of 1 kilogram an acceleration of 1 meter per second2 (1 m/s2) is 1 kg m/s2.

In our notebook example above, in picking the notebook straight up, you are moving it in the direction opposite to the gravitational force on the notebook, which is defined as its weight. Therefore the amount of work done on the notebook is equal to its weight times the change in height. As soon as you have begun to walk across the room to the more comfortable chair, no work is done on the book because the distance moved in the direction of the force (gravity) is zero.


Energy What does all this have to do with energy? When the notebook is moved against the force of gravity, work is done and energy is expended in the process. Thus, in our conversations with physical scientists, energy is the capacity to do work. In fact, work is just one form of energy. As long as something can do work, it is able to use energy.

Remember the work you did in lifting up your notebook against the gravitational force; because of this input of work, the book has energy associated with its position above the surface of the ground. This energy is termed gravitational potential energy. Indeed, if the notebook were dropped, this energy has the potential to change into other forms and, in turn, to do work. In dropping the book, the potential energy is converted into energy of motion, or kinetic energy. As the notebook hits the floor, its energy is transformed into energy of deformation. Ultimately, this energy of deformation is converted to sound energy and internal energy. The point here is that any sort of energy can be transformed into any other sort. Thus, the original work became gravitational potential energy, which became kinetic energy, which then transformed into deformational energy, and finally into sound and internal energy.

Although it is important to appreciate this ability to convert readily between different forms of energy, we must remember that energy is always conserved; it may be converted to another form, but it is never lost. Every process in nature obeys this basic principle of energy conservation. If we were to add up all of the energy in its various forms that an isolated system possesses before an event or process takes place and then do the same afterward, we would always find an exact balance. The problem then becomes one of being able to recognize and measure all the ways in which energy can appear.

Mechanical energy is the kind of energy used by machines. The category of mechanical energy lumps together kinetic energy and potential energy. Examples of mechanical energy are the pendulum, a jacked-up car, and similar devices. Other forms of mechanical energy more relative to the geosciences include landslides, avalanches, and rain. Similarly earthquakes and tsunamis, which you learned about in your first-year geology course, are also forms of mechanical energy. Earthquakes, which release stored rock strain energy along fractures, exhibit large-scale land motion.

Nuclear energy becomes available when unstable nuclei spontaneously change by throwing off particles. The decay of the neutron into a proton, an electron, and an antineutrino is an example of the conversion of nuclear mass energy into kinetic energy. We will discuss this type of energy later in the course.

Thermal energy is energy internal to the body, due to motion of the atoms making up the body. Hot springs, such as those found in Banff and Yoho National Parks in western Canada, are of high temperature because of the water’s contact with hot rock making up the basement of the continent. Probably our most impressive examples of thermal energy are volcanoes.

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Electrical energy is energy stored in the back-and-forth motion of electrons in electric utility lines. In nature, lightning involves the transformation of this electrical energy into heat energy and light energy.

Chemical energy is energy that has been stored in chemical form, such as in fossil fuels or as energy stored in car batteries. Gasoline is simply a chemical that, when combined with oxygen and a little heat, will release a great amount of heat stored in the chemical structure of the compound. We will be discussing many other such chemicals including methane and other natural gases.

Radiant energy, or electromagnetic energy, is the energy carried by light. It is this energy that makes the chemical storage of photosynthesis possible. In fact this energy is one of the most important types of energy from a geological perspective; photosynthetic organisms basically convert this radiant energy into chemical energy, which can be stored for geologically long periods of time.

Because there are so many different forms of energy, it has been difficult to form any kind of consensus on how to measure energy and what types of units should be used. You have no doubt heard of one of the most common units, the Btu or the British thermal unit. This is defined as the amount of heat required to raise the temperature of one pound of water 1.0o F. This is the equivalent to 778 foot-pounds in the old English unit system. Remember that, since work is force times distance, the English system with distances measured in feet and force in pounds provides units of work in foot-pounds.

In SI, the unit of length is the meter. The unit of area is the square meter or, in some cases, the hectare (104 m2). The unit of volume is the cubic meter, or, for a liquid, the litre, 10-3 m3. The litre is also 103 cm3. As we outlined above, the force applied to an object, its mass times its acceleration, has these appropriate units: Speed has units m/s, so acceleration has units (m/s)/s or m/s2. The mass has units of kg, so the force has units kg m/s2, or N. In SI the unit of work or energy is the unit of force times the unit for distance (N m or J).

The range of energies in nature is very large. For example, the energy involved in dropping your notebook would be about 10-2 J, whereas a rifle bullet has about 4 orders of magnitude more energy or about 104 J. At the other end of the scale, the amount of energy involved in a single moderate-sized earthquake in California is about 1020 J and the amount of energy released by the sun in one year is 1035 J.

Although the joule is one of the most common energy units, you will frequently hear many other units used and referred to in your conversations with energy scientists. The following will help you convert between the various units:

1 Btu = 0.252 kilocalories = 252 cal 1 Btu = 778 ft-lb = 1055 J 1 J = 0.734 ft-lb = 0.239 cal 1 ft-lb = 1.362 J 1 cal = 4186 J = 3.97 Btu


Finally, you will also be faced with attempts by scientists (and politicians!) to discuss the energy content of various fuels. Table 1.4 will help you understand a broad general conversion between the various types of energy sources.

Table 1.4 Conversion table for energy sources

Fuel Amount of Fuel

Energy: Joules

Energy: Btu

Oil 1 barrel 6.1 x 109 5.8 x 106 Natural gas 1 ft3 1.0 x 109 0.95 x 103 Coal 1 ton 2.8 x 1010 2.7 x 107 Wood 1 ton 1.0 x 1010 0.95 x 107 Dynamite 1 ton 4.4 x 109 4.2 x 106 Gasoline 1 gallon 1.3 x 108 1.2 x 105 Uranium 1 gram 8.2 x 1010 7.8 x 107 Deuterium 1 gram 2.4 x 1011 2.3 x 108

Power So far we have been discussing work and energy. The final topic is power. Suppose that you are studying with a friend and both of you decide to take your notebooks and move to more comfortable chairs across the room. For the sake of discussion, suppose that an equal amount of work is required, but you decide to undertake this task much quicker than your friend. Clearly you will have to convert body chemical energy into work at a more rapid rate than your slower-moving colleague. Thus, it obviously matters a great deal not only how much work is done, but how fast the work is done. Power is the rate at which work is done or energy is used and can be expressed simply as:

P = work/time

As discussed above, work is measured in joules, and if time is measured in seconds, the units of power become joule/second or J/s. This unit is given the special name watt (W):

1 J/s = 1 W.

For larger amounts of power, we use the more familiar terms kilowatt (1,000 watts) and megawatt (1,000,000 watts). An old, but still frequently used unit of power, is the horsepower (hp). The conversion between hp and W is:

1 hp = 742 W.

As with energy, power values show a great range. A pacemaker for a heart operates at about 10-4 W and typical small electronic home appliances are about 10-1 W. Automobiles frequently operate between 105 and 106 W, whereas a large coal or nuclear power station can generate 109 W (1,000 MW). Another term that you frequently see, for example, when you look at your electric bill, is

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the kilowatt-hour (kWh). Obviously, this is a measure of power times time. But, in rearranging the terms in the above equation for power:

P = w/t ⇒ P x t = w,

we see that the unit of kilowatt-hour is actually a unit of energy. So 1 kWh is equal to 1,000 W times 1 hour or 3.6 x 106 J. The important point here is to understand the distinction between power and energy (or work): units of kilowatts and units of kilowatt-hours refer to two different physical quantities.

Just as there are different “energy contents” of various material we commonly use for fuels to generate power, there are different fuel requirements for such things as power plants. For example, a power plant designed to generate 1,000 MW of electrical power, such as is common in western Canada, requires about 9,000 tons of coal per day if it is a coal-burning plant, or 40,000 barrels of oil per day if it uses oil, or 2.5 million cubic feet of natural gas if it burns gas, or about 3 kg of uranium if it is a nuclear plant.

Review questions 1. What physical quantity would be measured if the result were given in units

of kilowatt-days?

2. Classify the energy in the following systems according to basic energy forms: a. water in a storage tower b. sonic boom c. food d. boiling water e. moving automobile

3. What is the energy content of 1 ton of oil if a gallon of the oil has a mass of 7.5 pounds? Compare this with the value for coal.

4. Your boy/girl friend beats you at Indian wrestling and taunts you: “I’m simply more powerful than you are, you 90-pound weakling.” Would he/she be correct if you were using the technical definition of the term? Why?

5. Provide a sketch identifying and summarizing the major energy components starting from the nuclear energy of the sun to the mechanical energy of your electric lawnmower.

6. List the basic energy conversions involved in the sketch you made in 5 above.


Notes

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Unit 2 Energy and Mineral Resources: Sources and Terminology

Topics Historical use of energy and energy sources The earth system energy flux Resource and reserve terminology Resource base and reserve measurements

Introduction We will continue our introduction to energy and mineral resources by examining several more important basic concepts and terms in this section. It is very important to appreciate the historical aspect of energy use and the exploitation of various sources of energy through time. We will also quantitatively review the energy flux characteristics at the surface of the earth. Finally, we will examine the common terms and nomenclature used in resource and reserve work. The material learned here will be used throughout the rest of the course.

Learning objectives By the end of this unit you should be able to:

• trace and quantitatively outline the use of energy by humans through time;

• outline the major components of energy flux at the earth’s surface;

• discuss the importance of chlorophyll and the photosynthetic reaction;

• summarize the organic matter cycle;

• outline how material escapes the organic matter cycle;

• quantitatively describe the earth’s surface system energy flux;

• summarize why problems exist in the area of reserve and resource terminology;

• differentiate the various types of reserves and resources; and

• describe how coal, natural gas, and oil reserves are quantitatively presented.


Learning activities 1. Read the study notes.


3. Read pages 1–31 and page 447 in Resources of the Earth (note: pages 14–31 should be a review of material you learned in your first-year geoscience course.)

Study notes Key terms chlorophyll energy budget energy flux established reserve fund Source geothermal gradient income Source initial reserve nonrewable resource photosynthesis proved reserve recoverable reserve remain reserve renewable resource resource resource base reserve solar radiation constant

Historical use of energy and sources We learned in the last section that energy is viable and multiform in terms of physical (and chemical) components and in terms of sources. For our ancient ancestors, who lived by hunting and probably ate their kill raw, the typical energy requirements were only about 7,000 J/day. When people learned how to use fire, the amount of energy used per day was probably about double or triple this. When humans settled down to a more sedentary life of mainly agricultural pursuits and used oxen or horses, the energy usage per person tripled again to about 40,000 kJ per day. In most places in Europe during the early Renaissance, windmills and coal and wood burning became fashionable for heating, cooking, and power generation, and energy use doubled once more to about 100,000 kJ. During the last century in North America per capita energy usage was about 400 MJ per day, and today each person in Canada uses over 1,000 MJ per day.

These exponential increases in energy usage through time have been due mainly to the fact that we have almost completely substituted other forms of energy for human labour. For well over 90% of human existence on earth, the required

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energy was derived from captured wild food. For about 10% of our existence, fire provided the main energy. For less than 1% of the time, we have derived energy mainly from domesticated plants and animals. Finally, for only about 0.01% of human history on earth, fossil fuels have provided the major energy source.

In this very short time, however, we have become very dependent on and have become used to the chemical energy of gasoline being transformed into kinetic and heat energy. The chemical energy of wood and coal is routinely used to power boilers that generate electric energy. This electric energy is then transformed into mechanical energy in machines, into light energy in light bulbs, into thermal energy in ovens and water heaters, and so on.

The earth system energy flux Although we can easily trace the history of usage of different forms of energy sources from, for example, the widespread use of water and wind energy during the Middle Ages to coal and steam sources of energy during the nineteenth century, and ultimately to oil, natural gas, and coal sources today, we must appreciate the fact that most (but not all) energy ultimately comes from the sun. (The sun’s energy is supplemented by heat energy from the earth’s interior and tidal energy from the gravitational system of the earth-moon-sun.)

Energy flow or flux into and out of the earth “system” is always present and is relatively constant. The inward flow, termed flux to the earth’s surface, is derived mainly from solar radiation, which is by far the largest of the three components. The rate of flow of solar energy across a unit of area of the earth’s outer atmosphere is constant and is approximately 1.36 kW/m2, giving a total solar radiation constant (termed solar constant) of 1.73 x 1017 W for the earth. About a third of this solar radiation is reflected back out into space as shortwave radiation and about half of this radiation hitting the outer limit of the earth’s atmosphere is absorbed by the atmosphere, land, or oceans, converted to heat, and re-radiated as long-wave radiation. The relatively small amount remaining (about 20%) is used in running the hydrological cycle, and in driving the globe’s atmospheric and ocean currents. The chlorophyll of photosynthetic plants also captures a small proportion of this latter radiation.

Although very small usage in terms of the overall solar constant, the development of chlorophyll was one of the most important evolutionary steps. Chlorophyll is a very complex but relatively stable substance designed to utilize direct solar radiation. Because of its green colour, it can absorb visible light in the red and blue parts of the light spectrum. The ultimate importance of chlorophyll, from an energy resources perspective, is that it is the material that made possible abundant life on the earth. The photosynthesis reaction is of fundamental importance to energy resources:

2 2 6 12 6 2 26CO 12H O C H O 6O 6H O+ + +

This reaction is basically a transfer of H2 from H2O to CO2 and results in the production of organic matter (in this simple equation the C6H12O6 is glucose; other types of photosynthesis can result in more complex organic matter).


Another very important by-product of this photosynthetic reaction is the generation of free oxygen. Indeed, before photosynthesis was widespread, the earth’s atmosphere was oxygen depletes and the surface of most of the land was strongly reducing. Thus, this reaction, powered by direct sunlight fixes C in the form of organic matter and liberates O2. Upon the death of the organism that is doing the photosynthesising, the trapped (and converted) solar energy is liberated by the processes of decay, consumption, and/or oxidation.

While at any given time in this organic matter generation-decomposition cycle, the energy “budget,” or the balance between energy being stored in the plant and that being released by the decay/oxidation processes, is nearly perfect, a very small amount of organic matter does manage to escape in some circumstances. Thus, the system is “leaky”: a minute amount of organics (and the associated stored solar radiation) may fall into or be deposited in a nonoxidizing environment. These low O2 environments may be swamps, deep lakes, deep oceans, or even relatively shallow environments that are characterized by very rapid sedimentation. The point is, however, that the low oxygen environment prevents complete recycling of the organic matter and the stored solar energy is not released. Hence, the energy that we have in our fossil fuels is essentially stored solar energy.

The second component of the earth’s surface energy flux is that derived by conduction and convection from the earth’s interior. The temperature of the subsurface in most areas of the earth rises gradually with increasing depth. This gradual rise in temperature is termed geothermal gradient. The average conduction at the surface of the earth due to this geothermal gradient is small, only about 0.06 W/m2, but integrated over the entire earth’s surface, it amounts to over 32 x 1012 W.

Finally, the combination of kinetic and potential energy due to the earth-moon-sun planetary system contributes the smallest component (about 3 x 1012W) to the earth surface energy flux.

The following data and values summarize the earth’s surface energy flux system:

Solar radiation received at the outer atmosphere: 174 x 1015W

Solar radiation re-radiated to space as short-wave radiation: 52 x 1015W

Solar radiation converted to heat energy in the atmosphere: 82 x 1015W

Solar radiation used to drive the hydrological cycle (evaporation, precipitation, runoff, etc.): 40 x 1015W

Solar radiation used to drive atmospheric and oceanic winds, waves, and currents: 370 1012W

Solar radiation used by photosynthetic plants: 40 x 1012W

Terrestrial (geothermal) energy by conduction: 32 x 1012W

Terrestrial (geothermal) energy by convection: 300 x 109W

Tidal energy (earth-moon-sun system): 3 x 1012W

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Resource and reserve terminology We have learned that to effectively communicate with physical scientists it is necessary to master a few basic definitions and technical terms. The same is true for discussion and communication with energy and mineral resource experts. Much of the problem associated with energy and mineral reserve and resource terminology stems from simple misuse of similar terms. The reasons for this continued misuse are many but chief among them are:

1. The definitions and usages of the terms change and evolve with time. The mineral and energy extractive industries are among the oldest industrial pursuits of humans. Hence, the terminology that originated during the 1700s may have evolved considerably such that any particular term may no longer have the same original meaning.

2. Sometimes several definitions can exist for the same term or concept because the definitions were developed in different areas or the energy/mineral realm. The term “humic,” for example, has considerably different meanings when used in coal geology versus petroleum geology.

3. Due to the tremendous variety of energy and mineral resources, it makes sense that no completely standardized set of terms can be used. Even within one specific area of resource studies, fossil fuels for example, the terms used to identify and quantify reserves have not been and apparently cannot be standardized.

One of the first groups of terms that we must master is that dealing with renewable versus non-renewable resources. A renewable resource, sometimes also called an income source or an income resource, is one that has either a steady long-term direct supply or one that is readily replenishable over the relatively short-term. Examples of renewable energy sources are solar radiation, hydroelectricity, wind energy, biomass, tidal energy, and geothermal energy. In contrast, a non-renewable energy resource, also called fund source or fund resource, is one in which the energy source occurs in traps or reservoirs that cannot be replenished on any practical human time scale. Examples of non-renewable energy sources include most fossil fuels (oil, gas, coal) and most fissionable fuels such as radioactive uranium and thorium.

The next set of terms helps scientists to better communicate about the state of the quantity of the energy or mineral material being considered. A resource base is the total amount of energy (or mineral) source occurring in a particular region (or if we are dealing with very large-scale considerations, the entire world) in recognizable form. For example, the conventional oil resource base for Canada is about 1012 barrels. A resource, on the other hand, is the total amount of the resource base that is estimated to be “probably” usable to humans (“probably” is troublesome; what controls the probability factor?). Aspects like the precise recovery technique(s), the location, the economics, and the ultimate use of the product all must enter into the definition of this term. Thus, the term resource is very imprecisely defined. Using our example of conventional oil in Canada, the Canadian resource is only about 0.06 x 1012 barrels (as opposed to the resource base of about 1012 barrels).


A reserve is the next step down from resource and resource base. Usually the term reserve is only applied to non-renewable resources, such as most minerals and fossil fuels. A reserve is the total amount of the resource that can be defined as recoverable in terms of a specific set of economic, operational, and conceptual conditions. It is very important to realize that the term reserve must always be qualified. Unfortunately, many politicians and civil servants fail to apply the appropriate qualifying term and, therefore, their meaning is at best unclear or at worst incorrect.

One of the primary ways to qualify the term reserve is to indicate whether you are dealing with initial reserves or remaining reserves. In any finite deposit, whether mineral or fossil fuel, the initial reserves must always equal the amount produced to date (cumulative produced reserve) plus the remain reserve. Canada’s largest on-land oil field, the Pembina field in central Alberta, illustrates this very well. The field was discovered in the 1950s and has been a major contributor to Canada’s well-being and livelihood for many years. The initial reserves of the field were an impressive 1.5 x 109 barrels of oil. Now, however, after nearly 4 decades of production from this field, the remaining reserves are less than 500 x 106 barrels.

An even more important distinction that must be made is between in-place reserves and recoverable reserves. In-place reserves are the total resource in the deposit less any portion that cannot be recovered by any foreseeable technology or economic condition. Using the Pembina field again, the original in-place reserve was about 7.4 x 109 barrels. The recoverable reserve, in contrast, is that amount of the resource that is considered recoverable under present-day technology and economic situation. For the Pembina field, this value was only 1.5 x 109 barrels or about 20% of the in-place reserve.

A similar set of terms is often used by governments and oil/mining companies to help clarify the meaning of their reserve and resource numbers. A possible reserve is that amount of the resource which is within the range of possibility, given the general geological setting, but the actual geological knowledge of the region is insufficient to give a more precise qualification. The federal government of Canada often uses the terms low probability reserve and 10% probability reserve synonymously with possible reserve. The possible conventional oil reserve of Alberta is 13.5 x 109 barrels. A probable reserve is that amount of the resource that is potentially economically recoverable with only a slight increase in either geological knowledge or exploitation expertise. The probable conventional oil reserve of Alberta is 11.5 x 109 barrels. A proved reserve (synonymous with established reserve, high probability reserve, and 90% probability reserve) is the portion of the resource that is specifically delineated by drilling, testing, or other exploratory methods, and it is reasonably certain that it could be produced in the future under present-day economic and technological conditions. The proved conventional oil reserve of Alberta is about 10 x 109 barrels.

A separate category of reserve terms is sometimes used when the economic conditions are fluctuating dramatically, such as was the case during the oil crises of the 1970s. A reserve that is within economic reach is that portion of

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the resource that is recoverable and marketable under the current or anticipated economic conditions. In contrast, it is possible to have a reserve that is presently beyond economic reach. An example of this latter category is the large reserve of natural gas in the Canadian Arctic. It is not presently within economic reach because of the lack of a suitable transportation system to market areas.

There have been numerous attempts by various government organizations to standardize the terminology associated with reserves and resources. One of the first such attempts was that by the United States Geological Survey in the early 1970s. This standardization scheme recommended use of the term total resource (of the region or country), which was synonymous with the term resource base defined above. This total resource category was then subdivided into identified reserve, undiscovered resource, and subeconomic resource. The division based on economic conditions was quite rigidly defined: a resource was considered subeconomic if it required a substantially higher (greater than about 1.5 times) market price or a similar major cost-reducing technological advance.

In the latter part of the 1970s the Centre for Natural Resources, Energy, and Transport of the United Nations (CNRET) recommended another standardization scheme. This scheme avoided the use of the term “reserve” entirely and used resource exclusively. It also used a letter-number system of descriptors in an attempt to avoid the inherent ambiguities of the other systems. CNRET called for three basic levels or categories of resources: R-1, R-2, and R-3. An R-1 resource was considered the most reliable and was based on sound geological investigations and knowledge by drilling. The R-2 category was essentially an extension of a known deposit or accumulation. It was assumed that most R-2 resources would become R-1 upon further drilling and investigations. An R-3 resource was synonymous with the term “possible reserve” as we defined it above. Each of these categories was then divided into subcategories depending whether the resource was economically exploitable under present-day technological conditions (using the letter E), possibly exploitable as a result of an anticipated change in technology or economics within the next five to ten years (M), or possibly exploitable as a result of changes in technology or economics in ten to twenty years in the future (S).

In retrospect it can now be seen that none of these nor any other standardization attempt has been successfully adopted by the energy and minerals industries. There are many terms and many classifications systems currently in use, and it is very unlikely that any degree of standardization will be accepted universally. The important points to remember are that whatever terminology system you, your company, or your government agency does use, it is up to you to understand what is being referred to. You certainly cannot assume any one definition of a given term nor can you even assume that the writer or speaker is consistent with his/her terminology.

Resource base and reserve measurements We will once again return to the aspect of units of measure—this time of quantities of energy resources rather than of energy, work, and power.


The amount of coal as a resource or reserve is usually measured in terms of weight with the English ton or metric tonne being most often cited. As we will learn later in this course, however, the quality of coal varies significantly, and this quality affects the power generating potential of this fuel. Thus, coal is also commonly discussed in terms of grade and rank. These latter terms will be discussed in detail in a later lesson.

Oil reserves and resources are usually measured by volume, with barrels being the norm even in metric system countries such as Canada and Europe. More rarely, oil reserves are occasionally quoted in cubic meters. The factor for converting between barrels and m3 is: 1 barrel = 0.1589 m3. Because a barrel (42 gallons) is a relatively small volume, often reserves are discussed in terms of a thousand barrels (abbreviated Mbbls) or million barrels (abbreviated MMbbls). Like coal, the quality of crude oil is also important in dictating its power-generating capacity, its use as a refinery stock, and its overall resource attractiveness. The quality of the oil is usually evaluated by referring to some measure of the specific weight of the liquid. Two units are commonly used: specific gravity and API gravity. Unfortunately, these units of measure of specific weight are not easily correlated. Indeed, the scales even go in “opposite” directions. Most oil is, of course, less dense than water. The closer the oil is to water (i.e., the more dense it is), the closer the specific weight is to 1.0. A very light oil may have a specific weight of 0.2, whereas a very dense oil would have a specific weight of close to 1.0 (or even perhaps greater than 1.0). Conversely, the closer an oil is to water the closer the API gravity is to the number 10. A very light (low density) oil such as one with a specific weight of 0.2 would have a very high API gravity value (approximately 50). Finally, the quality of the oil is sometimes evaluated by referring to its dominant chemical composition. We will discuss this aspect in considerably more detail in future lessons, but oil can be naphthenic (having a relatively large amount of naphthene ring components), paraffinic (having a relatively large amount of paraffin components), or asphaltic (having a high proportion of heavy asphaltenes and other impurities).

Natural gas reserves are also measured in terms of volume, except that cubic feet (or cubic meters) are the norm rather than barrels. One cubic foot of gas is equal to 0.0283 m3 at surface temperature and pressure conditions. Similar to that of oil, a ft3 (or m3 ) is a relatively small volume, so reserves are usually discussed in terms of Mcf and MMcf.

Even from this very brief introduction to units of reserves for fossil fuels, it should be apparent that it is very difficult to discuss energy sources using common quantification factors.

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Review questions 1. What is the ultimate source of most energy used by people?

2. For about what proportion of human history have we depended on fossil fuels? How does this compare with how long we have depended upon energy from domesticated plants and animals?

3. Provide a sketch of the earth’s energy flux system and quantitatively identify each of the major flux components.

4. What is Canada’s conventional oil resource base? How does this differ from the size of our conventional oil resource?

5. The Pembina oil field in central Alberta is Canada’s largest non-offshore conventional oil deposit. How do the remaining reserves compare with the initial reserves? How do the recoverable reserves compare with the in-place reserves?


Notes

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Unit 3 Fundamentals of Energy and Mineral Crises

Topics Introduction and setting The crisis Tragedy of the commons

Introduction What will the world be like in 2010? Will the problems of supplying energy finally have caught up to society? Will the many facets of continued mineral and energy crises have proved too much for human society to handle? Will there be the oft-predicted forced cutbacks in use and demand of energy and minerals? Or will we have solved our energy and mineral supply problems? If so, how? Through voluntary decreases in demand? Through enhanced technology?

This section deals with energy and mineral consumption and the complex interaction of free-world supply and demand versus the realities of energy geopolitics and historical trends in use of our conventional energy and mineral resources.


• summarize the recent history of energy “crises”;

• calculate the doubling time of a material that is growing exponentially;

• outline the consequences of exponential population growth in a finite environment;

• describe the use of mineral resources in antiquity;

• discuss modern trends in resource usage;

• critically evaluate the role of governments, cartels, and corporations in control of resources;

• trace the history of oil use; and

• describe the concept of the tragedy of the commons and discuss this concept with respect to energy and/or mineral resources.


Learning activities 1. Read the study notes. 2. Answer the review questions.

Study notes Key terms arithmetic of exponential growth doubling time energy crisis energy gap tragedy of the commons

Introduction and setting In 1973 most of the world suddenly became aware that civilization was in the midst of an “energy crisis.” This point was brought home dramatically when the Middle East countries suspended all shipments of oil to North America and parts of Europe just before the onset of the northern hemisphere winter season. The resulting abrupt change in the fossil fuel supply did much to hasten society’s awareness of a situation that, in fact, energy and resource scientists had for many years been predicting and warning about.

Even without the Arab embargo on oil shipments, fuel supplies for large parts of North America and Europe were not in good condition. For some twelve years prior to the “first” energy crisis, geologists and resource scientists had been warning that the domestic and regional supplies were dwindling, and costs were necessarily going to rise in response to a more limited supply. For some time in northern Europe, Canada, and the United States, fuel stocks from local fields, particularly those of gasoline, fuel oil, and natural gas, were no longer sufficient to permit the extravagant use that these countries and regions had enjoyed in the past. In retrospect, it is now easy to read the warning signs: at times in North America, the increased use of air-conditioning equipment during a severe summer heat wave had overtaxed local electric generating plants and necessitated cutting back the output voltage, producing the well-known “brownouts” and occasionally complete blackouts.

The shortage of oil supplies in 1973 was temporary and was followed by half a decade in which oil was plentiful, although available at considerably higher prices. Then in 1979 North America once again experienced shortages in the supplies of gasoline and fuel oil. In Canada the price of a barrel of oil increased by nearly 400% in a matter of 18 months. This time, however, it was obvious to at least the political leaders and decision makers that, among other things, conservation measures would have to be forced upon the public, in some instances in the form of gasoline rationing, reduced speed limits, and mandatory fuel allocations.

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Now, some twenty years after these “energy crises,” there again is an oversupply of petroleum on the market and relatively low oil prices. There is, today, also an excess of electric generating capacity, and new plants under construction have been or are being cancelled. These experiences make it natural to wonder what our prospects are for the future. Have higher prices and increased conservation measures worked? Has the energy crisis been solved? Was there even an energy crisis or was it a temporary, short-term fluctuation in regional availability exasperated by a few oil-exporting nations flexing their collective muscles? Will the energy shortages return in the near future? Are the doom and gloom predictions of science valid? How long will our fossil fuel supplies and conventional energy sources hold out under today’s usage? How much energy will we need next year? In the year 2010? In the year 2050? What new possibilities are there for alternate or nonconventional sources of energy? Is the demand sufficient for the development of these new technologies?

To most people, these and many other similar questions remain unanswered and unanswerable. Clearly, we do not know the answers to these extremely important questions with any degree of certainty. Nevertheless, in many areas of the scientific and energy arena, the consensus is overwhelming: the age of fossil fuel dependence is (or will soon be) over. How society copes with this impending change is a function largely of decisions that must be made immediately. Thus, projections must be made to guide our thinking and actions. We will discuss some of these estimates and predictions in this lesson.

In looking at the overall energy picture, however, we immediately see a formidable problem: the only way to discuss the future energy situation is to use historical trends of energy demand and consumption, power production, and fuel reserves. And these trends are not particularly promising. Although economists and social scientists may predict, for example, that in times of economic recession, there should be smaller demands for energy and supplies will therefore be abundant and less expensive, in fact the historical data do not support this. Our demand for energy, mainly fossil fuels, has shown a steady, continuous, and exponential rise over the last century, despite repeated economic recessions, depressions, and market fluctuations.

The crisis What is an energy crisis? Is the world actually in danger of running out of useful energy? Are we faced with the prospect of darkened cities, curtailed transportation, and no heat for our homes? Much has been written about the energy crises of the 1970s and early 1980s. It is important to separate the concepts and phenomena of energy crises and energy gaps from long-term availability of fossil fuels and other conventional energy sources. The energy crises experienced by the free world 15 to 20 years ago were a complex series of problems including scientific, technological, social, economic, and political components. Many factors conspired to produce, in most cases, a potential shortage of energy. In fact, in most cases in North America the term “energy gap” (temporary shortage of energy due to an imbalance of demand exceeding supply) should be used instead of “energy crisis.”


First of all, the demand for energy has been and is continuing to increase at an exponential rate. There are several reasons for this. Not only is the world population steadily rising, but the individual demand for products and services is also increasing. In many areas of the world, this increase in demand for products and services is much greater than the comparable population increase. Affluent nations require more and more energy to maintain or to advance their standards of living. Emerging nations require more and more energy to convert from agricultural to industrial economies. Even agricultural activities demand increasing amounts of energy for fertilizer production and for mechanized equipment in order to meet the world’s increasing food requirements.

The arithmetic of growth is probably one of the most important concepts to master and understand in the entire realm of energy and mineral resources. Historically, since about 1860 the rate of consumption of energy has been growing at about 7% per year. As we discussed in lesson 1, nearly all of this energy (and energy growth) has been supplied by fossil fuels (mainly oil). Thus, for the point of discussion, we know that the increase in demand for oil has been growing at a fixed rate (about 7%) per year. This is referred to an exponential growth. The fundamental principle of exponential growth is that there is a fixed or constant time required for the growing quantity to double in size (i.e., to increase by 100%). This is referred to as the doubling time or T2, and can be approximated by the simple equation:

T2 = 70/p

where T2 is the amount of time in years required for the size of the material or quantity to double, and p is the percentage growth rate per year. So, we can see that the amount of energy required (i.e., energy demand) is doubling every 10 years. Furthermore, if we continue this simple arithmetic analysis, we realize that very large quantities of energy are required in a very short period of time. In 10 years (one doubling time) the amount of energy required (let’s say barrels of oil) doubles once: 21 or 2; in 20 years (two doubling times) this quantity doubles twice: 22 or 4x; in 30 years (three doubling times) the demand doubles three times: 23 or 8x, and so on.

This phenomenon of exponential growth has several significant repercussions. First, it is obvious that even just a few doublings will result in very large quantities. If the demand for oil in Manitoba in 1960 were 100,000 barrels, what would the demand be in the year 2000? 1.6 x 106 barrels! Second, the size of the demand (barrels of oil in our discussion) after each doubling period is always going to be greater than the total demand before the doubling took place. In other words, using the historical 7% growth rate in the demand for oil, we will use more oil in the next 10 years than we have during the entire period from 1860 to now.

It is essential that resource scientists have a firm understanding of these aspects of growth in a finite environment. The following story about growth of bacteria in a bottle serves well to illustrate the problems of our use of energy. Suppose that you place a bacterium in a bottle. For the sake of this discussion, assume that bacteria grow and multiple by simple division: 1 bacterium divides to

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become 2; 2 become 4; 4 become 8, etc. And finally assume that this division time is 1 minute. Thus, the bacteria have a doubling time (T2) of 60 seconds (or in other words the bacteria are growing at a rate of 1.16% per second). You placed the first bacterium in the bottle at 11:00 am. At 11:54 you come back to the bottle and notice that it is 1/64 full; a minute later it is 1/32 full. Clearly you can predict that at 11:56 it is 1/16 full; 11:57: 1/8 full; 11:58: 1/4 full; 11:59: 1/2 full; and at 12 noon, the bottle will be completely full. So at 2 minutes before noon you look into all the other laboratories to try to find more bottles. And you are amazingly successful: at 11:59 you find three new bottles—three times the space that you started with nearly an hour ago. How long will this additional space last? At 11:59 your first bottle will be 1/2 full and at noon it will be completely full. But at just one minute past noon, bottles 1 and 2 will be completely full and by 12:02 all four bottles will be full!

This simple story is a surprisingly accurate picture of today’s energy situation. One of the first scientists to work with this kind of exponential growth scenario was the geologist M. K. Hubbert in the 1960s and 1970s. He undertook an analysis of the amount of oil that had been produced in the world to date, how much likely remained, and what level of consumption demand there had been through history. Hubbert’s assessment provided the following information: he estimated that the ultimate world production of oil would be about 2 x 1012

barrels. Only about 13% of that quantity had been produced between 1860 and 1972, thus leaving over 1.7 x 1012 barrels for present and future use. How long did Hubbert predict this large quantity of the world oil would last? His conclusions shocked the energy (and political) world: if the historical trend of 7% increase in demand for oil were maintained, the world supply of oil would be exhausted by the year 2000!

The Hubbert style of analyses has been often repeated during the past two decades with amazingly similar results: until society alters the demand (7% per year increase), it is very likely that world oil resources will be exhausted very early in the twenty-first century. This type of analysis, of course, can be applied to any finite, nonrenewable energy or mineral resource. For example, in 1973 the United States Geological Survey concluded that the reserves of coal in North America were so great as to meet the then current levels of demand for the next 500 years! But the key phrase is, of course, at current levels of demand. This means zero percent growth in demand. If demand increased at the nominal rate of only 1% per year, the vast reserves of coal would last only 140 years. If a 7% growth rate were used, similar to that of oil, then the coal reserves of North America would be exhausted in only 50 years.

The second major factor contributing to the energy crisis is the adverse effect on the environment due to the increased exploration, extraction, transportation, and utilization of our remaining fossil fuel supplies. While efforts are being made to reduce the spoilage of the world by our increased use of energy, every such effort, as desirable as it may be, places increased restrictions on the utilization of energy and makes it more difficult and more expensive to supply the increasing demand. The geopolitics of oil and gas exploitation is a factor that is closely related to these environmental concerns. As North America (and


Europe) continues to depend heavily on a fuel that is supplied by another nation, it is always conceivable that deterioration in the international political situation could suddenly cut off the supply. In early 1973 North America imported about 30% of the oil that it used; about one-third of these imports were from Middle East countries. Because of the easy availability of imported oil and because of the environmental restrictions on widespread use of coal, oil had almost completely replaced coal as a fuel in electrical generating plants. Most of the oil used in these plants was imported. The reduction in the amount of imported oil therefore placed severe burdens on these power-generating facilities.

In retrospect it seems obvious that we should have begun years ago to address the problem of energy supply. But as long as we can flick a switch and have as much electrical energy as we need, and as long as we can drive to any gasoline station and fill our tanks, there seems to be no problem at all. It is only when temporary gaps between supply and demand lead to local and regional energy shortages those we collectively finally realized that there is indeed an impending “energy crisis.”

Tragedy of the commons Several decades ago, socioeconomist Garrett Hardin brought the concept of the tragedy of the commons to public attention in a series of publications on world population. Hardin contended that, rather than working for the collective good, individuals behave in a selfish fashion that ultimately leads to destruction of the society. To illustrate this concept, Hardin used an example of a village commons—a field open to all inhabitants of the village for use as park, pasture, field, or whatever they wanted. Each cattle owner in the village was entitled to use the commons, and, of course, each cattle owner tried to keep as many cattle on the common as possible. During times of war, famine, poor climate, or disease, this method of the use of the commons worked: the human and animal populations were kept in check. However, during good times the carrying capacity of the land of the commons would be quickly reached and permanent damage would be sustained. The continued use of the commons, despite the obvious damage, would result in all cattle starving, and the complete loss of the entire commons as a positive feature in the life of the villagers. The tragedy of the commons is essentially that complete freedom in a limited world will eventually bring ruin to all.

Much has been written and discussed about the tragedy of the commons concept with respect to western civilization resource ethics and society processes. Many believe that the tragedy of the commons will operate in every case in which personal gain is attained by losses for all, even if the losses may seem negligible to the losers. Indeed, the wealth of the gainers will actually lead them to destroy what all possess in common because if all possess something (i.e., free goods), then that thing is perceived as having no individual economic value. The natural conclusion of the tragedy of the commons concept, then, is the reasoning that injustice is preferable to total ruin. If we are exploiting resources in a laissez-faire manner, we favour people or companies who focus narrowly on profits and

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distribute losses as widely as possible. Or in practical terms: the cost of dumping waste, as far as a profit-oriented company is concerned, is less than the cost of cleaning up. When the waste accumulates to such an extent that it creates an unacceptable environmental hazard or is no longer acceptable to society, the companies are no longer identifiable, and the public must pay for the cleanup.

For example, power companies (use the example of coal-burning plants) are always under attack to provide cheaper energy to their customers. Obviously, the power company will therefore want to buy its fuel as cheaply as possible. Coal Company A operates a deep subsurface coalmine and provides coal at a price of $40 per ton. Coal Company B operates a strip mine and can provide coal at $10 per ton, but reclaims the stripped land after mining and therefore must charge an additional $5 per ton to undertake this reclamation. Coal Company C also operates a strip mine and sells its coal for $10 per ton, but has made the corporate decision not to undertake reclamation of the land. Clearly, the power company will buy from Company C. So at the next stockholders’ meeting of Company B, the decision is made to cease reclamation efforts; at the next stockholders’ meeting of Company A, the decision is made to abandon deep mining in favour of strip mining. As a result of these economically driven corporate decisions, the true societal cost of coal mining is under pricing and encouragement of the use of unnecessary energy. Clearly cheap energy is being gained at a cost to society as a whole and, because of the under pricing, there is no incentive to curb consumption. Indeed, this would likely filter back to the construction industry, for example, which would undertake to construct buildings with less insulation and sell them at a cheaper price and, since it would be so inexpensive to heat them, consumer demand would increase.

Review questions 1. Is it possible to construct energy-generating facilities without any cost being

borne by society at large? Discuss your point of view.

2. What are “free goods” in the context of economic energy and mineral resources exploitation?

3. What are some examples of the tragedy of the commons different from those given in the notes?

4. Define doubling time; give an equation for the calculation of doubling time.


Notes

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Module 2 Energy Resources


Notes

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Unit 4 Oil and Natural Gas: Introduction, History, and Geochemistry

Topics Role of the earth sciences in the petroleum industry Historical perspective Finding a commercial deposit of oil and gas Petroleum geochemistry

Introduction During most of human history, wood was the major fuel. Although the early Chinese had a viable petroleum industry several thousand years ago, it was not until the middle part of the last century that human society entered the era of petroleum energy. Now we will introduce some of the important historical aspects of the modern petroleum industry, and will begin our exploration into what makes a petroleum deposit.


• discuss the traditional and modern roles of the geoscientist in today’s petroleum industry;

• summarize the major reasons why the modern era of petroleum made a successful start when it did;

• trace the history of the petroleum industry and petroleum geology in Canada;

• outline the major advances in petroleum geology after the 1920s;

• describe the conditions or factors that must be accomplished or satisfied in order to generate a commercial deposit of petroleum; and

• differentiate the various types of organic compounds that make up oil and natural gas.

Learning activities 1. Read the study notes. 2. Answer the review questions. 3. Begin reading pages 125–189 in Resources of the Earth. 4. Begin reading pages 1–113 in Our Petroleum Challenge.

Note: these reading assignments contain material corresponding to several sections in the coarse notes. You should plan your textbook reading


schedule such that you have completed reading these pages by the end of unit 8 of the notes.)

5. Complete Assignment 1 and send it to the Distance and Online Education Student Services office.

Study notes Key terms aromatics benzene CPR fossil fuels GSC hydrocarbons maturity migration NSO paraffin permeable petroleum play porous naphthene reservoir rock seal sour gas source rock sweet gas trap Turner Valley whale oil

Role of earth sciences in the petroleum industry Petroleum geology is defined as the utilization of geology in the exploration, development, and exploitation of deposits of oil and natural gas. The major scientists involved with today’s modern petroleum industry are geophysicists, geologists, and geoengineers. Although it is very important that each of these groups of geoscientists is able to communicate with one with the other during the life of typical petroleum “play,” in fact the tasks and duties performed by these geoscientists are quite distinct. The geophysicist is often the dominant geoscientist early in the history of a prospect. His/her input into the prospect occurs mainly before the first well is drilled and decreases dramatically after this. The geologist, on the other hand, often does not get involved in the prospect until immediately before or during the drilling of the first well and then plays a dominant role until the first production in the field is realized. Finally, the geoengineer is usually not a contributor until after production is established.

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The role of earth scientists in this extractive industry has been variable over the past 100 years. The traditional role of the geoscientist was in the areas of:

• exploration for and location of suitable hydrocarbon reservoirs and new deposits and accumulations of oil and gas;

• evaluation of existing or new accumulations, reserves, and production potential; and

• extraction of the liquid and gaseous products.

Within the last decade the petroleum industry geoscientist has taken on the additional tasks of:

• explication, or the study and evaluation of the expected performance of the reservoir to enhance recovery schemes; and

• extrapolation of what is known from existing oil and gas fields to poorly explored areas.

Historical perspective The petroleum industry is an old industry. There were efforts by the Chinese around 1000 B.C. to locate and extract liquid hydrocarbons. There was a thriving oil industry in Burma in 500 to 800 A.D. with wells penetrating as deep as 1,000 feet. The Indians of North America commonly used oil and tar in daily activities.

The modern petroleum industry started in North America in the mid-1800s. The remarkable success of the early industry at this time was due to a combination of factors, including:

• market conditions: up until the 1850s most oil was derived from whales. By the mid-1800s the stocks of whales were dramatically decreased because of over fishing. Thus oil from the subsurface could be readily marketed.

• price of oil: the early petroleum industry benefited greatly from the relatively high prices for oil. In 1850, a barrel of oil cost about $24, a bit more than the cost of a barrel today!

• type of oil: the early North American oil fields, located in Ontario and eastern United States, were producing a very high quality type of oil.

Much of the early history of the modern petroleum industry revolves around exploration and development in eastern United States and Canada. Indeed, during the three decades following the initiation of the modern industry in North America, Canadian developments were extensive. The Geological Survey of Canada (G.S.C.) was probably the most knowledgeable organization in the world in terms of oil and gas in the mid-to late-nineteenth century. Dr. T. S. Hunt, a geochemist with the G.S.C., is often referred to as the father of Canadian petroleum geology because of his extensive work on petroleum generation and geochemistry.

The 1860s to 1890s saw a shift in action toward western United States and Canada. In Canada, the development of the CPR also contributed to the


exploration of large areas of the Prairie region. Many of the large southern Alberta gas fields, such as Medicine Hat, were discovered by CPR geologists at this time. However, it was not until 1914 that the first giant oil field in Canada was discovered. The discovery of the Turner Valley oil field was probably the single most significant event in the history of the Canadian petroleum industry. Not only was Turner Valley a world class giant field, but its discovery spurred development of many small exploration companies, aided and accelerated the development of geophysics, geochemistry, and structural geology as exploration tools, and opened an entirely new style of exploration.

The major point to be remembered concerning the early efforts of the petroleum industry is that for the first 70 years of development, the petroleum industry did not use petroleum geology! This is because the use of nongeological techniques was adequate for finding oil and gas and, in fact, geology and geologists then could not explain many of the deposits.

From the 1920s to the 1940s, many changes took place in the petroleum industry. These changes can be summarized as following:

• Improved drilling technology: for the first time geologists were actually able to see the subsurface because cores, chips, and samples could be retrieved and studied.

• Application of geophysical and petrophysical well logging. The use of electric logs allowed geologists to correlate stratigraphic units across long distances. The use of radioactivity logs allowed geologists to ascertain the reservoir quality of the rocks. Finally, and most recently (beginning in the 1950s), the use of porosity logs enabled geologists to gain an in situ assessment of not only porosity but also fluid content.

• Widespread use of exploration geophysics: the use first of refraction seismology and later reflection seismology greatly aided the ability of geoscientists to identify subsurface structures and irregularities which might act as traps for hydrocarbons.

Finding a commercial deposit of oil and gas The task of finding an oil and/or gas field today is not a simple one. First, there must be a rock containing original organic matter; petroleum geologists call this a source rock. It is usually a fine-grained mudrock or shale. As you learned in your first-year geology course, shale is a very common rock type and makes up about 80% of the world’s sedimentary rock volume. However, an average shale contains only about 1% organic matter. Thus, most shales make poor source rocks.

Second, the source rock must be buried deeply enough in the subsurface so that temperature, pressure, and time can cause the organic matter to change or mature into a petroleum-like product. This usually requires deposition in deep, long-lasting sedimentary basins and then infilling of these basins by thick accumulations of other sediments. Because over half of the world’s continental areas and adjacent marine shelves have sediment thickness that are too thin,

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there are only a relatively few areas of the world in which these required thick deposits of sedimentary rock occur.

Even in places where the buried organic matter can become mature, not all of it is converted into petroleum. In a normal marine shale with about 2% original organic matter, considerably less than one-third of that organic matter will eventually be converted to the hydrocarbon molecules that make up oil and natural gas. The rest remains behind in the source rock as an insoluble organic residue.

However, the least efficient step is next. Of all the petroleum generated, much less than 1% eventually makes it out of the source rock (a process called primary migration) and is able to move along porous and permeable conduits to a reservoir rock. Even if the oil and gas does make it out of the source rock, travels through the carrier system, and arrives at a reservoir rock, the majority of this petroleum, or even in some cases all of it, will be dispersed and lost to the surface because of a lack of good arrangement of strata to trap it or the lack of an acceptable impermeable seal or caprock.

Five factors, therefore, are essential for petroleum accumulation: • a mature source rock; • a migration path connecting the mature source rock to a suitable reservoir

rock; • a reservoir rock that is both porous and permeable; • a trap; and • an impermeable seal.

If any one of these factors is missing or inadequate, the petroleum prospect will likely be unsuccessful (an unsuccessful prospect or well is termed “dry”). Because of this required combination of factors only about half of the world’s explored sedimentary basins have proved productive, and typically much less than 1% of the productive sedimentary basin’s area is actually productive.

There are other risk factors that geologists must consider in the exploration effort, such as the ability to recover the petroleum and the quality of the oil or gas. As we learned in unit 2, there can be a big difference between in-place reserves and actual producible reserves. Usually less than 60%, and sometimes as low as 10% of the oil in the ground (oil in-place) and about 70% of the gas in-place, is economically recoverable by conventional modern technology.

Clearly the geological setting of the prospect must be accurately assessed in order to optimize the success of the drilling and exploration effort. Furthermore, in any sedimentary basin, there will be some traps that are simply too small or reservoirs of too low porosity and/or permeability to enable the oil company to pay back its drilling and production costs. Thus, a very important sixth requirement is that the oil and/or gas be present in sufficient quantity.

Although it may seem, at this point, that the task of finding a commercial deposit of oil and gas is overwhelmingly difficult, it is important to remember that the petroleum is not randomly distributed in the subsurface but rather the accumulations follow a specific set of rules. Our understanding of these rules,


admittedly, is incomplete and is based on numerous trial and error efforts and past lessons learned from the drilling of many dry holes.

Petroleum geochemistry The topic of petroleum geochemistry, like organic chemistry, is very complex. Our concerns are somewhat simplified, however, because we are only interested in the simplest organic compound group, the hydrocarbons. The hydrocarbon compounds make up most of petroleum. Strictly speaking, hydrocarbons are compounds that contain only two elements: hydrogen and carbon. Thus, most petroleum is not hydrocarbon because most petroleum also contains nitrogen, sulfur, oxygen, and a wide variety of trace elements and metals.

In some cases these nonhydrocarbon compounds and elements make the petroleum less valuable. For example, both sulfur and nitrogen are undesirable elements within petroleum. Sulfur is most abundant in the heavier crude oils and in asphalt. It can also occur in natural gas as hydrogen sulfide the very poisonous and corrosive compound. Natural gas is called “sour gas” (as opposed to “sweet gas”) if the H2S content is greater than about 1 ppm (part per million). Some gases in southern Alberta, for example, contain up to 5% hydrogen sulfide!

Nitrogen content is generally higher in both asphalts and natural gas, when compared to crude oils. In asphalt, nitrogen occurs mostly in high molecular weight hydrocarbon compounds, called NSO compounds because they contain impurities of nitrogen, sulfur, and oxygen. In natural gases, however, nitrogen occurs mostly as the inactive gas N2 and is relatively harmless. However, even though it is inert and nonpoisonous, it tends to lower the heating capacity (Btu) of the natural gas. Other compounds may also occur in natural gas mixtures, including CO2 and other inert gases.

Although the elemental composition of most hydrocarbon is relatively simple, there are a vast number of ways in which the atoms can be arranged. Compounds with similar physical and chemical properties can, however, are grouped into hydrocarbon series, of which four are particularly important in petroleum geochemistry. These are the paraffins, the naphthenes, the aromatics, and the resins and asphaltenes.

Paraffins occur as chain-like structures with the general formula Cn H2n+2. The carbon number, “n,” ranges from one in the simplest hydrocarbon gas, methane (CH4), to over 40. A natural gas composed of nearly pure methane is called dry gas. Other lightweight paraffins, with carbon numbers up to 5, are also gaseous at normal temperatures and pressures. A natural gas that contains these other heavier paraffin gases along with methane is called wet gas. Paraffins with carbon numbers higher than 5 are normally liquid. High molecular weight paraffin’s become viscous, waxy solids.

Naphthenes are closed ring structures with the basic formula Cn H2n. Compounds of the naphthene series have chemical and physical properties similar to equivalent paraffins with the same carbon number. Together with the paraffins, naphthenes form the major components of most crude oils.

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The aromatics are the third most important group and have a closed ring structure. However, the ring shows an alternation simple single C-C bonds and double bonds. The basic aromatic unit is called the benzene ring. Many other aromatic compounds can be made by substituting paraffinic chains or naphthenic rings at some of the hydrogen sites, or by fusing several other rings together.

The final group, the resins and asphaltenes, are also composed of fused benzene-ring networks, but they contain an abundance of impurity atoms. These impurities are the high molecular weight compounds referred to as NSO compounds above. Resins and asphaltenes are the heaviest components of crude oil and the major components in many natural tars and asphalts.

Crude oils may be classified by their relative abundance of these four hydro-carbon groups. The most common method plots paraffins, naphthenes, and the combination of aromatic and NSO compounds as three axes of a triangular graph and divides the graph into fields. Most crude oils in Canada fall within either the paraffins field (paraffinic oil) or the naphthene field (naphthenic oil). A few crude oils from Canada, such as those of south central Alberta, have subequal amounts of paraffins and naphthenes but are dominated by the aromatics, resins and asphaltenes.

Oil that may be situated at or near the surface can become degraded into heavy oil and tar by bacterial action and flushing by fresh meteoric waters of surface origin. These types of oil fall into one of two classes: aromatic-asphaltic or aromatic-naphthenic, both of which are relatively dense and enriched in the aromatics. Some may contain naphthenes (aromatic-naphthenic oil), but the paraffin content is always very low. In contrast to this shallow burial or near-surface alteration, deep burial in the subsurface usually has the opposite effect in altering crude oil. It tends to make an oil less dense and more paraffinic. Tar sands, like the Athabasca tar sands of western Canada, were once conventional deep oil reservoirs, in which the oil became degraded from flushing by fresh meteoric waters and by bacterial action. These processes have converted lighter oil into a viscous asphaltic tar.

The geochemistry of petroleum (termed quality of petroleum) determines the types and amounts of refined hydrocarbons that can be produced. Natural gas and lightweight crude oil yield mostly fuels. Gasoline consists mostly of medium weight hydrocarbons with carbon numbers ranging from 7 to 14. These can occur either naturally or be thermally cracked from higher weight molecules. As you probably remember from your high school or university chemistry course, cracking is simply the process in which the carbon-to-carbon bonds are broken down by heat, into simpler, lighter weight hydrocarbons. Other high-weight compounds, with carbon numbers greater than 14, are refined as lubricants, waxes, and asphalts.


Review questions 1. List the 5 “Es” of the geoscientist in today’s petroleum industry.

2. Why was the early modern petroleum industry successful?

3. Who was/is T. S. Hunt and what did he do?

4. Why did the early modern petroleum industry not use geology?

5. What is NSO and why is it important?

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Assignment 1

1. Define the concepts of energy, power, and work. Give the units of measurement of each.

2. What is an income energy resource? Given an example.

3. In terms of our “bacteria in a bottle” story, about how close to noon are we in terms of world oil resources?

4. In about how many years from now will it take us to consume more oil than the total amount of oil that humans have consumed throughout history to date?

5. How much work is required to lift a 10 kg box 3 m off the floor (assume the force of gravity is equal to 9.8 m/s2)?

6. Write a balanced and complete equation for photosynthesis, being sure to identify and label all the components of the equation.

7. List the main components responsible for energy flux to the earth’s surface in order of relative magnitude.

8. Differentiate between proved, probable, and possible reserves.

9. What is a resource base?

10. Sketch (or describe) the magnitude and relative timing of the roles of the various types of geoscientists involved in a petroleum play during the life of the play.

11. List the five tasks or responsibilities of geoscientists in today’s petroleum industry.

12. What are the components of a commercial deposit of petroleum?

13. Why was/is Turner Valley important?

14. How does API gravity differ from specific gravity?

15. What is wet gas?


Notes

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Unit 5 Drilling Technology

Topics Bases drilling considerations Drilling environments Drilling equipment Basic drilling functions Drilling the well Drilling progress

Introduction This section will provide a brief introduction to the equipment and procedures used in drilling a well and to some of the standard operating procedures used by geologists and geoengineers at the wellsite during the various phases of a well’s life. These topics are important to any geoscientist involved with resource exploration and exploitation, not just those in the oil and gas industry. However, our discussion here and the treatment of the subject in your textbook readings is directed primarily toward the energy industries.

In this section we will summarize how oil and gas wells are drilled and completed, including the equipment involved, some of the major procedures followed, and the fundamental technological principles behind these procedures. We will first cover the various drilling environments, both surface and subsurface, that the exploration geoscientists and engineers can encounter, and how these conditions may affect the drilling operation. Next, we will outline the elements of the drilling system, showing how each component functions and how all are integrated into an efficient mechanism for “making hole.” We will follow the chronological progress of an actual well, from the location survey to openhole evaluation, and provide some insight into problems encountered along the way. The special considerations necessary when drilling offshore will also be covered. Finally, we will discuss the procedures, such as perforating, fracturing, and acidizing, that are commonly used to complete the well for initial or secondary production.

Drilling any well, whether an exploratory well for oil or gas or a development well in a minerals deposit, is an exceedingly expensive undertaking. Insuring the reliability and usefulness of the subsurface data collected during drilling is almost exclusively the responsibility of the wellsite geologist. Correct evaluation of carefully obtained subsurface geological data is absolutely critical to the success of the well. Indeed, these data collected by the wellsite geologist assume a level of importance that extends much beyond the life of the particular well or play. These data form an essential archive that can be used many decades in the future to help guide subsequent resource exploration and exploitation efforts.



1. describe why geologists are interested in and need know about drilling and drilling technology;

2. trace the history of well drilling from ancient times to the early part of the twentieth century;

3. discuss differences (and similarities) between onshore versus offshore drilling environments;

4. summarize the problems that commonly limit the drilling of offshore prospects;

5. outline why drilling difficulties increase with depth;

6. differentiate between hydrostatic and lithostatic pressure and pressure gradients;

7. describe how and why lithostatic pressures can deviate from the “normal” trend;

8. summarize the basic task(s) of drilling a well;

9. describe the various types of land-based and offshore drilling rigs;

10. discuss the type of offshore drilling rig you would employ for various water depth situations;

11. outline the four basic functions that a drilling rig must accomplish;

12. describe the function of the drilling fluid;

13. differentiate the various types of drilling bits and what each type is used for; and

14. discuss the roles that mudcake, viscosity, density, and flow velocity play in helping control subsurface pressures.



3. Continue reading pages 125–189 in Resources of the Earth.

4. Continue reading pages 1–113 in Our Petroleum Challenge. Pay particular attention to the material on pp. 48–61; many of the illustrations and figures are important and will not be duplicated in these notes.

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Study notes Key terms annulus kelly barge rig kick blowout preventer lithostatic pressure cable-tool rig lost circulation casing moon pool crown block mud cuttings mudcake daywork contract percussion drilling derrick platform rig diamond bit pressure gradient drag bit rock bit drawworks roller cone bit drilling engineer rolling cutter bit drilling line rotary drilling drillpipe semisubmersible rig drillship skidding drillstem slips fishing structure rig footage contract submersible rig geothermal gradient substructure gooseneck temperature gradient hydrostatic pressure three cone bit jack-up rig tool pusher jackknife rig travelling block joint turnkey contract kelly viscosity kick wellbore lithostatic pressure

Basic drilling considerations Introduction To a petroleum exploration or exploitation geoscientist, an understanding of the drilling and completion process is valuable for several reasons:

• to provide necessary background for the work of prospect generation;

• to interpret information obtained during the drilling operation;

• to help understand the complexity of different well programs in order to consider and design various development plans for the pool or field;

• to provide background for the myriad other geological activities associated with drilling (e.g., mudlogging, petrophysical logging, formation evaluation, coring, etc.); and

• to help ensure the safety of drilling personnel when working on a location.


The actual drilling of a prospect is often considered by many geoscientists to be one of the most dynamic and exciting parts of their career!

Usually on a wildcat or exploratory well, the geoscientist spends almost as much time on site as any other individual connected with the operation. The specific role of the wellsite geologist may vary somewhat from company to company and in different regions of the world, but generally the geologist’s responsibilities include the well planning, logging, coring, and testing; in other words, a well does not get drilled (usually) without the geoscientist’s input.

History The history of oil well drilling is scattered with names that many of us are already familiar with: Colonel E. L. Drake, Captain Anthony Lucas, Spindletop, Turner Valley, Leduc. The rapid development and commercial application of rotary drilling in the early 1900s was preceded by the work of many individuals from many different areas of resource exploration (not just oil and gas) and from many areas of the world. Table 5.1 lists some of the important milestones that have been recorded in the early history of modern drilling.

Table 5.1 Rotary drilling history

Year Event

Ancient times

Wells dug by hand; this practice continued in many areas of the world until the1900s

265 BC Chinese use percussion drilling to drill wells for water, using derricks, tubing, bits, and cemented bamboo casing.

1500s Oil well drilling by hand common in Poland and other areas of Europe and western Asia.

1590s Extensive drilling, by hand, to develop the Baku (Russia) oil field.

1808 Ruffner brothers of West Virginia use a “spring pole” percussion-drilling apparatus to drill a well. The drillers attach a cable and bit to a flexible tree sapling secured as a lever over a fulcrum. After using their own weight to bend the sapling and drop the bit into the hole, they allow the spring pole to lift the bit back up.

1829 Steam is used to operate improved cable tool equipment that utilizes derricks, engines, and fishing tools to retrieve lost bits.

1844 Englishman R. Beart invents a drilling machine that includes a hydraulic swivel, hollow drilling rods, and circulating fluid.

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Year Event

1845 French engineer Fauvelle drills a water well near Perpignan, France, using a set of hollow boring rods to allow pumped water to flush rock material from the hole.

1848 A. Beer, an Austrian professor, suggests the possibility of drilling by a rotary method; Russian engineer, F. N. Semyenov, drills first cable-tool well in Eurasia to further develop the Baku oil field.

1858 North America’s first commercial oil well drilled in Ontario.

1859 Using cable-tool percussion drilling equipment, Col. E. L. Drake, considered by many as the “father” of the modern petroleum industry, completes the first commercial oil well in United States, at Titusville, Pennsylvania - TD (total depth) of 21 m.

1860 French engineer Leschot uses a power-driven diamond-studded rotary drill.

1866 Patent is granted for a “stone drill” that includes a hollow drillstem, a roller bit, and a fluid-conducting swivel head.

1869 Patent is granted for one of the first types of offshore drilling rigs.

1880s European oil well drillers, using versions of Fauvelle’s water-flushed drilling tool, drill wells in Alsace, France, and Baku, Russia.

1882 Baker brothers begin using rotary equipment to drill for water in South Dakota to depths of 150 m.

1888 Bakers move their equipment to Corsicana, Texas, where it becomes popular water well drilling equipment.

1893 W. B. Sharp drills for oil with a rotary rig near Beaumont, Texas; well is abandoned at 127 m.

1897 P. Higgins unsuccessfully drills for oil near Beaumont and then hires A. Lucas.

1900-1901 Rotary drilling is on its way: A. Lucas and associates drill the discovery well at the Spindletop Field near Beaumont, using rotary drilling equipment from Corsicana. The well flows 100,000 BOPD (barrels of oil per day) from 300 m.

1909 Howard Hughes invents the rotary rock bit.

1918 The world’s deepest well to date, drilled with a cable-tool percussion-drilling rig, is 2,250 m.

1920s Combination rigs are developed that use percussion cable tools to drill down to 1,000 m and rotary drilling equipment below that depth.

1930 The world’s deepest to date, well drilled with a rotary rig, is 3,000 m.


The early need for water and salt prompted the Chinese to develop a percussion-type drilling apparatus to replace the practice of digging wells by hand. The percussion, or cable-tool, method consists basically of alternately lifting and dropping a heavy iron bit into a hole in the ground and then periodically bailing out the broken pieces of rock.

Although many improvements were made to this basic “drive the pipe into the ground by hitting it” concept over a long time period, other individuals eventually conceived of methods for boring a hole into the earth and flushing out the cuttings. The discovery of a commercial use for petroleum in the mid-1800s accelerated the development of equipment and techniques used to drill for oil. While percussion techniques remained popular in North America (eastern Canada and northeastern United States particularly) for a long while, the rotary drilling rig, introduced into the American midwest by waterwell drillers, gradually became the most widely used method worldwide. Since its acceptance in the early 1900s, the turning bit has drilled over three million kilometers of hole, enough to penetrate the Earth from pole to pole over 200 times. In the search for hydrocarbons, drilling technology has been constantly called upon to adapt to new and usually harsher surface and subsurface environments.

Drilling environments Drilling for oil and gas is undertaken literally anywhere—as long as the basic components of reservoir rock, source rock and trap are present. Indeed, in many cases, the existence of one or more of these basic components is highly questionable, but still drilling is carried out. Although the fact that today’s exploration and exploitation efforts are usually confined to basins with relatively thick sequences of sedimentary rocks somewhat decreases the global extent of petroleum drilling, drilling locations still include almost every conceivable environment on Earth.

The setting for oil and gas well drilling can be categorized as either onshore or offshore, although this simple classification can be somewhat obscured in the case of drilling in swamps, lagoons, or shallow lakes, or in the case of drilling on ice. Onshore, the drilling environments can range from desert to mountain, jungle to arctic permafrost. Often, the biggest problem in onshore drilling is simply getting the drilling equipment to the site. For example, in Middle Eastern deserts, drilling rigs are sometimes transported to locations by trailers with wide, low-pressure tires to allow travel over sand. In low, swampy land, such as is common in many parts of North America and much of South America and the far east, rig equipment must be transported via helicopter or amphibious vehicles. River transport is also frequently used in South America and Africa.

The special challenges of drilling in the high arctic have resulted in several innovations, as discussed in your textbook readings—many of these advances have been made by Canadians and Canadian exploration companies. In much of the arctic, drilling is conducted from 1-2 m thick gravel pads which are put in place to protect the tundra and insulate the permafrost to prevent melting. Usually multiple wells are drilled from a single pad.

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As difficult as these remote onshore drilling conditions can be, some of the most innovative advances in technology have come about as a result of the necessity of drilling in highly urbanized areas. For example, drillsites in suburban Calgary or Los Angeles have to be camouflaged and noise-dampened. Fluids have to be trucked in and waste material immediately disposed of in methods compatible with normal suburban (and in some cases urban) activities.

In contrast to the difficulties of getting equipment to the onshore drillsite, travelling to an offshore location is not usually a problem, however staying at that site is! Weather, waves and water depth are the greatest challenges to offshore drilling. While offshore conditions can vary greatly depending on the location, drilling in water depths of more than 300 m is becoming more common. In some regions, such as the Gulf of Mexico, hurricanes can significantly delay drilling operations. In other cases, high winds and rough seas, with 30 m waves, must be considered in the design of offshore platforms and equipment. In offshore east coast Canada, drilling operations are frequently threatened by icebergs. Other problems that complicate offshore drilling in some areas of the world are earthquakes and subaqueous “landslides”/mudflows, which can destabilize the platform or in some cases completely destroy it.

In addition to considerations about the surface and near-surface environment, drilling technology must address a rather hostile subsurface environment. Although conditions below the surface of the Earth are much less variable, they do, nonetheless, present difficult problems. In general, drilling difficulty increases with increased depth. This is readily understandable because we are trying to maintain control over an operation that is taking place at increasingly greater distances via a relatively small linkage. A string of standard 12 cm drillpipe drilling a 4,500 m deep well is roughly analogous to a string of drinking straws dangling from the edge of a 75-story building.

Furthermore, increased depth also brings increased pressure. Much of drilling technology is ultimately an exercise in controlling pressures and pressure differentials between the surface and the deep subsurface environments. Most of the sediment in the basin in which drilling is being conducted was deposited by, and along with, water. Thus, the porous rocks of a potential reservoir are normally full of water. In nearly every case the oil and gas accumulations make up only a very small proportion of the total volume of fluids in the subsurface reservoir. Most of the pressure that we encounter in the pore space of the reservoir at the base of a drilling well is the result of this column of fluid (water).

For example, if you were to measure the pressure at different depths in a body of water, it will increase with depth. In addition, this increase will be dependent upon the density of the water. The rate of pressure change, termed the hydrostatic gradient, will increase with increasing salinity. Salt water exerts a hydrostatic pressure somewhat greater than that of freshwater (~10.2 kPa/m versus 9.8 kPa/m). Now if you think of this body of water as a body (basin) of water-saturated sand, the sand grains can be thought of as packing together and supporting one another throughout the column. Therefore, the fluid pressure in


the pore space between the sand grains has not changed; it still varies with depth and it still varies according to the density of the fluid.

The total overburden pressure, referred to as the lithostatic pressure, is the sum of the pressure exerted by the column of fluid plus that exerted by the column of sediment. But because the column of sediment is porous, it exerts a pressure per unit area that is only slightly greater than that of the water. The variation of the lithostatic pressure (i.e., the variation of the sum) with depth is also expressed as a pressure gradient, just like that of the hydrostatic gradient. These gradients will vary, depending on the thickness (i.e., height) of the fluid column, the salinity of the water, the porosity of the sediments, and the minerals making up of the grains or sedimentary deposits.

Because the composition of typical reservoirs, at least in general terms, is often quite similar, the reservoir pressure gradient can be expressed simply in terms of the weight of the fluid (often measured in pounds per gallon - ppg - or kg/m3). This raises one of the key points in drilling: the reservoir pressure must be exactly offset by the pressure exerted by the fluid in the wellbore of the drilling well.

Unfortunately, prediction of the exact lithostatic pressure is difficult. The pressure gradient can be influenced by a number of other geological and geochemical processes, causing it to deviate from a predicted “normal” trend. We refer to these deviations in the subsurface pressure as “abnormal pressures.” Usually they are higher than expected but sometimes can be lower.

One of the most common causes of abnormal pressures is rapid sedimentation. Normally deposited clastic sediment (silt, sand, clay) will be compacted as additional material is sedimented on top of it. The clays, in particular, will lose much of their interstitial fluid and will be compressed into shale. As the sediments are buried deeper, the sands and silts compact somewhat, but the clays/shales are squeezed and lose more and more of their interstitial water. If the rate of sediment deposition is so great that the water within the clay/shale cannot escape, it will, therefore, help carry the overburden load, resulting in abnormally high subsurface pressures.

This kind of pressure variation can also be exasperated by chemical diagenesis of the some of the minerals in the deposit. For example, the alteration of smectitic (montmorillonitic) clays to illitic clays results in an expulsion of interlayer “bound” water. If this water cannot escape from the compressing shales, or if is forced into interbedded sands/silts, abnormal pressure can develop. A similar situation can arise during the diagenetic alteration of gypsum (CaSO4 2H2O) to anhydrite (CaSO4 ) in the subsurface.

Another common cause of pressure variations in the subsurface is due to contrasts in the piezometric surface. The piezometric surface is the point to which the fluid in a reservoir will rise under a given pressure regime resulting from a difference in elevation. The difference between the distance from the reservoir to ground level and to this piezometric surface will determine the degree to which the measured pressure gradient is greater (or less) than normal.

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There are several other, but less common, mechanisms that contribute to the overpressuring of subsurface formations. Clay can act as a semipermeable membrane, allowing the process osmosis to inhibit the flow of water from compacting shales as a result of an increase in ion concentration. In deeply buried sediments, thermal expansion of water as well as thermal cracking of hydrocarbons both act to increase the volume of the fluids, and can cause abnormal pressures in the rock.

Another parameter that contributes to difficulties in the subsurface drilling environment is temperature. The temperature gradient, or geothermal gradient, is generally constant for a given region, although it may vary from area to area. Typically, the geothermal gradient is expressed in degrees per unit depth: the global average is about 2.6oC/100 m, although sedimentary basins show a surprisingly large range from less than 1.5oC/100 m to nearly 10oC/100 m. Sometimes a change in geothermal gradient in a well can be an indicator of abnormally pressured zones, although this is not always the case.

Although subsurface temperatures do not have as great an impact on drilling as subsurface pressures, a good knowledge of the geothermal gradient can help the geologist predict bottomhole temperatures (which, in turn, control to a major degree the type of stable hydrocarbon that may be found), as well as plan and interpret various technical aspects of petrophysical logging and formation evaluation.

Drilling equipment The basic drilling equipment of the early rotary rig has not changed significantly in nearly 100 years as far as function is concerned. The basic task is to transmit torque from a power source at the surface of the Earth to a bit at depth via a drillstem. We also need to have the capability to lengthen or shorten the drillstem as necessary and to regulate the force it exerts on the bit at the bottom of the hole. Finally, we need to be able to circulate a drilling fluid down the drillstem, through the bit, and back up the area between the outside of the pipe and the inside of the hole (referred to as the annulus), and we need to be able to control the pressures encountered in the subsurface as we drill deeper.

Clearly, this list of functions is not trivial. Because of the variety of environments in which drilling takes place (as discussed above) a rather wide range of drilling rig designs are in common use today.

Rigs and structures Rigs are generally classified as onshore or offshore. Onshore rigs are all generally very similar. Most modern onshore rigs are of the cantilevered mast or “jackknife” derrick type (see also the figures and descriptions in your readings). This type of rig allows the derrick to be assembled on the ground and then raised to the vertical position using power from the hoisting system. These various structures and components are made up of prefabricated sections that are readily moved to the location by truck, barge, helicopter, etc.


Once on location, the mast is usually set on a substructure several meters to as much as 12 m high. The top of this substructure becomes the floor of operations for the drilling crew. Rigs are rated according to their hoisting (or drawwork) horsepower, although sometimes classifications based on the mud pump horsepower is a better way to evaluate the drilling capacity of the rig. The larger rigs are capable of routinely drilling to depths of 9+ km (the deepest well in the world is just over 12 km) and can hoist loads of nearly 700,000 kg. Some modern rigs use an independent or supplementary hoisting system with hydraulic cylinders to support the heavy load generated by the string’s weight. The number of land rigs operating in North America is about 2,500 but fluctuates dramatically depending on season and economy.

Offshore drilling rigs fall into one of several categories, each designed to suit a certain type of offshore environment. One of the simplest, the barge rig, is a flat-bottomed vessel with a shallow draft that is equipped with a derrick and the other necessary drilling equipment. It is towed to the location and then has its hull filled with water, which allows it to rest on the bottom, providing a stable support for drilling activities. Obviously, this type of rig can only used in shallow water. Barge rigs are generally limited to drilling in water depths of less than about 3 m.

A submersible rig can be thought of simply as a larger version of a barge rig, and is capable of drilling in water depths up to 20 m. Often the hull of a submersible rig will have steel floats that can be filled with water which act as ballast to help stabilize the vessel on bottom.

A jack-up rig is designed to operate in water depths from about 10 m to 100 m. After being towed to the location, the legs of the rig are lowered until they rest on the floor of the ocean or lake, and the deck is levelled at about 20 m above the surface of the water. Most jack-up rigs have four or five legs, which are usually slightly angled for increased stability. When moving to a different location, the legs are simply raised high above the deck and the rig towed (admittedly slowly!) by another vessel.

Unlike other offshore vessels, the semisubmersible drilling rig does not rest on the seafloor. This type of rig consists of a floating deck supported by submerged pontoons. It is kept stationary by a series of anchors and mooring lines, and, in some cases, position-keeping propellers. Semis can either move under their own power or be towed to their location. They are best suited for water depths of 100–600 m. Although the semi can operate in deeper water than a jack-up rig, it is still limited by the capabilities of the mooring equipment.

Drillships are self-propelled vessels capable of drilling in water depths of as much as 2 km or more. They are most often utilized for very deep- water drilling at remote locations. As of 2002, the deepest water in which petroleum well drilling has been done is ~2,800 m. Like the semisubmersible rig, a drillship must maintain its position at the drilling location by anchors and mooring lines, or by computer-controlled dynamic positioning equipment. A series of controllable propellers, or thrusters, shift position and speed to

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maintain the ship over the wellbore. The drilling slot, or moon pool, is through the ship’s midsection.

Structure rigs or often referred to as platform rigs, are mounted on a fixed drilling and production platform, with all the necessary equipment secured on the deck. The derrick and substructure are usually capable of moving (or skidding) to slightly different positions on the platform structure. It is not uncommon to drill and complete 20 or more wells on the same platform. These “permanent” drilling and production structures vary widely in design as dictated by the environmental conditions (e.g., wave climate, water depth, ice conditions etc) at the site.

Basic drilling functions Depending on what kind of surface environment is encountered, the rig design can vary significantly. However, all drilling rigs are designed to accomplish four basic functions: hoisting, rotating, circulating, and controlling. Be sure to closely examine and study your textbook assignments, paying particular attention to the illustrations of the various rig components as you read through these notes.

The components of a rig that perform these functions are illustrated in your textbooks. The derrick supports the crown block and travelling block, which are operated via the drawworks and its drilling line. The kelly and swivel are connected to the drillstring and are suspended from the hook beneath the travelling block, allowing the kelly and drillstring to be turned by the rotary table. The drilling fluid circulation system pumps mud from the pits through standpipe, hose, swivel, and drillstem, finally returning the mud and cuttings up the annulus and back to the pits. The blowout preventer and associated equipment allow the drilling crew to maintain control over subsurface pressures.

The derrick, or mast, and the substructure it sits upon, support the weight of the drillstem and allow vertical movement of the drillpipe. The substructure also supports the equipment that is on the rig floor and provides workspace for the crew. The drillstring must be removed from time to time to change bits, test sections of the well, or replace damaged pipe. The length of drillpipe section that can be disconnected and stacked to one side of the derrick is determined by the height of the derrick. A single joint of drillpipe is about 9 m long. A derrick that will allow the pulling and stacking of pipe in three-joint sections (~27 m) must be about 45 m high.

The drawworks is a spool or drum upon which heavy steel cable (the drilling line) is wrapped. From the drawworks, the line is threaded through the crown block at the top of the derrick and then through the travelling block, which hangs suspended from the crown block (refer to the figures in your reading assignments). By reeling in or letting out drilling line from the drawworks, the travelling block and suspended drillstem can be raised or lowered.

The swivel allows the drillstem to rotate while supporting the weight of drillstring in the hole and providing a pressure-tight connection for the circula-


tion of drilling fluid. The drilling fluid enters the swivel by way of the gooseneck, a curved pipe connected to a high-pressure hose. Connected to the swivel is the kelly, a 10–12 m length of hollow steel, which is used to transmit the rotary movement of the rotary table to the drillstring. The kelly fits through a corresponding opening in the kelly drive bushing, which, in turn, fits into the master bushing set into the rotary table. The rotary table is turned by the rig’s power source, the table turns the bushings, the kelly bushing turns the kelly, the kelly turns the drillpipe, and so on, down to the bit. Most geologists use the term “drillstem” to refer to the entire structure: the kelly and the attached drillpipe, drill collars, bushings, and bit, whereas the term “drillstring” refers just to the drillpipe and drill collars.

Circulation of the drilling fluid in order to carry cuttings up the hole and to cool the bit is an essential function of any rotary drilling rig. The main part of the circulation system is the mud pump. The mud pump pushes the drilling fluid from the mud pit or mud tanks up the standpipe to a point on the derrick where the rotary hose connects the standpipe to the swivel. This flexible, high-pressure hose allows the travelling block to move up and down in the derrick while maintaining a pressure-tight system. The circulating drilling mud moves through the swivel, kelly, drillpipe, and drill collars, exiting through the bit at the bottom of the hole. The mud then moves up the annular space between pipe and hole carrying the drilled rock in suspension. At the surface, the mud leaves the drilled hole through the return line and falls over a vibrating screen called the shale shaker. This device screens out the cuttings (drilled fragments of rock) and dumps some of them into a sample trap and the rest into the reserve pit. Once cleaned of large cuttings, the mud is returned to a mud tank, from which it is again pumped down the hole.

As mentioned earlier in this section, controlling the subsurface pressures encountered while drilling is an important part of the operation. One of the purposes of the drilling mud is to provide a hydrostatic pressure to counterbalance the pore pressure of fluids in porous and permeable formations. If this balance is not maintained (such as when drilling through overpressured zones as discussed above) the higher pressures of the subsurface can lead to a blowout, with the formation fluids forcefully erupting from the well, often igniting, and endangering the crew, the rig, and the environment.

The blowout preventers are a series of sealing elements designed to close off the annular space between the pipe and hole where the mud is normally returning to the surface. By closing off this route, the well can be shut-in and the mud and/or formation fluids forced to flow through a controllable valve. This valve allows the crew to control the pressure that reaches the surface and to follow the necessary steps for restoring a balanced system.

Drillstem and drilling fluid These two components are probably the most complex portions of the drilling system and play an important role in the efficiency of the drilling operation. A large part of the effort in drilling a well is spent on monitoring and maintaining a correctly and efficiently functioning drillstem and drilling fluid.

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The drillstring is made up of lengths of steel pipe. In North America the American Petroleum Institute (API) establishes standards for pipe sizes, as well as for variations on the thread types and joint lengths. Drillpipe is available in a variety of lengths but, as indicated above, is generally in sections that are about 9 m long and about 6–17 cm in diameter.

The drill bit is probably the most critical component of the drillstem. Bit technology has undergone more changes since the early days of rotary drilling than any other element of the drilling system. There are several types of bits, with the design being a function of the type of rock being encountered.

The oldest of the rotary bits, the drag bit, uses flat cutter blades to essentially scrap away the rock. These bits, though relatively simple and inexpensive, and still used for drilling soft formations such as shale, have been largely replaced by other types.

The rolling cutter bit, also called a roller cone bit, three cone bit, or rock bit, is the most commonly used today. The cones of this bit are designed to individually roll as the bit turns on the bottom of the hole. While the cones distribute the weight of the drillstem, their teeth bite into the rock, gouging and scraping away the cuttings, which are then carried to the surface by the circulating mud. The toothed cones mesh together to provide a self-cleaning action. Bit cleaning is also done by the flow of drilling mud from nozzles, or jets, through which the fluid passes with high velocity. Roller cone bits vary according to the type, number, and configuration of their teeth and the type of bearing used to join the cones to the body of the bit. Steel-tooth bits have long, widely spaced teeth for drilling soft rock formations, whereas models having shorter, closely-set teeth are used for harder rock types.

Diamond bits operate similarly to drag bits, in that they have no moving parts such as cones or bearings, but rely on industrial diamonds to abrade the formation. The diamonds are set in a high-strength steel matrix, with a pattern and spacing designed for the drilling conditions expected. The location of the drilling fluid outlets is also critical in the design of the diamond bit in order to allow cuttings to be carried out from under the cutting surfaces. Although diamond bits are much more expensive than roller cone bits, they can be economical on a cost per meter, or meter per hour basis, especially in deep wells with hard formations.

Most wells are drilled with simple water (i.e., not mud) until a depth is reached where hole conditions dictate a need for a fluid other than water. The addition of clay and chemicals to the water permits the adjustment of viscosity, density, and other properties to improve hole cleaning and prevent sloughing of soft formations or various types of formation damage.

In most cases the circulating fluid utilized in a rotary drilling operation is a water-based mixture of clays, suspended solids, and chemical additives. In some cases, oil can be added to the fluid or the entire system may be converted to an oil-based mixture. A small percentage of wells are drilled with air or foam as the circulating fluid for part of the drilling operation. For example, because evaporites (salts) are highly water soluble, they are often drilled with an air or


oil-based mud system. Whatever the case, the properties of the drilling fluid must be such that it perform the following functions: • control subsurface pressures • remove cuttings from the hole • cool and lubricate the drillstem • aid formation evaluation and productivity

As we have discussed above, the subsurface pressures are controlled by adjusting the density of the drilling fluid so that a balance is maintained between the drillstem hydrostatic pressure (which is due to the column of drilling fluid) and the subsurface pore pressure. Obviously, given the variable subsurface pressure and temperature conditions, this balancing act can be difficult. If the formations are abnormally pressured, an unexpectedly high pore pressure can cause a flow of formation fluid into the wellbore. This further lightens the already underbalanced mud column, and can very quickly lead to a complete loss of control of the well. On the other hand, a mud column that has been “weighted up” (i.e., made heavier by mineral additives, such as barite) may adequately control the pressures in an overpressured formation but impose such a force on a normally pressured formation that it fractures the formation, allowing unobstructed flow of drilling fluid into the formation. This is referred to as lost circulation. Lost circulation such as this can also occur when naturally fractured or cavernous formations are suddenly encountered. The loss of drilling fluid results in a decrease in the amount of fluid in the column, which in turn translates into a drop in pressure. This drop in pressure may permit the fluids from other formations to flow into the wellbore. You can readily see how easily these situations can quickly go from bad to worse to disaster.

This chain of events must be prevented from ever having a chance to get started. While the drilling fluid density allows control of pressures, other properties of drilling mud allow it to form a protective cake of clay particles on the wall of the hole. This is referred to as mudcake. Development of mudcake is important in preventing excess fluid loss into permeable formations and preventing sloughing, or caving-in, of the sides of the hole.

Viscosity is the drilling fluid property that is important in accomplishing the task of removing cuttings from the hole. Mud must have the proper viscosity to lift the rock cuttings out from underneath the bit and carry them up the annulus to the surface. In addition, a drilling fluid must exhibit sufficient viscosity to hold the cuttings in suspension when circulation stops, and prevent them from settling to the bottom of the hole, collecting around the bit, and making the pipe stick in the hole. However, the mud must also easily liquify upon resumption of pumping and it must release the cuttings easily at the surface.

While not a property of the drilling fluid itself, the velocity at which the fluid is circulated is also important to the proper performance of the hole-cleaning function. Most drilling systems circulate the mud at a velocity similar to that of a normal walking speed. It is also important for geologists to know the velocity of the mud circulation so that the sample of cuttings can be correlated to the proper subsurface depth.

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The combination of weight on the drill bit (4,000–45,000 kg) and rotational speed (50–200 rpm) creates a large amount of frictional heat within the bit that must be dissipated by the circulating fluid. Lubricants may also be added to the mud system that can help reduce friction at the bit, between the drillstring and hole, and within the drillstring itself. Air or foam drilling fluids are particularly efficient at performing this cooling function.

The geoscientist must conscientiously monitor the drilling fluid properties to insure that the interaction between the mud and the formation does not damage the formation. Many types of formations can be irreparably damaged by the invasion of mud and mud filtrate. Oil-based mud in gas zones and freshwater muds in zones containing water-sensitive clays can reduce both porosity and permeability of the producing formation. Oil-based muds also make it difficult to evaluate potential producing horizons.

A wide variety of additives are available to help control the density and viscosity of the drilling fluid. Some common examples are:

• Bentonite: a clay mineral added to freshwater mud systems to improve the properties of a natural mud system;

• Attapulgite: a clay mineral added to salt-water based muds;

• Barite: barium sulfate having high specific gravity; added as weight; lead and iron compounds are also used for this purpose;

• Chrome lignosulfonates: chemical thinners used to decrease viscosity;

• Polymers: long chain molecules that increase viscosity; and

• Lost circulation materials: any of a variety of items that can plug fractures; often anything found around the rig, such diverse substances as walnut hulls, shredded cellophane, mica flakes, and vegetable fibers.

Drilling the well The seismic work has been done; the geologist has mapped and evaluated the reservoir, source rock, and structure of the prospect; the company land representatives have obtained all the necessary leases from the landowners, and all the required permits have been filed with the proper governmental authorities. We’re ready to drill the well. What happens now?

The actual planning of a well usually begins with the geologist. This is certainly true in the case of exploration wells, and usually true in the case of development wells. Because the geologist has studied both the surface and subsurface, he/she is the single most important individual in the planning process and is normally the individual responsible for outlining the objectives of the proposed well, including giving a prognosis of the formations expected, their extent, and the likelihood of success.

However, a rigorous economic analysis of the proposed well will probably be done by the geologist working in concert with engineers and land persons. The geological interpretation of the data is the basis of an estimate of the well’s productivity and, if successful, a production schedule. These are then combined


with estimates of well costs and product prices to determine the profitability of the well. If the venture meets the company’s economic standards and corporate objectives, the proposal is approved.

Based on the geologist’s well proposal, the next step is usually the preparation of a detailed drilling program and cost estimate. This plan is based on the past performance of drilling operations in the same basin or in similar areas, and the current costs of drilling services and well-completion materials. It is important that the geologist’s best estimates of formation depths, occurrence of abnormal pressures, pay thicknesses, and potential drilling problems be considered in the planning.

The exact requirements of the program vary widely, even with same areas of the basin. Generally the items to be included are: depth, commencement date, anticipated drilling rates, formations to be encountered, hole size, casing sizes and depths for setting casing, logging operations, and testing and completion programs. These are all necessary for the negotiation of a contract between the operating company and the drilling contractor.

Almost all oil and gas wells today are drilled by contractors rather than the actual energy producing companies, primarily because of the large capital investments involved in owning and operating drilling rigs. The operating companies can have their wells drilled under several common contract alternatives including:

• turnkey contract, which requires that the operator pay a fixed amount to the contractor on completion of the well, while the contractor furnishes all the material and labour and handles the drilling operations independently;

• footage contract, in which payment is on a rate-per-foot basis; and

• a daywork contract, which compensates the contractor on a rate-per-day basis.

Once the contract(s) are finalized, the drillsite is surveyed and staked to ensure that the rig is located at the exact location the geologist recommended. Obviously, in these days of satellite navigational aids and electronic triangulation, this is an easy task; however, many historical examples can be cited in which the prospect was not successful in part due to incorrect location.

Next, the land is cleared and levelled (in the case of an onshore well). In wet or swampy areas, the entire location may require draining, trenching, or other modification to prevent the heavy rig equipment and supply trucks from floundering in mud. A constant water supply is important and sometimes a shallow freshwater well will be drilled first to establish this source of water. The mud pits are excavated and lined with plastic. At the staked well location, a cellar is dug to accommodate components of the surface equipment that will be below ground level when the drilling is finished and the well completed. A large diameter conductor hole is started in the center of the cellar and lined with pipe. In swampy areas, the conductor pipe is often driven into the ground to depths of as much as 30 m.

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Next, the rig is moved in, beginning with the substructure (the framework that supports the derrick) and the drilling floor equipment. If a jackknife rig is used, the derrick/mast is hoisted upright using the hoisting equipment. All of the auxiliary equipment must be installed next: circulation system pumps, tanks, mud-cleaning devices; engines, generators and power transmission equipment; storage facilities and living quarters for the crew; and the electricity, water, sewage lines. This entire setting-up process can take anywhere from several days to several weeks, depending on the size of the rig, the remoteness of the location, and the complexity of the planned drilling program.

In general, various service company personnel are required to be on location. These individuals are on hand for special jobs, such as installing and cementing casing, mechanical logging, and, in the event of lost pipe or downhole tools, “fishing.” However, just as rigs vary greatly in their design depending on the complexity of the environment and drilling program, so do the number and responsibilities of the people involved in the operation. A small, onshore drilling rig, such as in southwestern Manitoba, may have a crew of only four or five individuals, while an offshore rig drilling a deep, exploratory well at a remote location may have several crews and groups of specialists, totalling more than 50 persons.

The drilling engineer or his/her representative most often is the person responsible for logistics, planning of day-to-day transportation and equipment inventories, and maintaining accurate records of the operation. While living at or near the location, the drilling engineer is in frequent contact with a company drilling supervisor at the area office, who, in turn, is perhaps in charge of several drilling operations going on simultaneously. The drilling supervisor is not usually present at the drilling location.

The tool pusher is the person in charge of the rig and overall day-by-day drilling operations. As the contractor’s senior representative on location, the tool pusher directs the drilling crew and is responsible for the rig and its equipment. On mobile offshore rigs, the tool pusher may share the responsibilities with a captain, who is in charge when the vessel is moving.

Reporting to the tool pusher is the driller, who operates the drawworks/hoist and the rotary table, and directs the roughnecks and the derrickman. The derrickman works on a small platform on or in the derrick, guiding the pipe as it is moved while running in or out of the hole. Often the derrickman is also responsible for monitoring the circulation system while drilling is under way. The roughnecks handle the lower end of the drillpipe during trips in or out of the hole. They operate the tongs required to connect or break the pipe joints. Roustabouts, or rig helpers, maintain equipment and supplies, help repair the rig, and perform various other jobs.

The service company personnel are on location for special jobs, such as installing and cementing casing, logging, and “fishing” for broken pipe or lost tools.


Drilling progress With the rig in position and the conductor pipe in place, drilling begins. Obviously, the largest bit is the first to be used. The geologist has designed the drilling program so that the initial bit will drill a hole large enough for the subsequent casing and can accommodate successively smaller bits and tools further downhole. The number of casings necessary to reach the target depth safely will determine the initial hole size.

Weight is applied to the bit and the rotary table begins to turn the kelly. As the bit grinds away at the bottom of the hole, the mud pumps circulate the cuttings up the annulus. The kelly slowly moves downward until the top of the kelly and the attached swivel are near the drilling floor. At this point about 9 m has been drilled. From now on, each time a kelly length has been drilled, another joint of drillpipe is added to the drillstem. The kelly and attached drillstring is lifted up in the derrick until the kelly bushing has cleared the drill floor and the joint between the kelly and drillpipe is visible. Toothed wedges (called slips) are set in the rotary table to grip the drillstring and allow it to hang motionless while the crew unscrews the kelly with the tongs, which are simply oversized pipe wrenches. Once the joint is broken, the kelly is hanging freely from the hook, and the crew can swing it over to the new length of pipe that is waiting. The kelly is then screwed into the new joint and both are lifted up into the derrick and swung over the drillstring which is being held by the slips. The driller lowers the assembly and the crew carefully screw together and tightened the two ends. The slips are removed and the entire assembly is lowered back into the hole to drill another joint length. After each kelly has drilled down 9 m, the connection process is be repeated.

At some point it usually becomes necessary to pull the whole assembly out of the hole. This is referred to as tripping (or tripping out and tripping in) and is usually done to change the bit or perhaps to install more casing. When making the trip, the drillpipe is handled in stands of usually of two or three joints each (18–27 m). Some large rigs have an automated pipe handling system with robot arms at different levels in the derrick to perform the job very quickly. Tripping in or out can take many hours to days in a deep hole.

We have mentioned casing several times in the above discussion. Casing is usually set for one of several reasons:

• to protect shallow freshwater aquifers from contamination by the drilling fluids;

• to support the unconsolidated, low pressure formations near the surface and prevent the loss of drilling mud as its weight is increased to permit deeper drilling; and

• to provide a base for well control equipment such as blowout preventers.

As you can imagine, the installation and cementing of casing can be a complex operation, depending on the depth of the hole and the number and sizes of previous casings (i.e., uphole casing). For example, the volume of cement that is needed to fix the casing at the required depth must be very accurately

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calculated. To do this, the true three-dimensional aspects of the hole must similarly accurately known.

When not tripping, the driller is doing what we would expect: drilling! Normally modern rigs have the control console on the drill floor, and it is the driller’s task to monitor and adjust several important drilling parameters. The weight on bit (WOB) is adjusted by lowering and raising the drillstem to allow more or less of its weight to rest on the bit. The driller also monitors rotary speed to make sure that the combination of revolutions of the bit and WOB is correct for efficient drilling. A mud level recorder, torque indicator, and pump pressure gauge allow the driller to be informed of any anomalous situations that could indicate a potential problem. Another important device is the drilling rate recorder, which keeps a log of depth drilled versus time.

As drilling proceeds, the deeper formations become harder to drill and the problems associated with drilling begin to become more obvious. Because of the great stress placed on downhole equipment, it is easy to imagine that eventually mechanical failure or adverse hole conditions will result in part of the drillstem becoming lost or stuck in the hole. When this happens, retrieving this lost or stuck equipment is referred to as fishing. Some of the more common situations requiring fishing jobs are:

• Differential sticking occurs when the pipe comes in contact with a permeable formation and the string is pushed against the side of the hole by the pressure differential existing between the mud column and the formation.

• Key seating occurs if the hole is crooked; in crooked holes the drillpipe can cut into the wall of the hole, creating a slot that grips the pipe at the coupling when the string is pulled out.

• Soughing shale is a problem that results from shale cavings breaking off from the sides of the wellbore. These shavings form bridges, or tight spots, when they gather at irregularities in the hole.

• Excessive mud cake formation on the walls of the hole can cause the drillstem to become wedged.

• Fatigue failures, which are the result of metal fatigue, can cause the drill string to break in two (or “twist off”).

• Foreign objects, such as bit cones that may break off or a tool that may be dropped down the hole by a rig worker, must be retrieved before drilling can continue.

In addition to these downhole problems, another very important consideration that was already mentioned is maintaining the proper pressure or pressure balance. Everyone who has watched television is probably familiar with the results of a blowout, the classic “gusher’’ spewing oil and gas high into the air, and broadcasting the success of the drilling with a tremendous roar. Today, of course, a gusher is exactly what we do not want when drilling a well.


As mentioned earlier, formation pressure results from fluid pressure gradients, which should be offset by the column of drilling fluid in the hole. A flow of formation fluid into the well is referred to as a “kick.” A kick occurs when the hydrostatic pressure due to the column of fluid is insufficient to prevent the flow of formation fluids into the wellbore. This can be the result of abnormal pressures in the subsurface or failure to keep the hole full of mud or a combination of causes. It is particularly important to maintain the level of mud when pipe is being tripped out of the hole. This is done by adding sufficient mud to replace the volume of removed pipe. As discussed above, lost circulation occurs when the mud weight is heavy enough to fracture the formation or when a formation is porous and permeable enough to allow the entry of large volumes of drilling fluid. This can also cause a sudden drop in mud level.

The fluids in the subsurface formation are under pressure. When a volume of the formation fluid (gas, oil or water) flows into the wellbore it begins to rise through the drilling mud because of its lower density (relative to the drilling fluid). As the introduced material rises to the surface, the decreasing size and weight of the volume of mud in the mud column above it allows this material to expand as it nears the surface. This increase in “bubble size,” in turn, pushes mud out of the hole, further decreasing the bottomhole pressure and allowing even more formation fluid to enter the hole. If the kick is not controlled very quickly, the condition can deteriorate into a full scale blowout.

Review questions 1. Why are geoscientists interested in drilling technology?

2. What was probably the single most important “event” in the history of drilling technology?

3. What are the main differences between drilling on land and drilling offshore?

4. Explain how sedimentation rates can influence subsurface pressures.

5. What is the function of the drilling fluid?

6. List, in order, the hierarchy of positions/personnel on a typical drilling rig.

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Unit 6 The Petroleum Source Rock

Topics Maturation Geothermal gradients, subsurface heat, and subsurface pressure Characterizing source rocks

Introduction We continue our examination of the petroleum world by looking at the details of source rock geology. The source and maturation part of the petroleum story is very important from the standpoint of predicting whether the sedimentary basin will have any petroleum reserves, and, if so, what type of products will likely be found and at what depth.

Learning objectives By the end of this unit you should be able to: • outline the maturation process;

• differentiate between the various types of organic matter from a compositional perspective;

• predict what type of petroleum product will be generated by different types of sources rocks;

• quantitatively evaluate the depth and temperature ranges of source rock maturation;

• discuss the conversion of organic matter into kerogen and then into petroleum;

• compare the attributes (both good and bad) of high geothermal gradient basins versus low geothermal gradient basins;

• calculate subsurface pressures; and

• describe a good source rock.

Learning activities 1. Read the study notes. 2. Answer the review questions. 3. Continue reading pages 125–189 in Resources of the Earth. 4. Continue reading pages 1–113 in Our Petroleum Challenge. 5. Complete Assignment 2 and send it to the Distance and Online Education

Student Services office.


Study notes Key terms blowout catagenesis diagenesis geopressured zone geothermal gradient hydrostatic pressure kerogen lithostatic pressure maturation metagenesis mud oil window overpressured zone Type I kerogen Type II kerogen Type III kerogen Type IV kerogen

Maturation Maturation is the complex process through which biological molecules, created by living organisms, are converted into petroleum. The early stages of this alteration are called diagenesis by petroleum geologists. During diagenesis, an intermediate form of organic matter, called kerogen, is formed. Importantly, kerogen is NOT oil or gas but rather is the actual precursor to oil and gas. It is created by the breakdown of complex biologically-formed molecules. The diagenetic reactions create newly formed and much simpler molecules, and usually involve the loss of much of nonhydrogen and carbon compounds like ammonia, carbon dioxide, and water.

Microscopically, kerogen is extremely complex and nondescript. It can be seen as buff coloured to yellow-orange to brown-black particles, and amorphous clusters of material. Since this material likely originated from many different kinds of living organisms, with different kinds and proportions of biological molecules, kerogen does not have a consistent chemical composition. Indeed, different types of kerogen will yield different types and amounts of petroleum.

Geologists have found it convenient to group kerogens into four fundamentally different classes. These are universally called simply Type I, Type II, Type III, and Type IV. Type I kerogen is derived mostly from the remains of algae. When it matures, it yields mainly crude oil. It is also capable of generating the most petroleum of all the kerogen types. Type II kerogen consists mostly of amorphous bacteria material and byproducts derived from the physical and mechanical breakdown of other one-celled plants and animals. This kerogen is also oil-prone but yields more natural gas than Type I. Type III kerogen, derived from the higher land plants, is sometimes known as coaly or humic

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kerogen. The humic material in Type III kerogen has a low capacity to form oil and yields mostly natural gas. Type IV kerogen consists mostly of inert particles that have been highly oxidized before burial, like charcoal. It has practically no ability to generate oil and can generate only small amounts of gas.

The geochemistry of the resulting crude oil can be linked to the kerogen type and ultimately to original organic matter type. Usually land-derived, nonmarine organic matter deposited near continental drainage areas (Type III kerogen) will form mostly gas, but any oil formed will be low sulfur, paraffinic to paraffinic-naphthenic crude oils. Marine organic matter, particularly types derived from marine animals (Type II kerogen), tends to yield high sulfur aromatic crude.

The petroleum is actually generated when the intermediate material, kerogen, is subjected to the increased temperatures that accompany sediment burial. The alteration of kerogen to petroleum is called catagenesis and is similar to other thermal cracking reactions. The large kerogen molecules decompose upon heating, to yield smaller molecules of petroleum. These reactions usually require temperatures greater than 600C. At lower temperatures, during early diagenesis, a form of natural gas, called biogenic methane or marsh gas, is generated through the action of microorganisms that live near the earth’s surface. However, most of the vast quantities of biogenic methane that are probably generated cannot be trapped and thus will be lost to the atmosphere.

The subsurface temperature range between about 600C and 1750C is commonly referred to as the “oil window.” This is the principal zone of oil formation. It begins at burial depths of about 1 to 2 km in most sedimentary basins and ends at depths of 3 to 4 km in most areas depending on the geothermal gradient.

The first oil generated is heavy and tends to be richest in aromatic and NSO compounds. As burial and temperature increase, the oil becomes lighter and more paraffinic. At temperatures much above 1750C, the generation of liquid petroleum ceases, and gas formation becomes dominant. When formation temperatures exceed about 2250C, most kerogen has used up its petroleum-generating capacity. Source rocks at this level of cooking are termed overmature. However, some methane can still be created, even at these very high temperatures, by the breakdown of the larger, heavier molecules of previously generated crude oil. This final stage of conversion of organic matter is called metagenesis.

Since the conversion of kerogen to petroleum is basically a series of chemical reactions, time also plays a major role in this process. Young Tertiary rocks, for example, must be deeply buried or have high geothermal gradients in order to generate significant amounts of petroleum. Although generation, migration, and entrapment have been documented in rocks as young as 1 million years old, major petroleum accumulations have not been found in rocks less than 10 million years old. On the other hand, some older Palaeozoic and Mesozoic source rocks may not have been buried very deeply, perhaps only to the uppermost part of the “oil window,” but have still generated petroleum because


of the time factor. However, in most petroleum occurrences, temperature appears to be a more significant factor than time.

Geothermal gradients, subsurface heat, and subsurface pressure Temperature, modified by time, is clearly instrumental in the formation of most major petroleum accumulations. During oil-well drilling, formation temperatures can be measured by lowering self-recording thermometers into the borehole. When this is done for various depth levels, the geothermal gradient can be determined. The world-wide average geothermal gradient is about 260C/km. Gradients measured in sedimentary basins around the world typically range from as low as about 180C/km to as high as 550C/km.

In a basin with a low geothermal gradient, the first formation of oil begins at fairly deep subsurface levels, but the oil window in these basins will be quite broad stratigraphically. In contrast, a high geothermal gradient enhances the early formation of oil at relatively shallow burial depths, but it causes the depth range of the oil window to be quite narrow.

The magnitude of a petroleum basin’s geothermal gradient is most often directly related to the earth’s internal heat flow; it will be high where heat flow is high. Consequently, high geothermal gradients are often found in basins that are associated with active tectonic elements such as deformation, seafloor spreading and mountain building processes. Gradients will usually be low in basins associated with old, stable interiors of the continents, the craton. Gradients will also tend to be low in areas insulated by cool underlying rocks or thick, rapidly deposited sediments.

Locally, the geothermal gradient will be influenced by the subsurface rocks through which the earth’s heat must pass. It is important to remember that the thermal conductivity of rocks is inversely related to the geothermal gradient. It varies both with the rock type and the kinds and amounts of pore-filling fluids. Thus, the geothermal gradient will normally vary vertically through a stratigraphic sequence, and temperature will have a nonlinear relationship to burial depth.

The present-day geothermal gradient may be of less importance to maturation than paleogeothermal conditions, particularly in areas that have undergone large-scale tectonic uplift and erosion. This is because the chemical reactions (e.g., diagenesis, catagenesis) completed at higher temperatures are not reversible. It is therefore most important to be able to establish the highest temperature attained at some time in the geological past. Various measurement methods, or paleothermometers, have been devised to determine the maximum formation temperature of a source rock.

Subsurface pressure, like temperature, increases with depth, however it plays a relatively minor role in the petroleum-generation process. Nonetheless, pressure does have other important effects. The total overburden pressure exerted at any point in the subsurface is the function of two forces: the weight due to the overlying rock (lithostatic pressure) and pressure due to fluids contained within

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the pore spaces (fluid or pore pressure). Lithostatic pressure is transmitted via grain-to-grain contacts. It averages about 14 kPa/m (0.6 psi/ft). Fluid pressure is transmitted via the pore-to-pore communication network that extends to the surface and is called hydrostatic pressure. For typical subsurface water (which is usually saline), the hydrostatic pressure gradient is about 10.52 kPa/m or 0.465 psi/ft.

From this, we can see that pressure increases with burial depth and, in a normally pressured oil well, the fluid pressure is always slightly less and the lithostatic pressure slightly more than half of the total overburden pressure, at any depth. However, abnormally pressured rocks are sometimes encountered in drilling, often unexpectedly. This may cause serious problems in the drilling of the well and in the production of any hydrocarbons found. If the rocks are overpressured where a permeability barrier seals pore fluids off from communication with the surface and the fluid pressure becomes high, the pressure exerted by the drilling mud may not be great enough to hold back the fluids in the rock, causing a “blow out.” Underpressuring, or abnormally low fluid pressure, is less common but it too can cause problems. When high-pressure drilling fluids enter the lower-pressured formation, loss of mud circulation can occur and the formation can actually be damaged by plugging up the pores in reservoir rocks. The loss of mud circulation, in turn, can lower the mud column in the well and cause even the normally pressured formations to blow out the well.

Although abnormally high pressures may be found in various sedimentary basins, they are particularly prevalent in rocks deposited in delta environments where sedimentation may be too rapid for fine-grained shales to compact and dewater. In this case, some of the weight of the overlying sediment, which is normally taken up by grain-to-grain contacts in normally compacted rocks, is taken up by the fluid in the pore spaces.

Characterizing source rocks Source rocks are any rocks in which sufficient organic matter to form petroleum has been accumulated, preserved, and thermally matured. Organic particles are usually fine-grained, and will settle out most easily in quiet-water environments. Therefore, source rocks are most commonly fine-grained rocks, particularly shales.

One of the most important factors in determining whether an organic-rich rock will become a source rock is its thermal maturity. However, some potential source rocks have never reached this thermal level. An example is the widespread oil shales of the Rocky Mountain region. In these rocks artificial maturation can be induced by heating the rocks to temperatures of about 5000C. This process is called pyrolysis.

Preservation of organic matter is usually harder to achieve than its production. As we learned in lesson 1, on land, with the exception of lakes and coal swamps, most organic accumulations are rapidly destroyed through oxidation


and biological activity. Most commonly, organic matter that eventually becomes oil is preserved in marine environments.

Rapid deposition is one way to avoid the destruction of organic matter and is characteristic of source rocks in thick sediment wedges, such as deltas. Rapid deposition, however, leads to dilution of the organic matter by sediment. Some shale source rocks found in rapidly prograding deltas have organic contents of only 1%. Usually shale requires a higher organic content than this to be an adequate source rock.

However, deltas often have excellent source/reservoir rock geometries, and structures are developed early in response to the sediment load. In such cases, migration and accumulation of petroleum is probably more efficient than usual, and even such organic-poor shales make adequate source rocks.

However, in most cases, marine shales with organic contents high enough to be petroleum source rocks are deposited slowly, under oxygen-free conditions that prevent organic destruction. This occurs most commonly in restricted marine environments, where a basin is silled or otherwise prevented from easy communication with the open ocean.

Review questions 1. Describe kerogen.

2. List the different types of kerogen and identify the main source material.

3. What, in terms of temperature, is the oil window?

4. Does time play a role in source rock maturation; discuss.

5. Why does the temperature in a sedimentary basin usually have a “nonlinear” relationship with depth?

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Assignment 2

1. List the five factors needed for commercial accumulations of petroleum to occur.

2. When commercially important natural gas is found, its generation can usually be related to either one of two factors. What are they?

3. As a general rule, how does the chemistry and density of deeply buried and/or old oil differ from that of young, shallow oil?

4. List three of the four common rock types that can be source rocks for petroleum.

5. What is a blowout and explain how blowouts occur.

6. Discuss the role of the drilling fluid in well drilling and list the properties that can be adjusted to optimize the functions of the drilling fluid. Explain how these properties are adjusted.

7. Sketch a typical land-based drilling rig and label all the major components.

8. What is/was the NEP and briefly summarize the impact of this entity on Canadian energy exploration/exploitation.

9. To which of the basic drilling functions do the following components of the drilling system correspond? Briefly describe the roles each play in the drilling operations. a. Mud pump b. Kelly c. Drawworks d. Blowout preventor

10. Where is the birthplace of Canada’s modern petroleum industry?


Notes

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Unit 7 Petroleum Migration and the Petroleum Reservoir Rock

Topics Migration The reservoir The trap Giant fields The seal

Introduction After having mastered the geochemistry and diagenesis of source rock geology, the next step in our continuing examination of the inner workings of a petroleum prospect is to tackle the migration and reservoir story. In addition, we will touch on the importance of giant oil and gas fields and their role in the world’s energy resource picture.

Learning objectives By the end of this unit you should be able to: • differentiate primary migration from secondary migration; • compare and contrast long-range migration versus short-range migration; • summarize the main attributes of a good reservoir rock; • discuss permeability and how permeability is evaluated; • differentiate primary porosity from secondary porosity; • characterize the components of a trap; • outline the different types of common traps; • summarize the importance of giant oil and gas fields; and • describe a seal or caprock.

Learning activities 1. Read the study notes. 2. Answer the review questions. 3. Continue reading pages 125–189 in Resources of the Earth. 4. Continue reading pages 1–113 in Our Petroleum Challenge.


Study notes Key terms caprock closure compaction darcy fracture porosity giant field intercrystalline porosity intergranular porosity intragranular porosity

permeability porosity primary porosity primary migration secondary porosity secondary migration stratigraphic ramp stratigraphic trap structural trap

Migration Migration is the most poorly understood and least measurable stage in the cycle of petroleum generation, migration, and accumulation. Primary migration, which involves the expulsion of petroleum from the source rocks, is still a great mystery. Various models for primary migration have been proposed, although none appears to have all the answers.

Secondary migration processes, which involve the movement of petroleum through permeable layers (carrier beds or conduits) to the trap, are better understood. Nonetheless, it is still often very difficult to apply these concepts to the exploration of a particular area. Although secondary migration is governed primarily by buoyancy differential between the petroleum and water, which tends to move petroleum relatively upward by displacing more dense water, the tectonic and hydrodynamic regime also becomes important. Consequently, a wide variety of spatial arrangements between source rocks and carrier/reservoir beds is possible.

In older, more consolidated basins where there is little disruptive tectonic deformation, secondary migration occurs updip along extensive stratigraphic “ramps” that carry petroleum from the deep basin oil window to the shallower trap areas. In these cases, very long-distance migrations are the norm, and large accumulations may result if the drainage area is particularly large. For example, all the oil that is present in the Palaeozoic sequence of rocks in southwestern Manitoba was derived from maturing source rocks hundreds of kilometres to the south and southwest.

In contrast, secondary migration in young basins that are less consolidated involves more movement through fractures and faults. In these situations, secondary migration is usually only over relatively short distances.

Migration is also often influenced by the water released through compaction of shales and other fine-grained sediments and by the presence of geopressured zones. Thus, although we can ascertain the general movement and direction of oil migration, the actual pathways are more difficult to predict. Migration is further complicated in that it can occur very quickly, over a short geological

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time interval, or intermittently over a long time span, and can take place either early or late in a basin’s history.

Thus, while the concept of secondary migration is simple to understand, its application to exploration is often the most difficult task the petroleum geologist must master.

The reservoir There are two fundamental physical properties that a good reservoir must have: • porosity, or sufficient void space to contain significant volumes of

petroleum; and

• permeability, or the ability of petroleum to flow into, or out of, these void spaces.

Consequently, the only effective pores are those that are interconnected and permit fluids to flow through them.

The only common rock types that normally have this favourable combination of porosity and permeability (and therefore the most common rocks making up most of the world’s petroleum reservoirs) are sandstones and carbonates. On a worldwide basis, sandstone reservoirs hold most of the world’s oil and gas (about 62%). In Canada, however, the situation is reversed: nearly 70% of the conventional petroleum in Canada is found in carbonate reservoirs. Many other rocks are sufficiently porous to be reservoirs, but are still useless because their passageways or pore-throats are too small to allow petroleum droplets to move through them. This can be due to their fine grain size, as is the case in many siltstones and shales, or to poor sorting, where fine and coarse grain sizes are intermixed and the finer particles clog the passageways. The best reservoirs are coarse- to medium-grained (either siliclastic or carbonate material) and show a high degree of sorting. Muddy sandstone lithologies, deposited by such processes as turbidity currents or rocks containing unstable minerals that are easily weathered to clay, generally make poor reservoir rocks. However, even poor reservoir qualities can be compensated for when there is a considerable thickness, or net pay thickness, of the oil column or great areal extent for the productive horizon.

Permeability is measured by a unit called the darcy. Most reservoirs, however, only have permeabilities recorded in the range of about 1/1000 of a darcy, so usually you will see permeability values quoted in millidarcies. Typical reservoirs in southwestern Manitoba range between 5 and 500 millidarcies, although some reservoirs in western Canada have permeabilities exceeding 5 darcies.

Another important aspect associated with the concept of permeability is that the nature of the fluid must be taken into account. Since permeability is defined as the ability of a rock to allow a fluid to pass through it under a given pressure differential, then we must know what fluid is moving through the rock. Gas, for example, which is much less viscous than crude oil, may be able to flow from tight sands or dense limestones with permeabilities of only a few millidarcies or


less. In order to overcome this apparent dilemma, all permeabilities are evaluated with respect to one fluid: mercury.

Porosity in reservoir rocks of southern Manitoba and Saskatchewan is normally between 10% and 20%, but some excellent reservoirs may have porosities of 30% or more. Accumulations in reservoirs with less than about 3% porosity are usually not commercial. Porosity can be divided into several types: • primary: intergranular (between grains), intercrystalline (between crystals),

and intragranular (within grains); and

• secondary: solution, fracture, and intercrystalline.

Sandstones usually have primary porosity, which decreases with depth of burial as the grains are compacted and intergranular cementation develops. However, leaching of carbonate cements and unstable minerals in sandstones can cause good secondary porosities even at depths where they would normally be tight.

Most carbonate reservoirs are usually cemented quite early in the history of the rock (often right at the time of formation and deposition, such as is the case in a carbonate reef), and most quickly lose their primary porosity. Fortunately, carbonates are also very susceptible to postdepositional solution and recrystallization so that when they are reservoirs their porosities are usually secondary. The major cause of secondary porosity in carbonate rocks is solution, but fracture porosity and development of intercrystalline porosity are also very important. The latter is particularly important in reservoirs in southern Manitoba where the original finely crystalline calcite has been diagenetically altered to coarsely crystalline dolomite. Also, the process of converting calcite to dolomite involves a volume reduction of about 13%, which helps to create the secondary voids.

Secondary porosities, both in limestones and sandstones, are often developed by leaching or dissolution along fault zones and unconformity surfaces. In such cases, these zones may become important conduits for secondary migration of hydrocarbons.

Finally, to date only a small fraction of the world’s oil reserves has been found in lithologies, such as shale or igneous and metamorphic rocks. It must be emphasized, however, that this may be due to the fact that there has been relatively little exploration for oil and gas in these types of rocks. Where petroleum has been found in such unusual reservoirs, the oil resides within fracture porosity. Such reservoirs can be quite productive, as for example, the shale reservoirs of the Bakken in Manitoba, and in Saskatchewan and North Dakota.

The trap The last critical factor in the cycle of petroleum generation, migration, and accumulation is the development of a trap. A trap is completely independent of the other components (source, reservoir, migration) and is simply a geometric configuration of structures and/or strata, in which relatively impermeable rock types lie updip from permeable rock types. The impermeable rocks are usually

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referred to as a seal. In some cases, traps may be created by hydrodynamic factors associated with the movement of subsurface waters, but these are rela-tively rare. Most traps fall into one of three categories: they can be structural traps, stratigraphic traps, or combination traps that have both structural and stratigraphic aspects.

Traps may contain oil, natural gas, a combination of both, or no hydrocarbons at all. It must be emphasized here that, in fact, most traps are nonproductive. Statistically, in North America, only about 1 trap in 10 contains any petroleum. Thus, from an exploration perspective, traps are usually the easiest component of the petroleum play to identify. It is important to remember that subsurface petroleum geology is much more complicated than the simple location of subsurface structural traps. Even in a petroleum-rich basin, such as the Western Canada Sedimentary Basin, the vast majority of structures that are tested will be dry or nonproductive.

If both types of petroleum products occur within the same trap, gas, being lighter, is trapped at the highest level in the reservoir and overlies oil. Below the oil and gas and at the edges of the trap, the pores of the reservoir are filled with water, which is, of course, heavier than oil or gas.

Structural traps are usually limited in size by their closure. Closure is the vertical distance between the high and low points of the structure. They may be full to their spill points or, as is more common, may be less than completely full. Many stratigraphic traps, in contrast, are usually limited only by the quantity of petroleum they contain or may be limited by the size and shape of the reservoir and by lateral lithologic changes.

Structural traps have been, by far, the most common exploration target, since they are usually relatively easy to detect. Structural traps have provided over 75% of the world’s discovered reserves. This is particularly true of anticlines. As you learned in your introductory course in Earth science, anticlines may originate in many ways: through compression, or as compaction and drape features over rigid high blocks, or as rollover forms where rapid sedimentation onto undercompacted muds causes instability and slumping. Anticlines may occur alone or in combination with faults. These faults may or may not help produce the trap. Faults may also be traps in their own right; but in either case the faults must be tight and impermeable if petroleum is to accumulate. Usually, there is no way to test this except by drilling.

Salt structures and salt domes or diapirs can generate anticlinal traps in the overlying sediment, as well as fault and stratigraphic traps along their flanks. Together, these salt flow-related traps account for about 5% of the world’s petroleum reserves.

Stratigraphic traps that are due to lateral and/or vertical changes in rock type, account for about 15% of the world’s reserves. They fall within a wide range of categories. Many are associated with unconformities. Others, like most of the traps in Manitoba, are updip stratigraphic pinchouts within fluctuating transgressive-regressive sequences. Stratigraphic traps may also be related to diagenetic changes, where differential solution or cementation have caused the


rock type to vary laterally. Some sandstone stratigraphic traps are elongated bodies, with the reservoir comprising either channels or coastal barrier islands or bars. These are referred to as shoestring sands and are usually surrounded by shales, which may act as both source rock and seal. Carbonate reefs can form stratigraphic traps if high porosity is preserved or secondary porosity is developed. Similar to the shoestring sands, these reefs are often surrounded by fine-grained, organic-rich shales, which act as both seal and source.

Relative to structural traps, finding stratigraphic traps is much more difficult because of their subtle nature and the lack of obvious structural components. However, because of the fact that most structural traps are nonproductive, and in fact most of the productive structural traps have already been found, a major effort is now being mounted by exploration geologists in the search for stratigraphic traps.

Combination traps contain about 10% of the world’s petroleum reserves. These traps are often found in areas where faults and folds were actively developing during deposition. In many cases, these growing structures produced lateral changes in rock type or sediment facies or unconformities which helped form the trap.

Giant fields The formation of large traps (structural, stratigraphic, or combination) concurrent with the actual petroleum generation and migration has been a major factor in the formation of a special type of petroleum accumulation known as a giant petroleum field. A giant field is one that contains over 500 million barrels of recoverable oil or more than 3.5 trillion ft3 of gas. Giant fields are of particular importance in energy resources because together they account for over 75% of the world’s known reserves.

An important lesson to be learned from giant petroleum occurrences is that the timing of reservoir availability, maturation, migration, and trap development is absolutely critical both in terms of the actual presence or absence of the field and actual size of oil accumulation. Optimal conditions for efficient generation, migration, and entrapment occur when structures are actively growing, or when stratigraphic features such as unconformities are being created, at about the same time as the generation and migration stage. Late-stage structures may well be barren or may entrap only gas, since it is more easily remobilized than oil. It is also very important to remember that the reservoir must already be in place.

The seal Clearly traps must be sealed by impermeable barriers in order to stop the continued upward migration of petroleum. In the case of anticlines, only a vertical seal, or caprock, is required. Faults and stratigraphic traps, in contrast, must be sealed both vertically and laterally.

Shale is the dominant caprock of most of the world’s reserves and is overwhelmingly the seal in basins rich in clastic or terrigenous sediments, where sandstones are the dominant reservoir rock. In terms of efficiency,

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however, most shale is actually quite “leaky,” and with time the gaseous components of petroleum can migrate through shales and be lost.

Evaporites are the most efficient caprock and seal. They are particularly common in carbonate-rich basins, such as Western Canada, and they often form seals for carbonate reservoirs. Furthermore, evaporites commonly develop in restricted basin settings, where accumulations of organic-rich source rocks are also favoured. Dense, nonporous, nonpermeable carbonate rocks can also form caprocks and seals. Carbonate lithologies seal about 2% of the world’s reserves.

Review questions 1. What is the difference between primary and secondary migration?

2. In a sedimentary basin like the Williston Basin, would you expect long-range or short-range migration to be the norm? Why?

3. What is the relationship between porosity and permeability?

4. What is effective porosity?

5. If most carbonate rocks are cemented early in their history, then why are carbonate rocks such an attractive target for petroleum exploration?

6. What happens when CaCO3 is converted to CaMg(CO3)2?


Notes

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Unit 8 The Big Picture: The Sedimentary Basin and Basin Exploration Philosophy

Topics The sedimentary basin Exploration philosophy in a petroleum basin Summary

Introduction So far in our discussion, we have focussed on the relatively small-scale, individual petroleum play aspects. Now we will examine the larger perspective: the total sedimentary basin and how basin petroleum exploration proceeds over a period of decades.

Learning objectives By the end of this unit you should be able to: • characterize what a sedimentary basin is and how it is distinct;

• summarize a basin with respect to petroleum enrichment;

• classify basins in terms of underlying crust, position, resource potential;

• locate the most attractive areas of a sedimentary basin in terms of hydrocarbon potential;

• identify the areas of a typical basin that tend to be oil prone and gas prone; and

• describe the major exploration phases within a large sedimentary basin.

Learning activities 1. Read the study notes. 2. Answer the review questions. 3. Finish reading pages 125–189 in Resources of the Earth. 4. Finish reading pages 1–113 in Our Petroleum Challenge. 5. Complete assignment 3 and send it to the Distance and Online Education

Student Services office.


Study notes Key terms basin classification basin hinge continental crust convergent margin basin cratonic basin

divergent margin basin intermediate crust petroleum enrichment sedimentary basin

The sedimentary basin Because of the burial and temperature requirements needed for the maturation of organic matter, most petroleum is found in sedimentary basins. Sedimentary basins are depressions on the earth’s surface, caused by subsidence, that receive greater than average sediment thicknesses.

Most sedimentary basins have sediment fills in excess of 2 kilometres, and some may contain 15 or more kilometres of sedimentary rock. This is usually sufficient for at least part of their contained organic matter to mature to petroleum. However, being within the “oil window” is not enough, as we have already learned. The petroleum richness of sedimentary basins, or even the presence of petroleum at all, is also highly dependent on most of the other geologic features discussed in this unit: source rock and reservoir development, migration pathways, geothermal regime, style and timing of trap and reservoir development, and the presence of good sealing lithologies. The age of the sedimentary rocks within a basin is also of some importance.

Even though petroleum reserves can be found in rocks of all ages, most giant fields and most of the world’s reserves occur in geologically young sequences: rocks of Late Mesozoic and Cenozoic age. Palaeozoic rocks probably had an equal potential to generate hydrocarbons as these younger rocks, but there has been more time in which to destroy all or part of the petroleum through uplift and erosion.

Petroleum enrichment (the ratio of barrels of oil discovered per cubic mile of sediment), the incidence of giant fields, and the habitat of petroleum within sedimentary basins can all be related to the structural, sedimentological, and geothermal setting of the basin. These features can be used to describe a number of petroleum basin types.

There are several basic ways in which sedimentary basins can be grouped. They can be divided on the basis of their underlying material or crust. These are either:

• continental crust, which is relatively light, granitic, and underlies most continental areas; or

• intermediate crust, compositionally between granite and basalt, and occurring along continent-ocean margins.

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Although a great deal of literature and academic discussion exists about this type of basin classification, the classification of basins according to underlying material or crust has little value to us in the energy resources field.

Basins may also be grouped according to the stability and movement of this underlying crust, as either:

• cratonic basins, developed on the stable parts of continents away from continental margins;

• divergent-margin basins, formed along continental margins where the sea floor is spreading, and rifting (extensional) movements occur; or

• convergent-margin basins, formed along continental margins where continents and/or oceans are in collision and some ocean crust may be consumed.

For the purpose of petroleum exploration, however, we require a much finer-tuned classification scheme. The classification scheme most commonly used in petroleum exploration consists of one based on a combination of parameters including age, geometry, thickness of sediment fill, and shape; overall tectonic setting, geothermal history, crustal setting, and petroleum enrichment. Table 8.1 summarizes the major groupings of basins according to this classification scheme.

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Table 8.1 Major groupings of basins

Simple Interior

Composite Rift Downwarp Pull-Apart Subduction Median Delta

% World Reserves

2 25 10 48 1 7 2 5

Petroleum Recovery

Low Average Good High Low High Variable High

Enrichment factor (bbl/mile3)

20,000

60,000

100,000

100,000

40,000

100,000

20,000

100,000

% with Giants 7 40 35 48 5 47 20 1

Main Lithology

Clastic+ Carbonate

Clastic Clastic+ Carbonate

Carbonate Clastic Clastic Clastic Clastic

Maturation Undermature Undermature Overmature Mature Undermature Mature Mature Undermature

Age Paleozoic Paleozoic-Mesozoic

Mesozoic Mesozoic-Tertiary

Mesozoic-Tertiary

Mesozoic-Tertiary

Mesozoic-Tertiary

Tertiary

Tectonic Location

Interior Exterior Rift Collision Margin

Divergent Margin

Divergent Margin

Convergent Margin

Interior

Traps Stratigraphic Fault Fault Stratigraphic Fold Fold Fault Stratigraphic

Crustal Zone Cratonic Cratonic Cratonic Intermediate Intermediate Intermediate Oceanic Oceanic

Thickness (feet)

6,000 6,000 9,000 9,000 12,000 6,000 6,000 12,000

As important as basin classification is in terms of our ability to discuss basins, in fact most of the worlds productive basins simply do not fit well into any specific classification. In fact, worldwide reserves are usually related to their simple location within a petroleum basin, regardless of the basin type. Most petroleum in any basin will usually be found along the basin’s flanks, either along “hinges” that mark the break between the basin and normal sediment thicknesses of the shelf, or along structurally mobile rims. Together, the basin margin areas (hinges and rims) comprise about 70% of the world’s known petroleum deposits. A sizeable amount of petroleum can also occur in traps in the shelf area and in the deep basinal region. Together these nonbasin margin areas comprise about 20% of the world’s known petroleum reserves. Finally, petroleum also occurs in “extrabasinal” settings or areas that have actually received thinner-than-average sedimentation. There are several classic example of these extrabasinal petroleum accumulations in Canada and the United States. However, these extrabasinal accumulations account for only about 10% of the world’s reserves.

Within any sedimentary basin, oil usually becomes lighter and gas more abundant with depth. Oil also becomes lighter and gas more prevalent laterally toward a basin’s centre. The heaviest crude is typically found along basin margins. This lateral and vertical distribution of oil and gas is of considerable importance to us as explorationists. Part of this pattern may be attributed to increased thermal maturation with depth. However, another explanation is that the lighter gas displaces earlier formed oil that had already accumulated in the traps. In other words, when the trap becomes full to its spill point, the oil is displaced and moves upward toward the basin’s flanks.

Exploration philosophy in a petroleum basin Petroleum basin exploration can be divided into a series of phases. With each phase or step, there is a progressively increasing informational data base from which to evaluate the petroleum prospects of a region.

Phase I is the stage of early surface mapping and reconnaissance geophysics. It begins with the unexplored basin. To varying degrees, there may be some previous knowledge of surface geology and structures. There may also have been reports of surface indications (e.g., surface seeps, springs, gas detected in water wells, etc.) to encourage the exploration. Surface evidence of petroleum has been important in the discovery of nearly every major onshore petroleum province in the world, although there are also major areas with abundant surface evidence that have proven to be noncommercial, such as in Cuba and Morocco. Virtually every sedimentary basin in North America and western Europe has already passed through this Phase I exploration, although worldwide there are about 100 basins that have not yet entered Phase I.

At the Phase I stage, the geologist’s role is to obtain knowledge (or a more detailed knowledge, if some already exists) of surface structures (potential traps) and to evaluate surface sedimentary facies, continuity, source rock potential, and possible preliminary levels of expected maturation. The


exploration geologist must work closely with the geophysicist to relate the surface geology and structures to the subsurface geophysical stratigraphy.

At this stage a geologic analog is often used to compare this largely unexplored basin to other producing “look-alike” basins that appear to have common geologic characteristics.

Phase II is a stage of mainly geophysical seismic surveys. During this stage, more data are obtained on the depth of the sedimentary sequences, configuration of potential traps, and possibly some knowledge of the character and volume of the sedimentary fill. Petroleum explorationists often use a simple rule of thumb: the chance of finding commercial oil and gas is roughly in proportion to the total sediment volume. The greater the volume of sediment, particularly if most of it lies within the depth range of the oil and gas window, the more encouraged the explorationist will be. The volume of subsurface shale (source potential) is also evaluated at this stage.

Phase III is the stage of exploratory or “wildcat” drilling, which establishes for the first time the details of the sediment character (reservoir, source and caprock potential), maturation, and the geothermal regime. Although the potential for a discovery exists at this stage, the fact that only about 10% of structural traps are productive implies that chances are slim. However, in a new basin, the most promising prospects, usually surface or seismically detected subsurface structures, are drilled first.

The drilling at this stage is not expected to be productive, and a dry hole is not considered a failure. This drilling will supply a large amount of data that will lead to the placement of new wildcat wells.

Phase IV, the discovery phase, follows the successful completion of some wildcat wells. At this stage, reservoirs are established, and hydrocarbon types may be linked to certain stratigraphic units and/or trap types. Further wildcat drilling in less developed parts of the basin may be guided in part by the play and petroleum zone concepts. A play is defined as a group of geologically similar, “look-alike” prospects, usually at fixed horizons sharing common stratigraphic features.

The basin may also be divided into discrete petroleum zones at this time. These are sediment volumes whose contained pools show several characteristics in common. Application of the play and petroleum zone concepts usually causes the success ratio of drilling to improve during the discovery stage. Many of the basin’s largest fields will probably be discovered at this time, and exploration for more subtle traps may commence.

Phase V, the production phase, begins to provide exploration geologists with reserve estimates and a history of the hydrocarbon potential of the basin There is enough information to work out field-size distribution patterns, which will help guide further exploration as the area matures. Both the field size of new discoveries and the success rate of drilling typically decreases during this stage.

Commonly, not all of a sedimentary basin is at the same stage of drilling and development at the same time. Part of the basin may be maturely drilled, while

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other areas that may have appeared initially less geologically favourable, or were less accessible, may still be only semi mature or untested. The Western Canada Sedimentary Basin is a good example of this. Much of the prairie region of the southern part of the Western Canada Sedimentary Basin is mature in terms of exploration. However, large areas of the western and northern parts of the basin (the foothills of Alberta and British Columbia, and northwestern Alberta/northeastern British Columbia) are unexplored or semimature. Also, the shallower depths of the basin may have been thoroughly tested and have established production, while at the same time deeper stratigraphic horizons may be only at the Phase I or Phase II stages of development. In western Canada, for example, it is significant that new discoveries are still being made in areas where drilling and development have proceeded for nearly 100 years!

Summary Five important geological factors are needed to get commercial petroleum accumulations: • a mature source rock; • a migration pathway; • a permeable reservoir rock; • trap; and • caprock or impermeable seal.

A sixth required factor is that the accumulation be sufficiently large in order to allow the company to produce enough petroleum to cover their exploration costs.

All five geological factors must be present in order to get significant petroleum. We have also discussed and briefly explored several other fundamental aspects of petroleum exploration geology. These include the nature of the chemical components that make up petroleum, circumstances that will produce natural gas or asphalt instead of crude oil, and subsurface temperature and pressure conditions that are critical for maturation and migration, and can affect the drilling and production processes. Finally, the sedimentary basin as a habitat for petroleum has been examined, as well as stages in its exploration and development.

Review question 1. You have just been appointed exploration manager of a major oil

exploration company. After two decades of working only in domestic exploration, your company has decided to go “international.” On the basis of your vast geological knowledge and expertise, your task is twofold: target the general type of basin that you would like to start your exploration in (and discuss why you chose this type of basin); and set up a five-year plan for exploration.


Notes

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Assignment 3

1. Discuss why we “know” that oil and gas did not originate in the rocks in which they are found but migrated from elsewhere.

2. What physical property of oil, gas, and water determines their stratification in a reservoir?

3. Define and discuss “primary migration” and “secondary migration.”

4. Consider the following argument: “Most water expulsion in clay sediments occurs in the upper 2 km of burial. For average geothermal gradients, oil generation occurs below this depth. Therefore, simple flushing of oil with expelled water is not a viable mechanism for primary or secondary migration.”

Do you agree or disagree? Discuss your point of view.

5. Illustrate with sketches primary intergranular porosity and primary intragranular porosity.

6. What two postdepositional processes in a sedimentary basin tend to diminish porosity? What processes tend to enhance porosity?

7. What geological environment would you go to in order to find a fracture porosity reservoir?

8. What is “swamp gas” and how does it form?

9. Describe the changes in the use of fossil fuels in time.

10. What proportion of the original oil in the rocks of a trap is usually recoverable and why is not all of the oil recoverable?

11. What effects did the OPEC oil embargo of 1973 have on subsequent oil usage and production?

12. How did the Big Inch and the Little Inch influence the development of the natural gas industry in US?

13. Describe the general steps involved in refining oil.

14. What do the M. King Hubbert-type curves tell us about the future availability of petroleum reserves?


Notes

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Unit 9 Coal and Oil Shales

Topics Introduction: What is coal? Origin of coal Physical properties of coal Chemical properties of coal Coal type Coal rank Historical development of oil shales Oil shale versus petroleum source rock Organic and chemical composition of oil shale Oil shale as a resource

Introduction In the Middle Ages the British began using coal for heating; this was the first large-scale use of any fossil fuel. Between 1800 and 1910 the use of coal doubled about every 16 years but since then the doubling time has been about twice that of oil. Similarly, early exploitation of the vast hydrocarbon resource base of oil shale began over 150 years ago but has since decreased in favour of more easily extracted conventional oil and gas. Beginning in the 1970s there has been again a major push on in North America for increasing the use of coal and oil shale relative to oil and natural gas. However, large-scale coal and oil shale usage has many social and environmental problems associated with it. This section will explore the geology of coal and oil shale.


1. define “coal” and “oil shale”;

2. outline the genesis and diagenesis of coal and oil shale;

3. differentiate humic coals from sapropelic coals;

4. summarize the major factors controlling coal deposition;

5. describe the physical, organic and chemical properties and characteristics of coal and oil shale;

6. quantitatively evaluate coal rank and coalification; and

7. discuss the history and future development of coal and oil shale as resource bases.


Learning activities 1. Read the study notes. 2. Answer the review questions. 3. Read pages 190–238 in Resources of the Earth (note: the material covered

by this reading will not be directly discussed in the study notes, however it is important and should be studied. You should plan to complete this reading assignment by the end of unit 10.)

Study notes Key terms algae Botrycococcus boghead coal cannel coal coal coal rank coal type fixed C umic coal

kerogen oil shale proximate analysis reflectance sapropelic coal shale oil Tasmanaceae ultimate analysis vitrinite volatile matter

Introduction: What is coal? Coal has intrigued humans as a topic of interest, and as a fuel, from the earliest recorded events in our history. Prehistoric utilization of coal is noted in archeological investigations. But, what is coal? There seems to be a need to define this material.

A dictionary definition of the term “rock” is “any solid mineral matter occurring naturally in large quantities.” Another general definition often quoted is “an aggregate of minerals.” Whatever the definition, generally the term “mineral” is included. Webster’s dictionary defines “coal” as “a black, or brownish-black, solid, combustible mineral formed by the partial decomposition of vegetable matter without free aggressive air, under the influence of moisture, pressure, and temperature.” The Glossary of Geology defines coal as either “a black coloured, compact and earthy organic rock with less than 40% inorganic com-ponents (based on dry material) formed by the accumulation and decomposition of plant material”—or as “the general name for naturally occurring, commonly stratified, rock-like, black to brown derivatives of forest-type vegetation that accumulated in peat beds which, by burial and dynamochemical processes, was compressed and altered to material with increasing carbon content and that does not contain so much incombustible material as to be unfit for fuel.”

If you take the time to read these definitions again you will note that some problems exist. Some suggest that coal is a mineral. Is it a mineral in the classic sense or is it a “mineral fuel”? If a rock is an aggregate of minerals and coal is

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composed primarily of vegetal material, is coal a rock? Definitions of one or the other must be modified if we are to consider coal as a rock. A definition for a rock such as “an essential constituent of the earth’s crust” would cover the situation. This sort of a general definition is favoured by many geologists.

The International Handbook of Coal Petrography defines “coal” as: “a combustible sedimentary rock formed from plant remains in various stages of preservation by processes which involved the compaction of the material buried in basins, initially of moderate depth. These basins are broadly divided into limnic (or intra-continental) basins, and paralic basins which were open to marine incursions. As the underlying strata subsided progressively, and more or less regularly but sometimes to great depths, the vegetable debris was subjected to the classical factors of general metamorphism, in particular those of temperature and pressure.”

This definition includes a bit more geology than many of the others. But complexities continue to plague us when defining coal. Clearly coal is a complex substance consisting of many different constituents and representing many chemical compounds. While it is true that it is “homogenetic,” in that it is derived almost entirely from plants, we must accept that plants as a whole are complex. Plants themselves are composed of a large number of different types of tissues, each consisting of a large number of cells in a great variety of arrangements and proportions.

Depending upon your definition, coal can be considered a rock, or if you prefer, it may be considered a substance that occurs in the earth’s crust. Coal is certainly not an aggregate of minerals but it is present in quantities sufficient enough so it is difficult to overlook it. A definition that suits your use is one you should choose. Keep in mind that often times a definition of “coal” becomes important when you enter into commerce and start buying, selling, or trading coal or coal properties.

Probably the best general definition of coal is a readily combustible rock containing more than 50% by weight and more than 70% by volume of car-bonaceous material, formed from compaction or induration of variously altered plant remains similar to those of peaty deposits. Vast differences in the kinds of plant materials (which we call type), in degree of metamorphism (which we call rank), and range of impurity (which we call grade), are characteristic of coal.

Origin of coal Thus, as we can see from the above discuss, literally any deposit in which organic matter comprises at least 50% by weight or 70% by volume can be considered coal. In modern sediments and in rocks, organic matter tends to occur in three natural associations: • remnants of algae, micro-organisms and phyto- and zooplankton; • highly degraded remnants of higher plants; and • less degraded remnants of higher plants.

Depending on the type and degree of maturation of the organic material, either petroleum source rocks, oil shales, or coal can result.


As we learned in unit 6, the first association of organic material, generally referred to as Type I organic matter, is the principal organic component of oil source rocks. If the organic matter comprises a significant portion of the rock, the rock may be referred to as an oil shale, or, if the organic component is greater than 50% by weight of the rock it may be referred to as coal. Type II organic material, depending on the abundance of organic matter, may also be referred to as a source rock, oil shale or coal. Type III organic material, when present in large amounts, comprises coal. However, because this type of organic matter has little oil-generating potential, rocks containing lesser amounts of Type III organics are not considered source rocks or oil shales but are simply referred to as carbonaceous rocks.

Thus, coal can originate not only from Type III organics, but also from Types I and II; the latter are referred to as sapropelic coals. Sapropelic coals are further subdivided into cannel coals, if they are rich in spores, and boghead coals, if they are rich in algal remains. Coals originating from Type III organic material are humic coals.

Humic coals are by far the most abundant and make up the major coal resources of the world. Accumulation and preservation of organic material in sufficient quantities to form humic coals is generally restricted to swamp, marsh, or bog environments, and most coal seams have been interpreted to have originated from peat deposited in these environments. Unfortunately, factors affecting the accumulation and preservation of peat and, ultimately, the transformation of peat into coal, are poorly understood. At best we can say that peat and coal formation is controlled by the evolutionary development of the flora, the climate, and the specific depositional environment.

The type of plants in any marsh, swamp, or bog environment is also mainly a product of the climate. The evolution of the plants, however, ultimately determines what plant forms will be incorporated into the peat. Although coals as old as Middle Precambrian have been described, it was not until the Late Precambrian that the earliest plants evolved, and not until the Early Silurian that the first vascular plants appeared. Only in the Early Devonian did herbaceous plants become established. These early plants were restricted to swampy soils and were characterized by a widespread shallow root system. In the Middle to Late Devonian the large gymnosperm trees began to develop and by the Carboniferous had completely developed for life on dry land. During the Late Carboniferous, in the northern hemisphere, luxuriant and diverse swamps existed which were characterized by gymnosperms, club mosses (up to 30 m high) and by tree-sized ferns.

Climate plays a major role in coal and peat formation by controlling the rate of plant growth, type of plants and the decompositional rates. Warm wet tropical and subtropical climates are most favourable for the development of coal forest swamps. Such climates are characterized by high rates of plant accumulation. In Florida and the Mississippi Delta, peats have been reported accumulating at rates of 1 mm per year. In temperate and cool climates, rates of plant growth are much slower but the rate of decomposition of the organic matter is also slower.

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Temperate peats of the Fraser Delta in British Columbia have also accumulated at rates of about 1 mm per year.

Thus, we can see that coal seams and peats can accumulate wherever the rates of accumulation are greater than decomposition. Peat accumulates in high Arctic climates as well as in tropical climates. However, it is likely that most ancient coals probably originated in tropical climates. Coal seams that are deposited in tropical or subtropical climates are generally characterized by the presence of bright bands originating from woody material. Coal seams originating in cool climates are more commonly thinly banded and very finely grained.

To a major extent the factors of lateral distribution, thickness, composition and quality of coal are determined by the depositional environment. For the formation and preservation of significant peat deposits, a depositional setting is required in which there is a combination of high organic productivity and slow continuous subsidence. This is necessary such that the groundwater table is continuously at or close to the peat surface. In addition the peat swamp has to be protected for clastic sediment influx. These conditions occurred in the past and presently occur mainly in coastal marine and lacustrine environments. The major environments for coal formation are: • back-barrier lagoons; • deltas; • coastal and interdelta plains; and • lakes.

The sedimentary environment that immediately preceded the coal swamp formation is also important because it shapes the topography on which the coal develops. This, in turn, affects the thickness and lateral extent of the coal. The environments that occur immediately after the coal swamp further affects the coal by channelling, which may remove part of the peat or by introduction of brackish or marine waters affect the peat chemistry.

Physical properties of coal Common physical properties of coal are color, density, hardness, and grindability. There are, of course, many others. Color is one which varies somewhat with rank but generally it is sufficient to say that coal ranges from brown to brownish-black to black.

The density of coal becomes of extreme importance when one is trying to clean this material in any sort of a preparation process. The differential densities between the organic material and the undesirable inorganics are of great importance. Various coals may be treated by various processes at several different densities. Individual coals and individual washing facilities will vary considerably. The “end purpose” use of the coal or the desired ash and sulfur content most often determine the density levels for separation.

The hardness of coal can be measured by any of a variety of tests but most often this becomes of importance when the coals are actually being processed. Hardness, and toughness or resistance to crushing, become extremely important


considerations in the design of not only preparation equipment but also in the selection of actual mining equipment.

The grindability of coals varies significantly with rank but there is not a straight-line progression, or a straight-line increase in hardness through the coalification series.

Chemical properties of coal The chemistry of coal is at best a complex topic. The coal itself is an extremely heterogeneous mixture of organic material, along with some undesirable inorganic entities. To describe this chemically is virtually impossible. Indeed, to suggest that something like a coal molecule might exist indicates a total lack of understanding of the basic physical nature of coals.

The gross chemistry of coals is often discussed under two categories: the normal proximate analysis and an ultimate analysis. Many geochemists have in the past refused to admit that these are even related to the “chemistry” of coal. A proximate analysis consists of analyzing for moisture content, ash, volatile matter, and fixed carbon. The first three of these must all be done according to industry standards and the fourth item, fixed carbon, is derived by subtracting the sum of the first three from 100. An ultimate analysis of coal consists of determinations aimed at obtaining values for carbon, hydrogen, sulfur, nitrogen, ash, oxygen, and moisture. All of these must also be carried out according to industry-prescribed procedure. Normally it is also desirable to determine the heat value (Btu) of the samples in question. There are other determinations which can be made for coal and depending somewhat upon your usage they may or may not be important. Some of these are forms of sulfur, various oxides, various trace elements and mercury, fluorine, and chlorine contents.

The mineralogy of coal is a topic which is being investigated by many researchers and agencies here in Canada at the present time. There is definite merit in pursuing this but it has always been a difficult subject because of the finely dispersed nature of much of the mineral matter in coal. Routine mineralogical analysis by X-ray diffraction techniques are difficult because carbon masks most of the important peaks. Much work has been done recently in low temperature ashing—the low temperatures are employed to avoid destroying the actual mineral structures. New techniques involving low angle x-rays are being pursued. The mineralogy of coals can be extremely important when coals are being considered for conversion or combustion. Also some minerals may act as catalysts during the conversion process.

Coal type The words “coal type” have a variety of meanings to a wide variety of people. However, they have been applied in a restricted sense for many years by geologists in general and coal geologists in particular. Coal type is initially determined by the nature of the plant matter, the conditions of deposition, and the extent of operation of the biochemical process. Generally, coal type classification schemes subdivide the coal into two major categories: those which are clearly banded or layered and those which are non-banded. The

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banded coals are subdivided into bright, semi-splint (or semi-bright) and splint (or dull). The non-banded coals that massive in appearance consist of cannel and boghead coals. The major differences between these have to be determined microscopically: the first is composed of a very high percentage of spores, and the second is composed of a high percentage of algal remains.

Coal rank For at least 70 years coal geologists and coal petrologists have agreed that there is some sort of a general progression from peat through various coals all the way to anthracite. The terms that have been applied classically to this sequence are peat—lignite—sub-bituminous— bituminous—semi-bituminous—semi-anthracite—anthracite and meta-anthracite. At one time some geologists felt that specific vegetational types gave rise to different rank coals. Most people do not hold with this interpretation today. Throughout the sequence noted above, many changes take place and it is the measurement of these changes, or the parameters which are used to measure these changes, which give rise to the word “rank.”

The coal rank is defined as the degree of coalification. The tricky part, of course, now becomes how do we measure the degree of coalification?

Many coal properties change with rank. In one way or another, and at one time or another, such measurements as volatile matter, carbon, fixed carbon, moisture, and heat value have been used either singly or in combination as indicators of rank. Unfortunately, these properties do not change uniformly with rank and consequently are just not suitable indicators.

The moisture content of coals in a general way decreases rapidly from peat through the higher rank bituminous stages, stays more or less uniform from there to anthracite but then shows a marked increase in the meta-anthracites. Volatile matter increases in the coalification series up to the lower end of the bituminous rank and then decreases to anthracite and may increase very slightly in the meta-anthracites. Fixed carbon shows a general progressive increase up to anthracite but then a decrease in the meta-anthracites. The heat value of coals increases steadily up to the area referred to as semi-bituminous coals and then begins to level off and shows a decided drop from the anthracite to the meta-anthracite categories. The total carbon, or ultimate carbon content of coals increases throughout the coalification series, however the band is quite broad in some areas and total carbon can be affected by coal type as well as its position in the series. The high volatile contents associated with some coal types such as cannels or boghead coals will throw this off as well as other indicators.

Because coal is a physically and optically complex material, it is best if the rank of a coal can be measured on one specific entity. This avoids the interactions that are bound to occur when ‘‘whole coal’’ is examined. The material that is best suited for this in coals is the maceral vitrinite. This maceral is almost always the most abundant material in a coal sample and therefore, hopefully representative, and it is relatively easy to isolate mechanically if this is necessary. Optically it is very easily isolated. In addition, the characteristics of


vitrinite change in a fairly uniform manner throughout the coalification series. There are difficulties in working with vitrinite in the very low rank coals and this is the major drawback.

The property of vitrinite that is most easily, effectively, and accurately measured is reflectance. This is an indication of the percent of light which is reflected from a polished surface of the vitrinite maceral. In other words, how much of the light that is impinged vertically onto the surface is reflected back vertically to the viewer.

There are several very gross generalizations that may be made with regard to rank variations. The first of these might be that the older coals (geologically speaking) are higher in rank. Generally also, coals that are at greater depth are also higher in rank. In the United States and Canada the coals in the eastern part of the countries are higher rank than those in the western parts.

The factors that are generally assumed to be important for causing increases in rank are temperature, pressure, and time. Most likely temperature coupled with time is extremely effective. The exact effects of pressure are not clearly understood but most assume that it is an important contributing factor. So far we do not know of any evidence that indicates that the pressure alone can cause increases in rank.

The two most common sources for the increase of temperature are the normal geothermal gradients and the presence of igneous intrusions. There are many examples of deep-seated igneous intrusions having affected the rank of large coal areas and many instances where rank has been changed on a local scale by dikes or sills that have approached or actually cut coal seams.

Probably the single most important reason for knowing the rank of a coal is for the sale or purchase of coals or coal properties. Almost all of this activity takes place on the basis of the classification adopted by the American Society for Testing and Materials (ASTM). The coal rank and associated vitrinite reflectance (Rv) and percent carbon limits are as follows: • Peat: Rv < 0.27; < 60% C • Lignite: Rv 0.27-0.4; 60-68% C • Sub-bituminous: Rv 0.4-0.6; 68-75% C • High-volatile bituminous: Rv 0.6-1.1; 75-85% C • Medium-volatile bituminous: Rv 1.1-1.5; 85-88% C • Low-volatile bituminous: Rv 1.5-1.9; 88-90% C • Semi-anthracite: Rv 1.9-2.5; 90-91% C • Anthracite: Rv 2.5-5; > 91% C • Meta-anthracite: Rv > 5; >91% C

The rank of coal or coal materials can be of importance when prospecting for oil or gas. Rarely do hydrocarbons occur when the reflectance of any organic material exceeds 1.3%. In fact, most of the petroleum and natural gas deposits occur in sediments where the organic reflectance does not exceed 1.0%. The

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rank of coal is also extremely important when selecting mining equipment, drilling equipment, and preparation equipment, as the hardness of the coal can vary significantly with rank. The way in which this varies has a very direct impact on crushing, grinding, and screening procedures. Generally speaking, the coals that are the easiest to grind or pulverize are those that fall in the medium-volatile to low-volatile classifications. Anthracite and high volatile coals along with the lignites and sub-bituminous coals are more difficult to grind. Other factors that may relate with hardness are such things as toughness, coherence, and tenacity.

Oil shale: A kerogen-rich sediment with potential economic value Historical development of oil shales The first mention of the oil shale industry goes back to the late 17th century (1694) when a patent was successfully applied for by an Englishman Martin Eale to extract pitch, tar and oil out of rock by heating it. This was followed in the early and mid-18th century by extensive exploitation of this new resource in France, Scotland, Australia, Brazil, New Zealand, Switzerland, Sweden, Estonia, Spain, China, and South Africa. Commercial use of oil shale as a resource continued in these countries until the early1940s. Only the discoveries of the vast reserves of conventional oil in the Middle East and the feasibility of low cost transport of this oil by pipeline and tanker ship to the market areas of the world brought the demise of the early oil shale industry.

However, in the latter several decades of the 20th century, the exponentially increasing consumption of conventional oil and similar escalations in costs made the vast energy reserves within the oil shales of the world marginally economic again Several countries (e.g., Russia, China, USA, Canada, Brazil) have recently re-examined the potential exploitation of their reserves. Both Brazil and United States have developed pilot plants on the world’s largest oil shale deposits: the Green River Shales in Colorado, Utah, and Wyoming, and the Irati Shales in Brazil.

Oil shale versus petroleum source rock Not surprisingly, considering the difficulties we discussed above with defining coal, there is no geological or petrographic definition of oil shale that is universally accepted. In fact, any rock that is capable of yielding oil in commercial amount upon pyrolysis (heating) is considered an oil shale.

The mineral constituents, and, hence, the rock classification of oil shales vary greatly. Some oil shales are true shales, where clay minerals are dominant and the rock is finely laminated. But others, like the well-known Green River Shales, are, in fact, carbonate rocks, with only minor amounts of quartz, feldspar, and clay minerals. The various oil shales that have been mined around the world during the last two hundred years range from shales to mudstones, limestones and dolostones.


The organic matter contained in most oil shales is mainly kerogen, insoluble solid organic material (remember our discussion and definitions of kerogen in section 6). A major point that must be stressed to persons unfamiliar with oil shale geology is that the rocks contain no oil and usually very little extractable bitumen. The rock will generate “shale oil” only during pyrolysis. In fact, the kerogen of oil shale is not any different than the kerogen of petroleum source rocks that we discussed previously! It is the richness of the kerogen and the occurrence of the rock in relatively shallow, near surface settings (i.e., mineable) that makes oil shales distinctive.

As we learned earlier, any rock containing more than about 0.5% organic carbon may produce oil or gas, provided it is buried to a sufficient depth. The generated hydrocarbons are mobile, so migration may result in commercial accumulations of oil or gas even if the material was generated from relatively low concentrations of organic matter in the source rock. In contrast, an oil shale must have a large amount of organic material to be of economic interest. One way of looking at this is to require that the oil shale yields more energy (in terms of shale oil) than it requires to process the rock. The average oil shale pyrolysis temperature is about 500oC. The energy that must be provided for heating the shale to that temperature is roughly 250 calories per g of rock, and the calorific value of kerogen is 10,000 calories per g. Thus, if the kerogen content of the shale is 2.5%or less, the total calorific value is used for heating the rock and the shale cannot be a source of energy. In fact in practice, a lower limit of about 5% organic content is frequently used, corresponding to an oil yield of 25 liters per metric t of rock (~6 US gallons per ton). Depending on the amount of overburden, availability of water, remoteness of the site and various other economic factors, often in North America a cutoff of 42 liters per tonne (~10 US gallons per ton) is used.

We must also be aware that the kerogen in oil shale should not have undergone any prior heating (in its geological history). In other words, optimum oil shale conditions dictate that the kerogen is immature. A petroleum source rock requires a sufficient burial history and the heating of the rock to the stage of catagenesis in order to thermochemically breakdown a substantial part of kerogen and thus generate oil. On the contrary, the best situation for an oil shale reserve is very shallow burial, and immature stage of kerogen evolution.

Organic and chemical composition of oil shale There have been many geological and geochemical studies of oil shale kerogens. These studies show that much of the organic matter is made up of algae. The main algal types are Botryococci and Tasmanaceae. Botryococcus is a fresh or brackish-water alga. It has a wide range of geological occurrences from the Precambrian to modern sediments. The kerogens from Permian boghead “coals” of France and Carboniferous torbanites of Scotland are almost entirely made of Botryococcus colonies, and the Recent coorongite in the Coorong Lagoon of South Australia represents a similar composition. Tasmanites (i.e., kerogenous rocks composed of Tasmanaceae) are marine in origin. There are many examples of oil shales having mainly Tasmanaceae: Permian tasmanites of Australia, Jurassic of Alaska and Silurian of France are

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among the most well known. However, most of the organic matter in oil shales on a global basis consists of unrecognizable (amorphous) organic matter. This amorphous organic material, commonly referred to as sapropelic matter, is probably derived from planktonic organisms, such as copepods or ostracods, and from the soft part of other types of microorganisms that normally inhabit freshly deposited sediment.

The chemical composition of organic matter from these oil shales varies greatly but almost always shows a high hydrogen and low oxygen content. The atomic O/C ratios also show a great range. Using the classification system we developed when discussing petroleum source rocks, oil shales would be groups as either Type I or Type II; there are no Type III examples.

Oil shales as a resource As conventional supplies of petroleum become more difficult (and more expensive) secure, it follows that there will be an ever increasingly widespread effort to seek possible substitutes for them. The reserves of oil shale stand out as a very important source of substitutes for petroleum. As pointed out above, in many parts of the world (e.g., Australia, France, China, Russia, Scotland), oil shales have been a via source of petroleum products for a long time. In North America, studies that there are about 3000 billion barrels of “potentially” economically recoverable synthetic crude oil in oil shales; the Green River Formation of Colorado, Utah, and Wyoming, alone contains about half of this. This represents about 100 times the known North American reserves of conventional oil. Of the total world potential of about 30 x 1012 barrels, roughly about 700 billion barrels are available for present-day commercial exploitation under today’s economic condition. constraints. However, caution must be exercised in any efforts to utilize oil shales on a massive scale. Significant environmental problems are inherent with the mining, processing, disposal of waste products.

Review questions 1. Define “coal.” 2. Define “oil shale.” 3. Compare and contrast organic matter in source rocks and organic matter in

coals. 4. A coal that is composed almost entirely of algal material is called what? 5. Discuss how plant evolution affected coal. 6. Is it likely that you would find a peat/coal forming area in the desert? Why

or why not? 7. Is it likely that you would find a peat/coal forming area in the high arctic?

Why or why not?


Notes

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Unit 10 Canada’s Energy Saviour: The Tar Sands and Heavy Oil

Topics Introduction to Canada’s oil sands and heavy oil Deposit categories Outcrop occurrences Fundamental geological properties of oil sands Geology of Canada’s oil sands deposits Other geological considerations in exploitation

Introduction The amount of oil in the Oil Sands and associated heavy oil and other tar sands of Alberta and Saskatchewan is staggering and may very well be the fuel that carries Canada into through the twenty-first century. This section will explore the geology of this important and immense petroleum deposit.

Learning objectives By the end of this unit you should be able to: 1. characterize the bitumen of the Tar Sands and Heavy Oil deposits; 2. outline the stratigraphic setting of each of the major deposits in Canada; 3. discuss the role of the geologist in evaluating the Tar Sands/Heavy Oil

resource; 4. list and discuss the major components of the Tar Sands; 5. outline the microscopic habitat of the in-situ bitumen; 6. summarize the geological history of the Tar Sands deposits; and 7. characterize the origin of the Tar Sands and compare this with the origin of

the bitumen within the Tar Sands.



3. Finish reading pages 190–238 in Resources of the Earth (Note: The material covered by this reading will not be directly discussed in the study notes, however it is important and should be studied.).


Study notes Key terms Athabasca deposit bitumen Boreal Sea cement Clearwater Formation Cold Lake deposit facies analysis Gething Formation Grand Rapids Formation heavy oil hydrophillic

in-situ technology Lloydminster heavy oil deposit matrix McMurray Formation Peace River deposit saturation Subcrop carbonate trend tar sands Wabasca deposit water wet

Introduction to Canada’s oil sands and heavy oil Canada’s oil sands deposits differ from conventional oil fields in two significant ways. Firstly, the oil sands are several orders of magnitude larger than conventional oil pools. The Athabasca deposit, for example, is estimated to contain as much as 900 billion barrels of bitumen in place. This compares with the large Leduc field at about 300 million, or North America’s largest conventional oil field, Prudhoe Bay, at about 15 billion barrels. The total reserves of Canada’s four major Cretaceous oil sands deposits is about 1.4 trillion barrels, or almost twice that of the known conventional in place reserves in the entire world.

Secondly, the physical characteristics of oil sands bitumen differ greatly from those of conventional crude oils. Oil sand bitumen is heavier (80API gravity, compared to 25 to 400API for most conventional crudes; remember from our earlier discussions that water is 100API gravity) and is much more viscous. Under reservoir conditions, the bitumen is essentially immobile. It has the consistency of a tar, and flows only when reservoir conditions are suitably altered (e.g., by heating).

Setting aside these two considerations, however, it can be seen that the oil sands deposits exhibit all the basic geological features that prevail in conventional oil reservoirs that we discussed earlier. The oil is contained within the pore spaces between the framework sand grains. The degree of oil saturation is a direct function of the porosity and permeability of the host sediments. Just as in conventional reservoirs, the distribution of rich and lean zones is controlled by the configuration and geometry of the sand bodies relative to the interbedded shaly strata. Considerations for source rocks, cap rocks, oil migration history, trapping mechanism—all of these are subject to the same type of geological analysis that we discussed previously and would apply in a conventional oil play.

Much is known about the geology of Canada’s oil sands deposits. Still, it must be acknowledged that our present understanding of the geology of the oil sands

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is far short of what it should be, given the current commercial interest in the resource and the pressing need to supply reliable input into the development of suitable extraction technology.

This deficiency has historical roots. Ever since the first explorers saw the Athabasca Tar Sands, the exploitation potential of the resource has been recognized, and it has been clear that problems of extraction are largely of an engineering nature. Petroleum geologists have been reluctant to participate in the development of the resource because the phase in which they are tradition-ally involved—exploration—has been by-passed. Only in the last decade has it been widely recognized that, if we are to succeed in developing appropriate in-situ technologies for the extraction of oil from the various deposits, we need all the geological insight we can muster.

Of the enormous petroleum reserves in place in Canada’s oil sands and heavy oil deposits, less than 5% lie close enough to the surface to be considered accessible by commercially viable open-pit mining techniques. If there is to be significant exploitation of the more deeply buried resources, it will be through application of a variety of in-situ recovery technologies. The economic incentive for developing these in-situ processes is great. In order to be successful, recovery technologies must be founded on an exhaustive understanding of the natural system in the subsurface.

Deposit categories Refer back to your reading and the figures in your textbooks while you study these notes. A sketch map of the main deposits is shown in figure 10.1 of your notes, and figure 10.2 provides a stratigraphic formation correlation chart. You might also want to consult an atlas or a simple road map of western Canada in order to get a better idea about the vast GEOLraphic areas that are being considered for exploitation.


Figure 10.1 Main deposits

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Figure 10.2 Stratigraphic formation correlation chart

The various deposits of oil sands and heavy oil are best considered as falling into three categories. The first group comprises Cretaceous oil sands deposits and includes the Athabasca, Wabasca, Peace River and Cold Lake accumulations. Virtually all of the reserves are contained within the Lower Cretaceous strata of the Mannville Group and its equivalents. The Mannville Group, comprising the formations Grand Rapids, Clearwater, Wabiskaw, and McMurray ranges in thickness from 150 m to about 300 m and consists mainly of unconsolidated clastic sediments of both continental and marine origin. In the Athabasca and Peace River Deposits, bitumen reserves are contained within single contiguous reservoirs. In Wabasca and Cold Lake, the reservoirs are stacked and are separated from one another by thick impervious shales.

The second group encompasses the Cretaceous heavy oil deposits of Alberta and Saskatchewan. These include a multitude of reservoirs in the Lloydminster area and a number of heavy oil deposits further south in the Suffield region. The heavy oil differs from the oil sands bitumen in that it is lighter (15–20oAPI, compared to 8–12oAPI) and allows some primary production. In the Lloydminster area the Mannville Group is differentiated into nine separate formations, with up to 20 individual reservoir zones, all arranged in very complex depositional patterns.

The final category of bitumen resources consists of reserves contained in the Paleozoic carbonate rocks that subcrop beneath the pre-Cretaceous unconformity over a large area of north-central Alberta. Indeed, the full extent of this “Subcrop Carbonate Trend” is still poorly defined. Knowledge of these deposits is based on relatively limited and scattered well control.


Reserves There are a total of about 1.4 trillion barrels of oil in-place within the various Cretaceous oil sands deposits. Of this total only about 74 billion barrels lie within the surface mineable region of northern Athabasca, where there is less than 50 m of overburden. Detailed work in this area suggests that approximately 41 billion barrels are recoverable by proven surface mining technologies.

Excluding the Subcrop Carbonate Trend, the total area of land underlain by the oil sands is about 58,500 km2. This area comprises four major deposits:

1. Athabasca, which is the largest in area and has in-place reserves of about 980 x 109bbls. The Athabasca is the only deposit to crop out at the surface and is the only deposit in which surface mining is possible. The surface-mineable area (the area in which the deposit is less than 50m from the surface) contains only a very small proportion of the total deposit. Most of the tar sands, about 90% of the total reserves, lie at depths beyond 50 m.

2. Cold Lake, which contains the second-largest reserves (270 x 109bbls). All oil sands in this (and the remaining two deposits) are at depths in which extraction must be done by in-situ processing (300-600 m). The oil is contained within three distinct Cretaceous-aged formations in the Cold Lake deposit: Cold Lake A – Grand Rapids Formation Cold Lake B – Clearwater Formation Cold Lake C – McMurray Formation

3. Wabasca, with reserves of 119 x l09 bbls. All oil sands are at depths of 75–750 m. The oil is contained in two formations: Wabasca A- Grand Rapids Formation Wabasca B- Clearwater Formation

4. Peace River having reserves of 92 x l09 bbls. Depths of the oil sands range from 300 m to 750 m with the oil contained in the Cretaceous Bluesky-Gething Formations (which are equivalent in age to the McMurray Formation).

Outcrop occurrences The entire Mannville Group is exposed in river sections in the vicinity of Fort McMurray. Only the McMurray Formation is oil saturated in this part of the Athabasca deposit. The Clearwater and Grand Rapids Formations, both of which are oil-bearing in Wabasca and Cold Lake, are barren. Still, the cliff sections along the rivers are valuable to geologists in that they give an opportunity to examine both vertical and lateral variability within the rocks. This is a luxury not available to workers dealing solely with subsurface data, where the control is, of course, only one dimensional (the borehole).

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Fundamental geological properties of oil sands Petrology of oil sands The role of the oil sands geologist is twofold. His/her first responsibility is to describe and characterize the rocks in as concise terms as possible, both for ease of communication with other scientists, and for purposes of quantifying rock properties in a manner conducive to manipulation in reservoir modelling and formation element testing.

The second responsibility involves trying to understand the geological controls on reservoir variability, so as to predict the geometry and configuration of the sand bodies in the subsurface, away from the drill holes. As you probably recall from your first-year Earth science course, this latter task is accomplished largely through a process called “facies analysis,” in which sedimentary features and structures are mapped and then compared with the features and structures known to be associated with specific depositional environments (for example, from present-day fluvial systems or well-known fluvial deposits from the geologic record). If we can peg down depositional environments, we can reasonably speculate about the form and configuration of the reservoir sand bodies, the likelihood of their persisting laterally, the chances of encountering specific discontinuities—all by analogy with known examples of that depositional environment.

The geologist must examine and compile a list of standard compositional and textural parameters used in order to describe and define the overall petrology of oil sands. These parameters include:

1. Grain size: absolute size and the proportional abundance of the constituent particles in the rock or sediment. High-grade oil-bearing sands in Athabasca are dominantly very fine- to fine-grained, although coarser sands (and local conglomerates) are present. Shale beds within the oil sands consist of clay- and silt-sized material.

2. Composition: defined on the basis of the mineralogy of the constituent particles. Typical Athabasca oil sands consist of:

Quartz: SiO2 ; greater than 90% of the sand grains;

Feldspars: KAlSi3O8 (orthoclase) and (Na,Ca) (Al,Si)AlSi2O8 (plagioclase); 1-5% of the sand grains;

Micas: K2Al4 (Si6Al2O20i (OH,F) 4 (muscovite) and minor biotite; <l% of the sand grains;

Heavy minerals: tourmaline, chlorite, zircon, staurolite, garnet, rutile, pyrite; trace amounts only;

Carbonates: CaCO3 (calcite) and FeCO3 (siderite); usually minor; and

Clay Minerals: kaolinite, illite, and montmorillonite.

In general, the mineralogy of Athabasca oil sand is extremely mature and stable: about 95% quartz grains, 2–3% feldspar grains, 2–3% mica and clay


minerals, and traces of other minerals. The composition of the other deposits varies, however.

3. Sorting, which is a measure of the uniformity of grain size of a given sample. Athabasca oil sands are moderately sorted.

4. Rounding, which measures the degree to which the sand grains have rounded corners, and sphericity, which measures the degree to which the sand grains approach spherical form. Athabasca oil sands are generally subangular, with moderate sphericity.

5. Porosity: high-grade Athabasca oil sands have porosity in the region of 30 to 35%, considerably higher than most subsurface conventional oil reservoir sandstones. The high porosity is mostly attributable to the lack of mineral cement in the oil sands, cement that in most sandstones occupies a considerable amount of what was void space in the original sediment.

6. Permeability: permeability of oil-free McMurray Formation sands is very high, but in the bitumen-saturated sands the oil is essentially immobile, and its presence effectively precludes significant movement of fluids through the oil sands.

7. Matrix, which is that particulate matter much finer than the principal constituent particles of the rock and occupies the pores between the clasts. Matrix material is normally incorporated into sediment at the time of deposition, but it may originate later as a precipitate in the pores. In sands, as the amount of matrix silt and clay increases, the sorting, porosity, permeability, and saturation decrease. High-grade Athabasca oil sands con-tain less than 1% matrix clay.

8. Cement, which is the chemically precipitated mineral matter that binds adjacent clastic particles together and gives strength to the material. Except for local instances of calcite or siderite cemented sandstones, the Athabasca oil sands are essentially free of cement. Thus, they are called “sands,” not “sandstones.”

9. Saturation or the extent to which the voids in the rock or sediment are filled by various fluids. Saturation is expressed as a weight percentage or a volume percentage of the total bulk. The highest-grade oil sands in Athabasca have oil saturations of about 18 wt.% (36 vol. %), with water saturation of about 2 wt. % (4 vol. %). Ore for the tar sands plants at Fort McMurray averages 12 wt. % bitumen. Anything over 10 wt. % is considered rich, 6 to 10 wt. % moderate, <6% lean. Even in the richest zones, there is still some water present, an irreducible water saturation of ~2 wt. %.

Another relatively common measure of saturation is “pore saturation”—the ratio of the volume of oil to the total void volume (porosity), expressed as a percentage. Pore saturation oil, plus pore saturation water, equals 100%. The pore saturations can be calculated for the Athabasca sands as:

Oil - 31 vol. %/35 vol. % = 89%

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Water - 4 vol. %/35 vol. % = 11%

10. Sedimentary structures or features of the internal form and configurations of the strata (cross-bedding, burrows, and the like) that yield information on the processes by which the sediment was deposited and/or subsequently modified. They are particularly important in determining the energy and direction of the transporting medium, the level of subsequent biological activity, and the nature of postdepositional deformation. Characteristic associations of sedimentary structures, along with grain size and provenance information, are the key parameters by which the sedimentologist assesses the depositional and postdepositional history of a given sequence of sediments.

Microscopic habitat of bitumen Perhaps the single most characteristic feature of the oil sands, and almost certainly the most fortunate, is that the grains are dominantly water wet or hydrophilic. The oil in the pores is not in direct contact with the mineral grains. Rather, each grain is surrounded by a thin film of water beyond which, in the center of the pore, is the oil. Thus, both the water and the oil form essentially continuous phases. The presence of the water envelope has been documented largely on the basis of inferential evidence, for it has not yet proved possible to sample and mount oil sands in such a way that the water envelope is not ruptured. Thus, geologists have never been able to actually “see” the water envelope by microscopic or petrographic methods.

The “fortunate” aspect of the oil sands’ hydrophilic nature is that the hot-water extraction process would not work if the grains were anything other than water wet. Indeed, not all oil sands are oil wet and the relatively cheap hot-water extraction method has there proved useless in numerous deposits in the United States and overseas. Canada’s hydrocarbon energy future would be markedly different, and probably much less optimistic than it is, if our deposits lacked this hydrophilic aspect.

Geology Of Canada’s oil sands deposits General geological history The most prominent oil sands deposits in North America are Early Cretaceous in age, meaning that the sands which host the heavy oil were originally laid down during that geological period, about 120 to 110 million years ago. In the eastern part of northern Alberta, the basal Cretaceous rocks (~120 m.y.) rest directly on Devonian limestones (360 m.y.). Towards the west the basal Cretaceous rocks rest on successively younger Paleozoic rocks until, in the Peace River area of central Alberta, they overlie Mississippian or Permian rocks. This major gap in the rock record (which you recall from your first-year course as being referred to as an “unconformity”) is representative of long-standing erosion in northern Alberta. Rocks of intervening age were probably laid down but were eroded away before the Lower Cretaceous sediments were finally deposited.


The depositional context of the Mannville Group sediments (i.e., all of the major Cretaceous oil sands formations) is as follows. Immediately prior to Cretaceous deposition in northern Alberta, the entire area was part of the North America interior continental landmass, subaerially exposed, and subject to the normal forces of physiographic sculpting such as we see all around us today (e.g., stream and river incision, mass wasting, etc.). Deposition of the initial Lower Mannville sands (the McMurray-Gething Formations) took place largely as a result of fluvial (river) deposition, localized principally in the depressions or troughs on the unconformity surface. Sand was supplied from source materials in the Precambrian Shield area to the northeast, and from the rising Cordillera in the west. Much of the upland areas (e.g., the Wabasca area) did not receive sediments.

Near the close of Lower Mannville deposition, the Boreal Ocean, transgressing the former land surface from the north, began to dominate sedimentation, and sands were deposited in deltaic and estuarine type environments. Soon the ocean had transgressed the entire area and a major seaway existed right through the heart of central North America, with marine shale deposition taking place over large areas (relatively deep water) and sands deposited in local shoreline zones. This episode is referred to as the Clearwater time.

Subsequently, during Grand Rapids time, the sea retreated to both the north and the south, probably the result of either a worldwide fall in sea level, or more likely through sedimentary build up and uplift in the central interior part of the continent. Deposition of Grand Rapids Formation sediment was largely in transitional sedimentary regimes, such as beaches, deltas, estuaries, and other shoreline settings. Climate during the entire Mannville interval was semitropical. Both land and sea vegetation were lush.

During the remainder of Cretaceous time, several hundred meters of marine and continental sediments were deposited. The strata were gently tilted to the southwest. Erosion and differential removal of several hundred meters of Cretaceous sediment took place during the Tertiary and Quaternary periods. In the Pleistocene, the region was subjected to repeated glaciations, with ice thickness up to 3 km, producing considerable scour and depositing varying thicknesses of glacial debris over the entire area. Finally, in the last 10,000 years, muskeg soils and a forest cover were established.

Depositional control of bitumen in the oil sands deposits The single most important control on the distribution of oil in the Cretaceous oil sands reservoirs relates to the facies patterns, as controlled by the depositional environments. Mannville Group sediments have undergone only very limited burial (<1 km maximum depth) and have been subject to only minimal cementation. The sediments remain largely unconsolidated. Original primary porosity and permeability trends have been preserved and the bitumen saturation in the reservoirs is largely a function of these primary porosity and permeability characteristics. Thus, ascertaining the facies patterns leads geologists directly to an understanding of the grade and configuration of the oil-saturated zones in the reservoir formations. In short, the detailed knowledge of

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depositional environments provides us with a valuable tool for prediction of reservoir character in the zones away from one dimensional borehole control.

Athabasca is the largest of the Cretaceous oil sands deposits in Canada, with estimated in-place reserves of 980 billion barrels. It is also the only deposit that crops out at the surface as an oil sands reservoir. Likewise, it is the only deposit with surface mineable reserves, and it is the only deposit from which there is commercial production at present.

The deposit lies in a broad depression on the unconformity surface, with the McMurray Formation thinning over the Devonian highs. The McMurray trough was initially filled by sediments derived largely from the east and northeast, deposited in a variety of fluvial and deltaic depositional environments. Subsequent reworking of the sands in some of the areas by large estuarine channels produced the sequences that are the most attractive reservoir zones. Marine shales of the Clearwater Formation form the reservoir cap over the entire deposit area.

Reserves in the Wabasca deposit are contained in mixed marine and continental sediments of the Upper Mannville Grand Rapids Formation. All of the reserves lie at in-situ recovery depths, 75–300 m. The Grand Rapids Formation is a sand-shale sequence with maximum thickness of 100 m. The sands are mainly fine-grained with some medium-grained beds and scattered chert pebble horizons. The mineralogy is complex, dominated by quartz, chert, feldspar, volcanic rock fragments, and clays. There are three main sand bodies, separated by relatively thick shale units. The two upper sands constitute the main reservoir zones. Maximum pay thickness is 25 m.

Reserves in the Peace River Oil Sands are contained in the Gething-Bluesky interval, which is correlative with the McMurray-Wabasca zone in the Athabasca area. The reservoir varies in depth from 300 to 750 m. The Gething Formation consists of sands and argillaceous sands, dominated by quartz and chert but with significant carbonate grains and rock fragments. Maximum oil saturations are about12 wt. %. The Gething Formation is interpreted to be dominantly continental in the southeast, becoming more marine towards the northwest. The Bluesky Formation represents the basal transgressive sand deposit of the boreal Clearwater Sea. It is rarely more than a few metres in thickness and contains abundant glauconite, an excellent marine indicator. The trap is an up-dip stratigraphic pinchout against a Paleozoic high.

The Cold Lake Oil Sands Deposit contains reserves in all three Mannville Group Formations. Reservoir depths vary between 300 and 600 m. The McMurray Formation in the Cold Lake area consists of very fine-to medium-grained quartzose sands with associated shales. Individual reservoirs are of limited lateral extent. In the Cold Lake area, the McMurray Formation is interpreted as being dominantly fluvial in origin. The Clearwater Formation consists of near shore marine sands and associated marine shales. Because the marine sands in the Clearwater interval tend to be laterally extensive, they constitute the most attractive reservoirs for in-situ recovery. The main Clearwater reservoir averages ~10–15 m in thickness. Porosity varies between


18 and 35%, and oil saturations of 14–16 wt.% are common. The Grand Rapids Formation at Cold Lake is divided into an upper member and a lower member. The sequence consists of interbedded sands and shales deposited in near shore marine and continental environments. The sands are mineralogically complex, with quartz and feldspar grains, volcanic rock fragments, chert, and clay. Despite the fact that the Grand Rapids Formation contains the majority of the reserves at Cold Lake, the various reservoirs are not as continuous or homogeneous as those in the underlying Clearwater Formation, and are thus not as attractive to in-situ recovery.

The heavy oil deposits of western Canada occur mainly in the vicinity of the Alberta/ Saskatchewan border, in a trend extending from the Lloydminster region in the north to the Suffield area in the south. The reserves in the Lloydminster area are confined to the Lower Cretaceous Mannville Group. In this region the Mannville Group consists of a complexly differentiated sequence of sands and interbedded shales, containing a total of nine different formations. The basal Dina Formation is correlative with the McMurray Formation to the north. The sequence from the overlying Cummings Formation through to the Colony Formation correlates with the Upper Mannville in the oil sands area. Individual heavy oil pools, commonly of very limited lateral extent, occur at virtually all levels within the Mannville section. The best reservoirs are in the Sparky and Waseca Formations. The McLaren, G.P., Rex, and Lloydminster Formations contain pools of intermediate magnitude. Cummings and Colony Formation sands contain very little oil.

The Subcrop Carbonate Trend encompasses bitumen-bearing rocks beneath the pre-Cretaceous unconformity. The subcrop consists of Upper Devonian and Mississippian carbonate rocks, dominantly dolomite and dolomitic limestones, with some calcareous shale. The principal reservoir formations include the Devonian Winterburn and Wabamun Formations, and the Mississippian carbonates of the Pekisko Formation. Geological controls on the distribution of bitumen are poorly understood, but it appears that some of the rich zones are controlled by primary porosity trends, some by secondary (vuggy) porosity, and others by fracturing, solution, and brecciation associated with weathering and karstification of the exposed Devonian landscape.

In-situ extraction of bitumen from the carbonate rocks will almost certainly involve technologies, which contrast markedly with those employed in the overlying Cretaceous sands. One of the most important factors relates to the highly reactive nature of the carbonate materials in comparison with the siliceous detritus.

Origin of the oil There remains considerable debate about the origin of the oil in the oil sands. One school of thought is that the oil originated in Mannville source beds (mainly Clearwater shale), and migrated down into the porous and permeable McMurray Formation sands where it was ultimately trapped. The other school suggests Paleozoic source rocks, with the oil migrating up to the unconformity and flooding into the basal Cretaceous McMurray Formation.

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As we discussed earlier, in general, the origin of liquid petroleum is relatively well understood. Upon burial, the organic matter in sediments is subjected to biochemical degradation, yielding complex organic compounds collectively known as kerogen. With further burial, and consequent increase in temperature, various hydrocarbons are liberated mainly by thermochemical reactions: first immature natural gas, then crude oil, then mature natural gas. Under normal geothermal gradient conditions in a basin, the normal course of thermal maturation yields maximum amounts of oil when the rock containing the organic matter is at depths of 2–3 km. If this oil is then expelled from the source beds into adjacent porous strata, it is free to migrate up-dip until it encounters permeability barriers that result in three-dimensional closure (i.e., it cannot migrate further).

Once pooled like this in the reservoir, the oil is subject to further alteration by a number of agencies. Some processes, such as gas deasphating and thermal alteration, can enhance the quality of the pooled crude, converting it into a lighter product (higher API gravity). Alternately, the pooled crude may be subjected to water washing and/or biodegradation, both of which yield products that are heavier than the original oil (lower API gravity). A large body of evidence indicates that the oil in the oil sands was once a thermally mature crude, but that it has been subjected to extensive biodegradation and water washing in the near-surface realm.

Geological observations on the distribution of oil within the McMurray Formation reservoir indicate that at the time the oil was pooled, it was much less viscous (and probably lighter) than at present. This observation supports the proposal that the pooled crude was degraded in-situ. Locally, there are small pockets of natural gas trapped within the reservoir rocks, and in places there is a water-bearing leg beneath the oil column. Both of these features are common characteristics of petroleum reservoirs in general.

Details of the trapping mechanism are more difficult to understand. The impermeable Clearwater shales clearly acted as the cap rock, or roof, for the trap. But how the reservoir was laterally confined is still uncertain because the outer limits of the deposit, particularly on the east side, are not marked by permeability barriers. In short, there is no three-dimensional closure! Why the oil did not continue to migrate eastward is thus difficult to understand, because the sands to the east are at least as porous and permeable as the reservoir sands.

Regarding the time of oil migration, most geologists agree that it was probably only in Late Cretaceous time that there was sufficient overburden in the region to generate the vast amount of liquid petroleum that is now contained in the oil sands.


Other geological considerations in exploitation Surface mining Designing, building, and operating an oil sands mining facility involves consideration of many factors. In the final analysis, of course, it is the economics of the undertaking that are of paramount concern. Nonetheless, geology has an impact on virtually every aspect of a mining project, from preliminary lease evaluation to reclamation.

From a geological point of view, the principal base requirements for a viable mine are: • that there be sufficient reserves to support a plant life of 20–30 years; • that the ore body be continuous enough to allow for a reasonable mine

layout (ore being defined as > 8 wt. % oil sand); and, • that the overburden to ore ratio be about 0.6:1.

The reason that 8 wt.% bitumen is used as the cutoff between ore and non-ore sand is that difficulties appear in the hot water process at saturation levels below 8 wt.%. The current mining projects are designed to utilize sands averaging 11–12 wt. % bitumen.

In-situ recovery At present, there is no in-situ technology that has been proven to be viable on a large commercial scale. Furthermore, there seems little likelihood that a single recovery technology will be adaptable to all geological conditions. What works in Peace River, for example, may not work in the mineralogically more complex Cold Lake sands. Thus, the emerging technologies are exceedingly complex.

Heavy oil reservoirs have virtually no natural drive energy. Thus, in order to mobilize and produce the bitumen from the subsurface it is necessary to alter its physical characteristics. This normally involves reducing the viscosity of the bitumen by the addition of heat and/or solvents. There are a number of pilot-tested recovery schemes founded on this basic premise, the most prominent of which are Cyclic Steam Stimulation (“Huff and Puff”), Steam Injection, In-situ Combustion (wet or dry, forward or reverse), and Electrical Heating.

From a geological point of view the most crucial input into the recovery process relates to providing predictive capability beyond the borehole: furnishing the engineer with a three-dimensional picture of the geometry of the reservoir sand bodies and the intervening shaly strata. In order to do this the geologist must come to grips with all aspects of the depositional environments as they relate to the facies patterns. Only through detailed sedimentological and petrological analysis can we hope to do this. Thus, for geologists working in in-situ areas, the first priority is to achieve a good understanding of the facies patterns. It is at this point that geologists and engineers diverge: the engineer has little interest in the detailed depositional environments of the sands. All he/she wants to know is essentially “how far is this 2 m shale barrier likely to persist laterally?” The best a geologist is likely to give him is a well-educated guess based on analogue studies of similar facies patterns.

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Apart from detailed facies patterns study, there are numerous other areas in which geological work needs to be done. Several of the most prominent of these are described below.

• Subjecting oil sands to intense heat may cause reactions to take place between the mineral matter and the associated fluids (formation fluids and injected fluids). These reactions involve organic and inorganic compounds and may be extremely complex. Indeed, many solution and reprecipitation reactions could have deleterious effects on reservoir porosity and permeability. Clearly, there is need for much study of the kinetics and thermodynamics of these reactions.

• There is considerable scope for experimental work. It is possible that turbulent flow of fluids through the porous oil sands could induce physical movement of fine particulate matter, especially clays. Trapping of these clays in pore throats, leading to plugging, or production of clays, giving rise to refining problems, are possible problems.

• Several proposed in-situ production schemes are dependent upon basal communications along permeable paths between injection and production wells. If natural communication routes do not exist, there is a need to develop artificial paths. Artificial horizontal fracturing is one possible means by which this may be accomplished. But there is much still to be learned about how tar sands and heavy oil deposits behave when subjected to the pressures required to fracture the sediment.

Review questions 1. Compare tar sand bitumen and heavy oil with conventional oil and with

water in terms of density. 2. List the four major tar sands deposits in Canada in order of size. 3. What is the age of the reservoir in which the bitumen occurs? 4. Characterize the Athabasca Tar Sands with respect to grain size, sorting,

and porosity. 5. What does the term “water wet” mean? 6. How were most of the McMurray sands deposited in the Athabasca area?


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Assignment 4

1. List, in order of amount of in-place reserves, the four main tar sands deposits of western Canada and show, with a sketch map, the approximate location of each.

2. Summarize the geological history of the tar sands of western Canada.

3. List in order of increasing rank: brown coal, peat, anthracite, bituminous coal, semi-anthracite.

4. How is rank measured?

5. What is sapropelic coal?

6. Compare and contrast the elemental composition of (a) petroleum, (b) kerogen, (c) natural gas, and (d) lipid organic matter.

7. Discuss the temporal distribution of coal in the world.

8. Describe and discuss the use of a Van Krevelen diagram.

9. Summarize the anticipated change in ratio (between today and about the year 2020) among the amount of energy Canada derives from oil, natural gas, and coal.

10. What factors have controlled the development of the oil shale industry?

11. Which of the fossil fuels has the greatest ultimate potential to produce usable energy?

12. What/where is the Strategic Petroleum Reserve and what is its primary purpose?


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Module 3 Mineral Resources


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Unit 11 Economic Geology, Iron, Alloy Metals, and Base Metals

Topics Economic geology Mineral resources Geology of mineral deposits Crustal processes and ore deposits Iron ore Alloy metals Rare Earth metals Base metals Precious metals

Introduction The mining industry is one of the oldest of human endeavours. There is no question that society as we know it could not exist without the amazing array of products that are generated and produced by mining. In our final module, we will examine the geology, GEOLraphy, and scope of the world’s mineral resources.

Learning objectives By the end of this unit you should be able to: • summarize the historical impact of mining on society;

• outline the major ore minerals and their GEOLraphic locales for iron ore, alloy metals, rare earth metals, base metals, and precious metals; and

• discuss production trends and marketing strategies for the various groups of metals.



3. Read pages 239–329 in Resources of the Earth.


Study notes Key terms Agricola hematite alloy metal Hutton anglesite komatiites banded iron formation limonite BIF magnetite black smoker midocean ridge bog ore mineral deposit carnotite Mississippi Valley Pb-Zn cassiterite molybdenite cerussite placer chalococite Red Dog deposit chalcopyrite REO chromite REM copper scheelite Cuvier siderite Descartes syngenetic deposit economic geology vanadinite epigenetic deposit Werner galena wolframite hematite

Economic geology Economic geology is one of the oldest forms of human knowledge and endeavour. The first human beings, some 2 million years ago, were users of cutting tools. They soon learned which stones were better than others for this purpose. Also clay was used early, first for pots and later for bricks. Neolithic man was acquainted with gold and copper. The first used metals were probably found as native metal on the bottom of creeks. The Egyptians, Babylonians, Assyrians, and Indians, precious stones were held in high esteem. The Pharaohs sent prospectors and miners to Sinai and the Sudan looking for turquoise and emerald. Lapis lazuli was obtained from Afghanistan which points to early distant trade in minerals.

Copper was used in Europe around 4000 B. C. and gold and copper had been known in Egypt several thousand years earlier. Greek and Roman philosophers were also some of the earliest geologists and were interested in ores and their genesis. Agricola, the father of mineralogy and metallurgy born in 1555, wrote the first textbook on economic geology and was also credited with the first theory about the genesis of ores. In the seventeenth century, Descartes saw the earth as a cold star with a hot interior. He contended that the ore minerals were pressed upwards and deposited as lodes in the cracks of the outer crust.

In the eighteenth century German and Swedish scientists had lively controversies about hypotheses on the genesis of ores. One of the most famous, Werner, discarded the theories about an interior origin of metals and suggested

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that mineral veins had been formed by precipitation from water percolating down from a primeval universal ocean. This origin was ascribed not only to ores in sedimentary rocks but also to igneous and metamorphic rocks. As you recall from your first-year course in Earth science, Werner became the leader of the Neptunist school.

A generation later Cuvier dominated the geological thinking of the time with his theory of catastrophism. It was generally thought that earlier periods had been exposed to more dramatic natural processes than the present time. Both Neptunism and catastrophism were criticized by Hutton who was the leader of the Plutonist school. Ultimately this lead to the doctrine of uniformitarianism: to understand the rocks (and ores) Hutton and his followers only needed to study the geological processes that currently could be observed. It was not until the mid-nineteenth century that von Cotta pointed out that there are many types of ores and that they were most likely formed by widely separate processes.

However, it was not until 1974 that ore formation was actually studied directly in the field. At this time geologists went down to the sea bed at a depth of over 2,700 m at the rift valley in the middle of the Atlantic Ocean. Here in the rift valley molten magma is only some 10 m below the surface. The geologists were able to observe that as the magma gets in contact with water metals are separated and either deposited in cracks in the rock or gushed out by geysers and deposited on the seabed. It is now accepted that many ores on land have been formed in one of these two ways.

Mineral resources The word “mineral” can be defined in a variety of ways. One definition includes any naturally occurring substance that is not a vegetable or an animal. A you recall from your first-year course, geoscientists define minerals as all the naturally occurring solids—plus a few liquids—that display distinctive chemical composition and crystalline structure and that are the components of rocks. To the economic geologist, however, minerals are simply materials extracted from the Earth that have current or potential economic worth, and any site from which this material can be recovered is considered a mineral deposit. For this section of our studies, the most appropriate definition is that a mineral resource includes any naturally occurring combinations of elements.

As discussed above and in your textbook readings, understanding the location of metallic and nonmetalic ores and how to mine them is one of the most ancient fields of scientific endeavours undertaken by humans. Exploration of mineral deposits is similar in some ways to oil and gas exploration. Both are strongly affected by economic fluctuations and politics. Advances in geology, geophysics, geochemistry, and data-gathering and data-handling capabilities have revolutionized mineral exploration and development, as they have the petroleum industry.

Mineral resources are generally concentrations of one or more of the materials that constitute the solid Earth. As you recall from your first- year course, over 99% of the Earth’s crust is made up of only nine elements: oxygen, silicon,


aluminum, magnesium, iron, calcium, sodium, potassium, and titanium. But it is the other ~1% of the crust that interests the mineral-exploration geoscientist. This interest centers on understanding the processes that form the mineral deposits, the environments in which those processes operate, and the distribution of deposits through space and time. Obviously, with this understanding, new deposits can be predicted and discovered.

Mineral deposits form through a wide range of geological processes, but the net result of nearly all of these processes is concentration. Less than one part in 10,000 of the metals present in the upper km of the crust is concentrated in known mineral deposits. The remainder is widely dispersed at low concentrations and, thus, is unsuited to economical recovery. A major point of mineral exploration (like petroleum exploration) is that ore deposits are rare.

The locations of undiscovered major mineral deposits are among nature’s best-kept secrets. Except for some industrial mineral deposits, such as sand, salt, or limestone, most mineral deposits constitute very small targets in complex but otherwise normal but valueless rocks. Concentrations comprising ore quality are rare and difficult to find, but their values can be immense. An example is the recently developed Red Dog Pb-Zn-Ag deposit in the arctic of northwest Alaska, which contains metals worth about $35 billion within a 5 km2 area. The Red Dog deposit is also remarkable because the ore was exposed at the surface and was visible to a curious pilot who talked a geologist into flying over the strange rocks. But such obvious occurrences are rare. Most exposures of significant concentrations appearing directly at the Earth’s surface have long ago been discovered by prospectors. The tops of near surface deposits are commonly worn away by weathering, or concealed by soils, glacial deposits, swamps, or lakes. Unexposed deposits usually indicate their presence only by meagre evidence.

The targets of mineral concentrations required for economic recovery are not only small but can be extraordinarily localized. For example, seven gold fields covering an area of about 5,000 km2—no larger than the area of Lake Manitoba—have produced more gold than has been discovered over the entire remainder of the surface of the Earth. The Hg deposit at Almaden, Spain, has yielded more mercury than any other source and still retains the bulk of the world’s reserves. The Bushveld intrusion in South Africa contains over 98% of the world’s Cr reserves, most of them in a single layer. Such rich deposits represent only minuscule proportions of otherwise ordinary parts of the crust. The possibility exists that similar deposits are hidden in the unexposed basement rocks of the North American mid-continent, beneath the jungles of South America or Southeast Asia, or under thin coverings of glacial debris in northern Canada. Thus, the driving mechanism for mineral exploration is that it has the potential to be a very prosperous undertaking.

To illustrate the fact that new sources of minerals continue to be discovered, consider two mineral sources that were once thought to be unique: the Climax molybdenum deposit and southeast Asian tin. The Climax molybdenum deposit at Fremont Pass, Colorado, was for over 50 years the single most important source of molybdenum, which is used in the steel industry. Despite abundant

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markets, other major molybdenum deposits were not identified until the 1960s, when a full understanding of geological characteristics of the Climax deposit were finally known and then recognized in numerous other localities. The result was that a series of major molybdenum deposits was discovered. Similarly, the marine placer deposits of southeast Asia dominated the world tin market for years, because they could provide tin more cheaply than any other source. However, in the 1980s the world tin market collapsed, and many southeast Asian operations were sharply curtailed when abundant low-cost tin emerged from new discoveries in Brazil. Thus, molybdenum and tin are examples of mineral resources in which suppliers suddenly found themselves downgraded or displaced by more economically competitive sources.

But new deposits are not the only reasons for the rapid changes that characterize the mineral resources industry. Other factors include price fluctuations in response to changing demands, environmental concerns that restrict mining or processing, or local or national policies that encourage or discourage mineral exploration and development. Changes also frequently result from new or improved technologies.

Geology of mineral deposits Ore deposits can be subdivided into two major categories: epigenetic and syngenetic. Syngenetic deposits are those mineral concentrations that formed at the same time as the host rock. Epigenetic deposits involved the addition of minerals to an existing rock, such as we might get by the process of precipitation from migrating aqueous solutions. These epigenetic ores tend to form at contacts between rock types or near the margins of discrete rock bodies such as intrusive masses. They are normally found within a few km of the surface, where enriched solutions can mix with surface waters. In short, epigenetic deposits are associated with near-surface environments. Their host rocks are variable and often lack any genetic affiliation with the ore minerals. In contrast, syngenetic deposits, which are generated along with their host rocks, are spread throughout the crust.

Crustal processes and ore deposits Plate tectonics concepts have been routinely applied to mineral exploration for many years and the association between tectonic environment and certain types of mineral deposits is now clear. For example, the genetic links between porphyry copper deposits and volcanic arc systems are well-established.

As the Earth evolved, the abundances of various types of mineral deposits also changed. Until ~2.8 billion years ago, Mg-rich lavas known as komatiites erupted on the seafloor and, as they crystallized, precipitated rich deposits of nickel that are now preserved in Canada, Australia, and South Africa. Komatiites have been essentially absent from the numerous varieties of rocks forming on our planet since 2.8 billion years ago.

Between about 1.8 billion and 2.8 billion years ago, huge sedimentary banded-iron deposits (or banded iron formations, BIF) formed in what are now areas of Australia, Brazil, Russia, and the Lake Superior region of the United States and


Canada. At the same time, gold and uranium were accumulating as placer deposits. These iron deposits now form the bulk of the world’s economic iron resources, and the paleoplacers include more than 50% of the total known gold resources. No accumulations anything near the size of these BIF and gold-bearing paleoplacers have been discovered in rocks that have formed since.

A detailed understanding and explanation of this obvious time-dependent genesis relationship has been slow in forthcoming, however. For example, we only recently now accept that the mantle of the younger Earth was hotter than it is today. These very high temperatures were required to keep the komatiites molten, close enough to the surface to permit eruption of the rock magmas. Likewise, we now realize that formation of the large iron deposits and the gold-uranium-rich placers is due to a much different composition of the early atmosphere.

The Pb-Zn ores of the Mississippi Valley region are important sources of zinc and lead within the United States. These ores result from the filling of solution cavities in carbonate rocks with metal-rich material at relatively low temperatures (<125oC). We now realize that this ore-forming process was related to migrating fluids in the compacting sedimentary basins.

Clearly, economic geologists have much in common with petroleum explorationists: both try to build models for exploration that address the questions of source, migration, and traps. However, mineral deposits are generally more complex because there is not a single source material, as there is in petroleum formation. Minerals may originate in the mantle or in the crust and may represent concentrations in a particular environment, such as dissolved salts in the ocean, which are concentrated by evaporation until they form economic salt deposits. Transport processes are equally varied.

The variety of possible formation environments for copper deposits illustrate this complexity. Copper deposits occur in primary or altered sedimentary environments, in veins within rocks of all types, in products of seafloor hot-spring vents, and in mafic lavas. This multitude of host environments indicates a variety of deposition and transport processes, which complicates the task of categorizing and studying copper resources. Deposit types for many other metals are just as diverse. Indeed, the source, transport, and accumulation processes that concentrate minerals in deposits are seldom fully understood, in marked contrast to most oil and gas accumulations.

Early ideas about the origin of mineral deposits were based largely on association and conjecture because only a few examples of ore formation could be directly observed (e.g., placers forming in streams, volcanic fumaroles yielding sulfur and metallic precipitates, evaporation of playa lakes, and marine lagoons depositing salt). However, in the past few decades many additional examples of direct observation of ore formation have been recognized.

Since 1979 many spectacular discoveries of huge thermal springs have been made at the Earth’s spreading centers along the mid-oceanic ridges in the Pacific and Atlantic oceans. Heat from sub-seafloor basalt creates circulation of hot seawater and reactions between the water and the basalt form strongly

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acidic solutions. These solutions are able to leach metals and sulfur from the rock and then this material is deposited at the vent openings on the seafloor. Cones containing iron, copper, zinc, gold, and other metals have been observed to be forming at the active vents, which commonly have temperature up to 350oC. The rapidly precipitating sulfides in the vicinity of these vents give rise to the graphically-named “black smokers.”

Iron ore Iron, the basis of our civilization, accounts for 5% of the earth’s crust. However, for economic exploitation only concentrations with much higher iron content are of interest. Location and chemical characteristics influence the feasibility of mining and may lower the limit for iron content that make the rock an exploitable ore. Nonetheless, few deposits of less than 30% iron content are being used; most large iron mines have ore with iron contents exceeding 50%.

As the noniron parts of the ore only increase the amount of slag in the blast furnace, the ore is often crushed, concentrated, and cleaned before being put into the furnace. This process is known as beneficiation.

The most important iron-bearing minerals that form iron ores are oxides: magnetite (Fe3O4) is black in colour; hematite (Fe2O3) is red; limonite or bog-iron ore (2Fe2O3, 3H2O) is brown; and siderite (FeCO3) is pale brown. Magnetite and hematite are by far the most important sources of iron for the world’s steel industry. Pure magnetite contains 72% iron, pure hematite 70%, and limonite 60%. Siderite holds only 48% iron. However, the iron-bearing mineral is hardly ever the only one in the ore, and thus the metal content is lower than the theoretical values. Rich iron ores seldom exceed 65% iron.

Most of the world’s iron ores are sedimentary in nature. A well-known example is the limonite that was deposited in lakes and bogs. Under the name of lake or bog ore it played an important part in the early iron industry. The large iron ore fields near Lake Superior in the United States also belong to this category. They are made up of hematite ore, made relatively rich through weathering and natural beneficiation. Until recently, this ore was the main basis of the large American iron ore production. The surrounding sediments are low grade, strongly cemented, and unweathered.

Many sedimentary ores have been changed and metamorphic ores of sedi-mentary origin may be difficult to distinguish from those of igneous origin.

Alloy metals All steel, in addition to iron and carbon, contains small but important amounts of other elements such as silicon and manganese. To give ordinary carbon steel characteristics, which are in demand, one or more metals are added. The material added to the ore is usually prepared at a special ferroalloy plant. The ferroalloys produced in these works contain a high percentage of other elements such as chromium, cobalt, manganese, molybdenum, nickel, tungsten, vanadium, silicon, or cerium. Most of these elements are added as pure metals rather than oxides.


“Alloy metal” usually refers to those metals added to steel. However, nonferrous metals are also alloyed. Common alloys of the latter type are bronze (copper and tin) and brass (copper and zinc). These alloy metals are usually mined only in a few restricted areas. They are indispensable in the manufacture of armaments and are often referred to as strategic materials.

World production of manganese and chromium ores amount to millions of tons, but for the other alloy metals quantities are rather small.

Manganese in small amounts is used in the production of most kinds of steel. Normally the manganese content is about 1%. The purpose of the input is to neutralize the negative effect of sulphur on the high-temperature strength of steel. Larger amounts, up to 14%, are added to give steel a hard surface. Manganese is also used in the manufacture of bricks, glazed pottery, plastics, floor tile, glass, varnish, and dry-cell batteries.

Before the World War II the Soviet Union and India were the dominating producers. More recently China and South Africa have made a rapid postwar expansion into Mn production and is now almost on a par with India.

The conspicuously small North American production of manganese may help explain the interest shown by the United States in exploiting the tremendous deposits of manganese nodules on the deep sea floor. The nodules also contain other metals of interest including copper, nickel, and cobalt, in amounts that may satisfy the needs of society for hundreds of years. Geologists have estimated that some of the manganese nodules form faster than they can be used, making them a renewable resource.

Chromium is second only to manganese among the alloy metals. Small amounts increase the hardening ability of steel. Steel with 1% Cr + 4% Ni is used in most tools. Larger amounts of Cr increase the high temperature strength and corrosion resistance as well as resistance, to wear. Stainless steel (8% Ni, 18% Cr) is used widely in machinery where steam, water, moist air, or acids would corrode ordinary steels.

Chromite (Fe0 Cr2O3) is the only chrome mineral of significance. Several small countries in the former Soviet Union dominate the output of chromite ore. Additional production comes from Asia. The Western Hemisphere has very little chromite ore.

Nickel gives strength to iron and other base metals. For heat and corrosion uses, nickel has no substitute. In jet engines, gas turbines, and rockets, nickel is used. It is used with chromium in the making of stainless steel. Among the nickel-copper-alloys is “monel metal” (67% Ni, 28% Cu, 5% Fe), which is highly corrosion resistant to salt water and therefore is used in pumps, propellers, and mine screens. “Permalloy” (80% Ni, 20% Fe) is an easily magnetized and demagnetized alloy used in electromagnets.

The mining of nickel is more localized than that of most other metals. The complex nickel ores usually also contain copper and other metals. They are associated with basic igneous rocks. Some 80% of the world’s production has been obtained from underground sulfide ores in Canada, but in fact over 70% of

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the known nickel reserves are in laterite deposits in South America and Africa. Since 1900 Canada has supplied most of the world’s nickel with Sudbury by far the leading nickel producer, followed by mines at Lynn Lake and Thompson in northern Manitoba. Several companies participated in the development of the large nickel deposit at Sudbury, which was discovered in 1883 in connection with the construction of the Canadian Pacific Railway. The companies were merged in 1902 and formed the International Nickel Company (Inco).

Tungsten is used in steels for high-speed cutting tools (18% W) and in hard metal for rock drills, as well as in pure form in electric-lamp filaments. It has the second highest melting point among the elements. Hard metal or cemented carbide is a mixture of tungsten carbide and cobalt in which cobalt is used as a binder. Tungsten carbide is almost as hard as diamond. It is used in cutting tools and abrasive wheels. Steelite, a W, Co, Cr-alloy, is used for hard facing of other metals: armour plates, guns, and armour-piercing projectiles.

The principal tungsten mineral is wolframite, (Fe, Mn)WO4, which contains only 3% tungsten. It is concentrated to about 60% tungsten oxide before being shipped to the market. Another tungsten mineral is scheelite, CaWO4. China has long been the leading producer of scheelite and wolframite, followed by Korea and the Caucasus region of Eurasia.

Because Communist countries accounted for most of the world output of W, in the 1950s many western countries made a great effort to force into production marginal deposits. For example, in the United States some 700 mines were producing in 1956; none are producing today.

Antimony is found in stibnite, Sb2S3, the only important antimony mineral. Many copper, silver, gold, and lead ores contain some antimony. The metal has a low melting point and expands during solidification. As much as 30% antimony is alloyed with lead to increase the hardness of the lead. Lead-antimony-alloys are also used in pipe, electric cable coverings, buckshot, solder, foil, and storage battery plates. Antimony compounds enter paint pigments, fire-proofing materials, glass, and rubber.

China is the leading producer of Sb with large deposits in the central and northern parts of the country. South Africa, which is near to China in total production, obtains its antimony as a by-product from a gold mine in the Transvaal. Bolivian antimony is mined with many other metals at Potosi and other places in the tin belt of the Eastern Cordillera. Other producing regions include: central Siberia, the Urals, and eastern Turkestan. The largest producer in the Western Hemisphere is Mexico, which produces Sb as a by-product from lead mines.

Molybdenum has a high melting point and adds strength and creep resistance to steel at high temperatures. At low temperatures molybdenum increases the corrosion resistance of steel. Molybdenum can be used as a substitute for tungsten, which was of importance during the Cold War. Molybdenum steel is used in propeller shafts, gun barrels, and high-speed tools.


Molybdenite, MoS2, is the only important mineral. The world’s largest deposit is at Climax, Colorado. The low-grade ore is crushed and concentrated through flotation. Tailings are processed in by-product plants for the recovery of both tungsten and tin. The balance of the Northern American molybdenum production is obtained as a by-product, from copper mines in Utah and Arizona. The United States accounts for more than 75% of the world’s output, followed by Canada. The Canadian production is from a series of Vanadium in small amounts increases the toughness, hardness, and fatigue resistance of steel. Such steel is used in armour plate, rock drills, springs, and other components in automobiles, locomotives, and guns.

In minor amounts vanadium is present in most rocks, but concentrations rich enough to be exploited are relatively few. United States produces vanadium from mines in the Colorado Plateau region where the mineral carnotite, K2O 2UO3 V2O5 2H2O, was mined (for its uranium content) yielding vanadium as a by-product. Also in this Colorado Plateau region, the mineral vanadinite Pb5Cl(VO4)3, is mined for both vanadium and lead. However, with the decrease in uranium mining, South Africa has now become the dominant producer of V. Peru, once the world’s leading producer, and Zambia have recently both suspended production.

Cobalt in steel, especially if it also contains tungsten, increases its hardness and high-temperature strength. Cobalt alloys are used for cutting tools in lathes (high-speed steel and hard metal) and for components in jet engines and atomic energy reactors. Heating coils in electric radiators also contain small amounts of cobalt. Cobalt is also used in the production of permanent magnets. Finally, cobalt is an ingredient in paints and medicine. The radioactive isotope of Co is commonly used in radiotherapy.

Almost all cobalt is obtained as a by-product of ores worked for other metals. Leading producers are Zaire, Sudbury, Canada, and Finland.

Niobium, in very small concentrations in normal carbon steels, lowers the grain size of steel, thereby increasing its strength. This material is used for machine parts. Small amounts of niobium in low-carbon steel increases resistance to deformation. In greater amounts (1%) the steel becomes very resist to deformation and is used in jet engines, gas turbines, rockets, and missiles. Chief producing areas are Africa, Bolivia, Brazil, and Malaysia.

Tantalum retains its strength at very high temperatures and is used in alloys for jet engines and missiles. It is resistant to corrosion by most acids and is used for chemical, dental, and surgical instruments. It is mined chiefly in Africa, Brazil, and Malaysia.

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Rare earth metals The rare-earth metals scandium, yttrium, and the fifteen elements in the lanthanide-series have also acquired economic importance as alloy metals. They are sold as rare-earth metals (REMs) or “misch metal,” which contains 50% cerium. Separation of individual metals is very complex because of their great chemical similarity. Prices for individual metals are therefore very high.

REM and REO (rare earth oxides) are also used as catalysts in petroleum cracking, glass manufacturing, and for ductile steel. In metallurgy, misch metal is used because of its high affinity for sulphur and the increased hardness of the REM-sulfides. The increased ductility make such steels attractive in shipbuilding and for pipelines.

The rare-earth metals have turned out to be less rare than originally thought. The former Soviet Union has large deposits of REM and REO associated with apatite ores. United States has large production from California; both Australia and India have deposits associated with monazite beach sands.

Base metals If iron was the most important metal in helping develop our civilization, the modern machine culture depends as much on the base metals such as copper, zinc, lead, and tin for continued development.

Copper has been used for millennia in tools, weapons, and ornaments. Bronze (an alloy of copper and tin) was used before iron was known. But copper really came into its own with the Age of Electricity. Copper is a good conductor, can be drawn into wire easily, and resists corrosion. More than half of all the world’s copper is used as wire in electrical equipment. Most of the rest is used in copper alloys, chiefly brass (copper and zinc), but also bronze. Some copper goes to roofing, plumbing, hardware, jewelry, and decorative objects.

Copper deposits are quite widespread but six countries account for about 90% of the world’s output. Concentration, smelting, and refining are also GEOLraphically concentrated in these six countries (USA, Canada, Chile, Eurasia, Zambia, and Peru). The most important copper minerals are chalcopyrite (CuFeS2) and chalcocite or copper glance (Cu2S). Copper is reusable on a large scale. Some 60% of all copper is recycled, but with a long lag: the average life of copper in a given use is over 40 years. Secondary copper accounts for 40% of world consumption.

Tin has a low melting point, is malleable and ductile. It forms alloys easily, resists corrosion, is nontoxic and makes excellent solder. Tin is used in most electric and electronic equipment, but its principle use is as coating for steel.

The most common tin-bearing mineral, cassiterite (SnO2) is obtained from alluvial deposits, mainly in southeast Asia. The only producer of Sn in the Western Hemisphere is Bolivia. Africa is also an important tin mining area, primarily Zaire and Nigeria. Both Zaire and Nigeria gained prominence during World War II when the mines of Southeast Asia were taken over by the Japanese.


Zinc is used for coating iron or steel (galvanization), which makes it more corrosion resistant than ordinary iron or steel, in alloys such as brass (copper and zinc) and in die-casting alloys which can also have an aluminium, copper, tin, or lead. Zinc oxide serves as a paint pigment and enters into various chemical and medical preparations.

Zinc is rarely mined alone but is usually associated with lead and often with copper, gold, or silver. It is a rather common metal, found on all continents and in many countries. Production is no longer dominated by one or a few regions although historically most production has come from Canada, Australia, and United States.

Lead is one of the earliest known metals. The Chinese used lead in coins at 2000 B.C. The silver-lead mine at Laurion near Athens was exploited about 1200 B.C. The water conduits of lead at Pompeii and the lead roofs of the Venezian prisons are well-known.

Lead is heavy, soft, ductile, and malleable. It alloys easily and is corrosion resistant. It has a low melting and a high boiling point and is not penetrated by short-wave radiation.

The electric industry takes almost half the lead for storage batteries and cable coverings. The chemical industry is another large lead consumer: tetra-ethyl-lead, paint pigments, ceramics, plastics, bullets, and insecticides. Lead is used in the construction industry and in alloys such as solder, bearing metals, and type metal. A use of increasing importance is as radiation shields in production of nuclear energy. More than 40% of the lead used in the United States has been secondary metal; the recovery rate is high.

The most important lead minerals are the sulfide galena (PbS), which almost invariably contains silver and is the dominate lead ore, the carbonate cerussite (PbCO3) and the sulfate anglesite (PbSO4). Lead often occurs with zinc, and lead ores also contain other metals.

United States is the leading producer with Australia, Canada, and Mexico following. Until the Second World War, America was a net exporter of lead, but more recently American mines have at times delivered only about 30% of the national consumption. The balance has been supplied by secondary lead and imports.

Mine output in North America has long been dominated by the lead belt of the Upper Mississippi region. Large deposits of low-grade galena ore are mined in large-scale operations. The Missouri mines, which contain pure lead ore not associated with other metals, have been worked since the seventeenth century. In 1990 this accounted for about 70% of the North American mine production.

Precious metals Precious metals, including gold, silver, and the platinum group of metals, have important industrial uses. In addition, gold and silver have long been monetary standards. Both gold and silver have been used for money since prehistoric times. For geological reasons gold was originally more common than silver.

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Native gold could be obtained with primitive methods (panning, mechanical working of gold veins) while silver required more advanced mining and smelting methods. The largest silver mine of in the ancient realm was south of Athens, employed 20,000 slaves, and played a central role in the economy of Athens.

Gold has two distinct uses: as an international monetary reserve and as commercial metal. The reserve is kept by central banks in ingots of the metal (bullion), although some countries still make gold coins. Some 75% of the commercial gold is used in jewelry, the rest in dentistry and as a conductor in the electronics industry. Pure gold is too soft for jewelry and is alloyed with copper and other metals. The fineness of gold is measured in karat, 24 karat being pure gold. Gold of 14 karat contains 58% gold and nobler metals (platinum), 25–32% copper, and some silver, zinc, or nickel.

Most gold is obtained as native gold, which is not pure but almost invariably contains some silver. In the past, gold was primarily produced by placer mining but for many decades the chief source has been quartz veins or sulfide ores, often obtained in deep shaft mines. Much gold is obtained as a by-product or co-product in mines operated for other metals.

The search for gold was a major driving force during the era of great discoveries. Until the middle of the nineteenth century, production increased steadily but slowly. More than 80% of the gold was produced in South and Central America. The California gold rush in 1849 and the rush to Victoria, Australia, in the 1850s brought about a great rise in output. A large drop during the war was followed by recovery. In the mid-1960s production was about 45 million ounces, and in 1970 a record of 47 million ounces was reached.

The two separate uses of gold became two separate markets. Sale of gold from the central banks to the free market was no longer allowed. The fluctuating gold price in the free market, set at auctions primarily in London and Zurich, reached the record level of $197 an ounce.

South Africa has historically accounted for most of the world’s output, almost all from deep shaft mines. Many of their mines produce uranium as a by-product. The world’s largest gold deposit is the Witwatersrand, or the Rand, in Transvaal, where gold was found in 1886. The deepest mine, 2,700 m below the surface, has serious temperature and rock pressure problems.

Silver is used in jewelry and fine house furnishings, in photography, and for metal coating. Use of silver in coins has declined in many countries, but it is still used in commemorative coins and medals. Among modern uses are electric and electronic apparatus. For coins and jewelry, silver is alloyed with copper and nickel to become harder. In earlier times, silver was a standard of value along with gold.

Most of the silver is derived from the Western Hemisphere, with United States, Canada, and Mexico each producing about 15% of the world’s supply, followed by Peru and Bolivia. Most of the silver produced is a by-product of mines producing base metals and gold.


Review questions 1. Cite several examples of early human’s use of minerals.

2. What important event took place in 1974 that revolutionized our thoughts about ore generation?

3. List the major iron-bearing minerals that form most iron ores.

4. Where are most of the world’s manganese deposits?

5. Which country supplies most of the world’s nickel?

6. What is gold used for?

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Unit 12 Light Metals and Nonmetallic Minerals

Topics Light metals Nonmetallic minerals

Introduction To conclude, we examine the mineral resources of light metals and nonmetallics. These materials are the most abundantly mined and consumed of all mined materials and are essential to many facets of modern society.


• outline the use and source of the most common light metals;

• differentiate the various types of stone and summarize their uses; and

• locate the major sources of nonmetallics such as asbestos, clay, marble, china clay, and bentonite.



3. Read pages 331–399 in Resources of the Earth.

Study notes Key terms bauxite bentonite brucite cryolite dolomite ilmenite kaolin light metal magnesite dimension stone


Light metals Metals show a tremendous spread in densities, between 0.534 for lithium and 22.5 for osmium. The distinction between light and heavy metals is drawn at a density 4.0. Lightness is a desired quality in construction materials, not only for airplanes and space craft, but also for land and sea vehicles, containers, and packages.

Aluminium occurs abundantly in all ordinary rocks, except limestone and sandstone. Only oxygen and silicon among the elements are more common than aluminium in the Earth’s crust. Aluminium was first isolated in 1825. The complex isolation method was improved by the French chemist H.S.C. Deville, who showed the metal, worth more than gold, at the Paris Exhibition 1854. Originally the mineral cryolite (Na3AlF6) was used as a source for Al. The only known deposit of cryolite is found in Greenland. Mining was discontinued in the early 1960s when the mines had been emptied. This strategic material can now be made synthetically, but still in the early 1970s natural cryolite was sold from stocks.

The electrolytic method of isolation, by which aluminium is now produced from alumina, was discovered in 1886. Pure alumina is made from bauxite, which is now the raw material for aluminium. Bauxite, named for the French village Les Baux where the ore was found in 1821, contains 45–65% aluminium oxide or alumina (A12O3). The clay-like ore contains aluminium hydroxide, but also impurities in the form of silica, clay minerals, and iron oxides. It was formed by leaching under a humid tropical climate. Deposits now found in temperate regions such as United States, Canada, and northern Europe, were formed when those areas had a warmer and wetter climate. Because aluminium components have low solubility they become concentrated under warmer temperature and precipitation as the silica is leached out. Iron oxide as well as aluminium oxide end up in the concentrated residual. The lower the content of iron oxide, the higher the quality of the bauxite deposit. Bauxite is beneficiated at the mine where it is crushed, washed, and dried.

Other large bauxite deposits have been developed in Arnhem Land in the Northern Territory of Australia and in the Darling Range, east of Perth, Australia.

Magnesium is the lightest of the major metals. Magnesium has the density 1.74 and is strong and machinable. It can be cast, rolled, drawn, spun, forged, blanked, and coined. Magnesium in alloys makes them corrosion resistant. Magnesium burns with a dazzling white light and is used in flares, fireworks, and flash bulbs. Since magnesium is an alloy metal of aluminium and is used in bombs and other munition, the American production reached a pronounced peak during the Second World War. The Korean War and the Vietnam War also led to increased production.

Magnesium can be extracted from continental saline brines, from sea water, and from minerals containing the metal, primarily brucite, dolomite, and magnesite. Sea water is by far the most important source.

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Titanium has been known as a common element for more than 150 years. It occurs in almost all rocks and in two important ores, rutile or titanium dioxide (TiO2), and ilmenite (FeTiO3). Ilmenite often occurs in monazite sand.

Although titanium is one of the ten most common elements in the earth’s solid crust, the pure metal is still expensive. Production per ton requires more than twice as much energy as aluminium. The metal, which is obtained mainly from rutile, is only used where lightness, strength, or corrosion resistance justify the cost. Over 80% of the titanium metal is used in bracing constructions of airplanes, in turbo jet engines, and in rockets. Production has followed a steeply rising curve since 1948. Titanium and its alloys have tensile strengths comparable with those of many steel alloys and their corrosion resistance at normal temperature corresponds to that of platina. Pipes in desalting plants is a new use of titanium metal. Its corrosion resistance to salt water is unique.

In Australia ilmenite is obtained as beach sand in southern West Australia and rutile along the coast between Sydney and Brisbane. The sand mineral production also occurs in the United States, Malaysia, India, and Sri Lanka. American sand quarries are primarily located in the southeastern states including New Jersey. Allard Lake, Québec, is a layered intrusion and the largest known titanium ore body. In Norway and Finland ilmenite-magnetite is produced in large mines.

Nonmetallic minerals Nonmetallic minerals other than fuels and fertilizers cover a wide range. Many are used in the construction, ceramics, and chemical industries. Nonmetallic minerals are abundant and cheap, but since total quantities used are very large the combined value of cement, clay, gravel, lime, sand, slate, stone, gypsum, salt, and sulfur is larger than the value of iron ore, bauxite, and several other major metal ores combined.

Most nonmetallic minerals are ubiquitous; if not literally found everywhere they are at least readily available in most regions of the world. Several nonmetallic minerals are important in our civilization although used in small quantities: asbestos, graphite, mica, quartz crystals, diamonds, and gems. The electronic industry is a heavy user of quartz crystals.

Stone is still widely used in all parts of the world, but as a house building material it was relatively more important in the past, especially in densely populated regions with restricted forest areas. The labour-intensive stonecutting industry cannot today compete with manufactured stones, such as bricks and cement blocks, and with reinforced concrete. Only a few percent of the stone used is cut into dimension or building stone; the rest is sold as crushed stone.

The more important stones utilized by society are basalt, granite, limestone, marble, sandstone, and slate. Almost all dimension stone and some 75% of the crushed stone are used for construction. Another 15% of the crushed stone is turned into cement, which is also used in construction. Limestone and dolomite account for about 80% of the total tonnage.


Most dimension stones are used relatively near the quarry but some building stones, such as Manitoba’s Tyndal stone, because of exceptional beauty or special properties, are shipped long distances. There are several times as many crushed-stone plants as quarries producing dimension stone. The region’s local geology largely decides which type of stone is used at given place. Old settlements in regions with houses predominantly of stone clearly reflect the local geology.

Basalt and other dark igneous rocks, known commercially as traprock, are used almost exclusively as crushed stone. Granite, an igneous rock that varies much in color and crystal structure, takes a high polish and is used in monuments and tombstones. Only 2% of the granite in North America is cut into dimension stone but this represents about 30% of the total value. Like traprock, crushed granite is used as concrete aggregate, roadstone, and railroad ballast. Granite as a paving stone in towns can no longer compete with asphalt and other materials. In Europe, Sweden, Finland, Norway, and Scotland are known for their dimension stone.

Limestone is second only to granite as a dimension stone in North America. The Bedford limestone of the Bloomington area in Indiana accounts for over half the tonnage in North America. Most of the limestone quarried tonnage is used as flux in steel mills and as the raw material of cement and lime. The world’s largest limestone crushing plant is located in southeastern Michigan. It ships some 15 million tons a year.

Marble or metamorphic limestone takes a high polish and is used for tomb-stones, monuments, statuary, and buildings. Major producing centers are in the United States, Italy, and Spain. Slate has well-defined planes of cleavage and is excellent for roofing, for fiagstones, and steps. Quarries in northern Wales have been in production since the fifthteenth century. Sandstone like slate and limestone is used for flagstones and steps.

Asbestos is a fibrous amphibole, used for making fireproof articles. A few major uses dominate. Asbestos cement building materials and asbestos cement pipe make up 70% of world production. Floor tiles, brake linings, gaskets, and clutch facings are other important uses.

Canada and the countries of the former Soviet Union dominate world production. Interestingly, Canada produces over 40%, but asbestos accounts for only 4% of the value of the Canadian mineral production. The vast deposits of asbestos occur in southeastern Québec. For many years these deposits were exploited in open pits, but most operations are now underground. Other asbestos deposits have been developed in northwestern Québec, in Newfoundland, Ontario, and British Columbia.

Clay is widespread and used for many purposes. It consists essentially of hydrated aluminium silicates. Common clay is produced in tens of millions of tons. It is almost exclusively used by the producer in the fabrication of a products such as common brick, tile, sewer pipe, drain tile, and cement. In the tropics and in dry areas in the middle latitudes, adobe in large quantities is mined and processed almost entirely by hand.

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Sand and gravel rank first in tonnage among the minerals, surpassing oil and coal. Both result from natural disintegration of rocks, and primarily consist of the harder minerals, such as quartz. About 90% of all sand and gravel is utilized for construction and paving. Sea shores and sea bottoms, lake beaches and lake bottoms, and river terraces and river bottoms are the major sources of sand and gravel except in formerly glaciated areas where eskers and glacial outflows provide much material. In areas with no natural sand and gravel, rocks are crushed to provide substitutes.

The sand and gravel industry is highly decentralized, each small unit operating within a restricted area. About 9,000 commercial units account for 80% of North American’s output.

Glass was made by the ancient Egyptians and Romans. As a handicraft, glassmaking was well developed centuries ago among the Venetians, Dutch, and French. Mechanized glassmaking is new, however, developed since about 1900. Almost all window panes and glass containers are now machine-made in contrast to the situation a century ago in even the flat glass was handblown.

The raw materials for glass are sand, soda ash, lime, and a large number of other materials in smaller quantities such as metal oxides to give color to the glass (cobalt, blue; gold, red; copper, red or green). Sand, which accounts for the largest quantities, should have a low content of iron and aluminium oxide and a high silica content. Sand grains should be uniformly small and angular, which simplifies the fusion.

Porcelain. Kaolin, named for Kaoling, a Chinese mountain that yielded the first kaolin sent to Europe, is produced in Cornwall and Devon in southwest England and exported to chinaware works throughout the world. Kaolin is also used for paper filling. The terms china and china clay indicate that the product originally was imported from China; it was an important item in the early Canton trade.

Porcelain was first produced industrially by the Germans in the eighteenth century. Dresden and Berlin became well-known for their china. Austria, Czechoslovakia, and Denmark also have famous china factories based on nearby raw material. In France, the western flank of the Massif Central has extensive kaolin deposits and is known for its porcelain. In Britain the North Staffordshire coalfield is known as the Potteries. Here six pottery towns early in this century were merged to Stoke-on-Trent, which is now the center of the industry. Stoke gets its clay from Cornwall through the Trent and Mersey Canal, opened in 1770. Wedgwood china from this area is well-known.

Bentonite is used as a binder in forming strong pellets of iron ore. This demand is worldwide, and deposits in North America are the principal source. Swelling bentonite, used for this purpose, is produced in Wyoming, Montana, the Dakotas, and Saskatchewan. It is also used for rotary-drilling mud. Bentonite and barite are important ingredients of the mud used in petroleum drilling. It is not unusual that the mud for a single deep well costs more than a million dollars. In addition to cooling the drillbit, it helps keeping the pressure in the hole and thereby prevents petroleum under pressure from blowing out.


Review questions 1. Where are the largest deposits of bauxite found?

2. How is most of the world’s titanium ore mined?

3. What is most quarried limestone used for?

4. Where does bentonite come from and for what is it used?

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Sample Answers Appendix

Unit 1 Energy Fundamentals 1. energy

2. a. potential b. sound c. chemical d. heat/thermal e. kinetic

3. A ton of oil has about 38 x 109 J whereas a ton of coal has 2.8 x 1010 J.

4. No, power involves a time component.

6. perhaps nuclear => radiant => thermal => gravitational => electrical => mechanical

Unit 2 Energy and Mineral Resources 1. the Sun

2. 0.01%; < 1%.

4. 1 trillion bbl versus 60 billion bbl

5. 1.5 billion bbl versus 500 million bbl; 7.4 billion bbl versus 1.5 billion bbl

Unit 3 Fundamentals of Energy and Mineral “Crises” 1. No; discussion should revolve around the fact that everything we do extracts

a price and everything is connected to everything else.

2. Many possible things could be listed: environment in general, land, water, air, etc.

3. Many possible depending upon your past experiences: oil exploration in national parks; commercial fishing in open sea, etc.

4. The amount of time required for a quantity that is growing at a fixed rate per time to double in size; T2 = 70/p


Unit 4 Oil and Natural Gas 1. The 5 Es of petroleum geology are: exploration, evaluation, extraction,

explication, extrapolation.

2. Declining whale oil stocks, price of oil, type of oil (the text reading also emphasizes the persistence of the managers)

3. He is/was the Father of Canadian petroleum geology; expert in petroleum geochemistry.

4. Success (at least from the standpoint of supplying the demand) without it; geology could not explain the occurrences.

5. NSOs are compounds containing nitrogen, sulfur, and/or oxygen; they occur in petroleum and can give distinctive properties to the petroleum.

Unit 5 Drilling Technology 1. Many possible answers but mainly: prospect generation, interpretation of

data, safety, background for other activities.

2. Invention/discovery of the rotary drilling system; also may include discussions on mud systems.

3. Land: access often difficult; offshore: staying at the site is difficult, in addition water depth, waves, wind, icebergs present problems.

4. If the sedimentation is so rapid that the fine-grained material cannot release the water that it would normally do in a compacting situation, then high pressures can be created.

5. Many possible explanations here, but the big ones are: control of subsurface pressure, remove cuttings, cool and lubricate the bit and drillstem, and aid in formation evaluation.

6. Drilling supervisor, drilling engineer, tool pusher, driller, roughnecks/derrickman, roustabouts.

Unit 6 The Petroleum Rock Source 1. Chemically complex, nondescript, buff to yellow-orange to brown-black,

amorphous

2. KI: algae; KII: bacteria; KIII: higher plants; KIV: oxidized organic matter

3. 60–175C (your reading says about 100C)

4. Yes; your discussion should site old but marginally mature source rocks versus young but high temperature source rocks.

5. Because the geothermal gradient usually varies (somewhat) with depth depending rock type, thermal conductivity, fluid content, etc.

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Unit 7 Petroleum Migration 1. Primary migration is movement out of the source rock; secondary migration

is movement within a porous and permeable conduit.

2. Long-range because the Williston Basin consist largely of rocks that were deposited in an area of relatively little tectonic deformation

3. Nothing! There is no consistently valid relationship; shales for example have very large porosities but very poor permeabilites; fractured reservoir rocks on the other hand can have very low porosities, but very good permeabilities.

4. pores that are interconnected

5. because carbonate rocks are very susceptible to postdepositional alteration

6. a volume reduction of about 13% and the development of porosity

Unit 9 Coal and Oil Shales 1. Several possible; most acceptable: readily combustible rock containing

>50% wt (>70% vol) carbonaceous material.

2. Any rock that is capable of yielding oil upon heading. You might also mention the various economic constraints (i.e., the amount of oil the rock yields must be greater than the amount of equivalent energy necessary to extract the oil).

3. They are the same; there is nothing different (other than amount) between source rock organic matter and coal organic matter.

4. boghead coal

5. Evolution ultimately dictated when (geologically) coals could form.

6. No, lack of moisture for plants to grow; highly oxidizing

7. Yes, cool temperatures greatly reduce the amount of decomposition.

Unit 10 Canada’s Energy Saviour: The Tar Sands and Heavy Oil 1. Athabasca bitumen is much more dense than most other oils and is more

dense than water.

2. Athabasca, Cold Lake, Wabasca, Peace River

3. Lower Cretaceous

4. very fine to fine-grained, moderately sorted, 30-35% porosity

5. A substance is “water wet” if water tends to adhere to it rather than being repelled.

6. by northward flowing rivers


Unit 11 Economic Geology 1. many possible: cutting tools, clay, precious stones

2. Geologists examined an active submarine rift for the first time.

3. magnetite, hematite, limonite, siderite

4. deep ocean

5. Canada

6. monetary reserve and commercial metal

Unit 12 Light Metals and Nonmetallic Minerals 1. tropical climates

2. mining beach sands

3. cement, lime, crushed stone

4. North America; binder and mud

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Sample Final Examination

NOTE: This is a short answer format examination. I do not expect full sentences or long answers. You may have up to 2 hours to complete the exam. The numbers in parentheses are the values of each question.

1. (6) List and characterize (in terms of source material) the different types of kerogen.

2. (3) What is an alloy metal? List two such alloy metals.

3. (2) Classify each of the following in terms of type of energy: a. light b. motion of a pendulum c. an earthquake d. hot springs

4. (6) Discuss the historical use of energy and energy sources from our ancient ancestors up to a typical modern day Canadian. Be sure to provide approximate quantitative levels of energy use in addition to sources.

5. (1) For approximately what proportion of human history have fossil fuels provided the major energy source?

6. (5) Explain and discuss how climate plays a role in coal and peat formation.

7. (4) Discuss the concept of the tragedy of the commons and give a modern example.

8. (4) (i) Differentiate between the terms: resource and resource base. (ii) How large is Canada’s conventional oil resource base? (iii) How large is Canada’s conventional oil resource?

9. (2) What is the difference(s) between coal type and coal rank?

10. (2) What are the classes of oils that have been degraded by near-surface bacterial action and/or water flushing? Be specific!

11. (2) What are the “usual” subsurface temperatures of the oil window (i.e., upper and lower limits)? Be specific!

12. (3) Define and differentiate among the following terms: (i) work (ii) power (iii) energy

13. (6) Summarize the type and character of the petroleum products that are generated from a maturing source rock.


14. (2) What are the two most important physical properties that a good reservoir must have?

15. (3) Name two important iron-bearing minerals that form iron ores and give the chemical formulae of each.

16. (4) For each of the following economic “mineral” components, list the major ore mineral (name) and the chemical formula for that mineral: Chromium Molybdenum Tin Titanium

17. (4) Provide a labelled sketch of the earth system energy flux. Be sure to give the approximate proportions of each of the major flux components.

18. (1) Based on past drilling in North America, about what proportion of subsurface traps contain petroleum?

19. (1) What is the importance of giant petroleum fields?

20. (2) (i) Which lithology is the dominant caprock in most of the world’s reservoirs?

(ii) Which lithology is the most effective caprock?

21. (2) How is “petroleum enrichment” defined in the context of a large sedimentary basin?

22. (1) Why was 1974 a landmark year for the study of economic geology and ore formation?

23. (2) Define coal.

24. (4) List the major depositional environments for coal.

25. (2) Sketch (be sure to clearly label) or describe the relationship of water depth with different facies of iron minerals forming in a marine setting today.

26. (2) What rank are the following coals: (i) Rv = 0.3 (ii) Rv = 1.0 (iii) C = 70% (iv) C = 94%

27. (4) List Canada’s major oil sands deposits in order of decreasing size.

28. (2) What is the mineralogical composition of typical Athabasca oil sands?

29. (6) What is the most likely origin of the vast amount of oil in Canada’s tar sands deposits?

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30. (5) Provide one specific basin type to answer each of the following: (i) usually has the thickest sedimentary sequence; (ii) usually is composed of a mixture of clastic and carbonate rocks; (iii) the source rocks are often overmature; (iv) has the greatest percentage of known giant fields; (v) has the lowest percentage of known giant fields; (vi) has the greatest percentage of world petroleum reserves; (vii) has the lowest percentage of world petroleum reserves; (viii) is dominated by stratigraphic traps; (ix) has the highest enrichment factor; and (x) has the lowest enrichment factor.

31. (2) Which base metal is the world’s most widely used and which country has the world’s greatest reserves of this base metal?

32. (2) We refer to oil sands as being water wet. What does this mean?

33. (3) (i) Which are usually larger: structural traps or stratigraphic traps?

(ii) Which of these two trap types have historically been most productive?

(iii) Which of these two trap types have been “easier” to find?


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Energy and Mineral Resources GEOL...

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