Darling, T. - Well Logging and Formation Evaluation (2005) PDF

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WELL LOGGING AND FORMATION EVALUATION WELL LOGGING AND FORMATION EVALUATION Toby Darling AMSTERDAM • BOSTON • HEIDELBERG • LONDON NEW YORK • OXFORD • PARIS • SAN DIEGO SAN FRANCISCO • SINGAPORE • SYDNEY • TOKYO Gulf Professional Publishing is an imprint of Elsevier Science Gulf Professional Publishi...

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WELL LOGGING AND FORMATION EVALUATION

WELL LOGGING AND FORMATION EVALUATION Toby Darling

AMSTERDAM • BOSTON • HEIDELBERG • LONDON NEW YORK • OXFORD • PARIS • SAN DIEGO SAN FRANCISCO • SINGAPORE • SYDNEY • TOKYO Gulf Professional Publishing is an imprint of Elsevier Science

Gulf Professional Publishing is an imprint of Elsevier 30 Corporate Drive, Suite 400, Burlington, MA 01803, USA Linacre House, Jordan Hill, Oxford OX2 8DP, UK Copyright © 2005, Elsevier Inc. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without the prior written permission of the publisher. Permissions may be sought directly from Elsevier’s Science & Technology Rights Department in Oxford, UK: phone: (+44) 1865 843830, fax: (+44) 1865 853333, e-mail: [email protected]. You may also complete your request on-line via the Elsevier homepage (http://elsevier.com), by selecting “Customer Support” and then “Obtaining Permissions.” Recognizing the importance of preserving what has been written, Elsevier prints its books on acid-free paper whenever possible. Library of Congress Cataloging-in-Publication Data Application submitted. British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library. ISBN: 0-7506-7883-6 For information on all Gulf Professional Publishing publications visit our Web site at www.books.elsevier.com 05 06 07 08 09 10

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CONTENTS

Introduction ix 1

Basics 1 1.1 Terminology 1 1.2 Basic Log Types 3 1.3 Logging Contracts 9 1.4 Preparing a Logging Programme 11 1.5 Operational Decisions 14 1.6 Coring 16 1.7 Wellsite Mud Logging 21 1.8 Testing/Production Issues 24

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Quicklook Log Interpretation 29 2.1 Basic Quality Control 29 2.2 Identifying the Reservoir 30 2.3 Identifying the Fluid Type and Contacts 32 2.4 Calculating the Porosity 34 2.5 Calculating Hydrocarbon Saturation 37 2.6 Presenting the Results 40 2.7 Pressure/Sampling 42 2.8 Permeability Determination 45

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Full Interpretation 49 3.1 Net Sand Definition 49 3.2 Porosity Calculation 51 3.3 Archie Saturation 53 3.4 Permeability 54

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Saturation/Height Analysis 59 4.1 Core Capillary Pressure Analysis 60 4.2 Log-Derived Functions 64

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Contents

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Advanced Log Interpretation Techniques 67 5.1 Shaly Sand Analysis 67 5.2 Carbonates 73 5.3 Multi-Mineral/Statistical Models 74 5.4 NMR Logging 76 5.5 Fuzzy Logic 85 5.6 Thin Beds 87 5.7 Thermal Decay Neutron Interpretation 93 5.8 Error Analyses 96 5.9 Borehole Corrections 101

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Integration with Seismic 103 6.1 Synthetic Seismograms 103 6.2 Fluid Replacement Modelling 108 6.3 Acoustic/Elastic Impedance Modelling

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Rock Mechanics Issues 115

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Value Of Information 119

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Equity Determinations 125 9.1 Basis for Equity Determination 126 9.2 Procedures/Timing for Equity Determination 9.3 The Role of the Petrophysicist 129

10 Production Geology Issues 137 10.1 Understanding Geological Maps 140 10.2 Basic Geological Concepts 147 11

Reservoir Engineering Issues 155 11.1 Behavior of Gases 155 11.2 Behavior of Oil/Wet Gas Reservoirs 11.3 Material Balance 162 11.4 Darcy’s Law 163 11.5 Well Testing 166

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12 Homing-in Techniques 171 12.1 Magnetostatic Homing-in 171 12.2 Electromagnetic Homing-in 185 13 Well Deviation, Surveying, and Geosteering 193 13.1 Well Deviation 193 13.2 Surveying 195

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Contents

13.3 13.4 13.5

Geosteering 197 Horizontal Wells Drilled above a Contact 203 Estimating the Productivity Index for Long Horizontal Wells 205

Appendix 1

Test Well 1 Data Sheet

Appendix 2

Additional Data for Full Evaluation 215

Appendix 3

Solutions to Exercises

Appendix 4

Additional Mathematics Theory 251

Appendix 5

Abbreviations and Acronyms

Appendix 6

Useful Conversion Units and Constants

Appendix 7

Contractor Tool Mnemonics

Bibliography 309 About the Author 313 Acknowledgments 314 Index

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INTRODUCTION

The purpose of this book is to provide a series of techniques which will be of real practical value to petrophysicists in their day-to-day jobs. These are based on my experience from many years working in oil companies. To this end I have concentrated wherever possible on providing one recommended technique, rather than offer the reader a choice of different options. The primary functions of a petrophysicist are to ensure that the right operational decisions are made during the course of drilling and testing a well—from data gathering, completion and testing—and thereafter to provide the necessary parameters to enable an accurate static and dynamic model of the reservoir to be constructed. Lying somewhere between Operations, Production Geology, Seismology, Production Technology and Reservoir Engineering, the petrophysicist has a key role in ensuring the success of a well, and the characterization of a reservoir. The target audience for this book are operational petrophysicists in their first few years within the discipline. It is expected that they have some knowledge of petroleum engineering and basic petrophysics, but lack experience in operational petrophysics and advanced logging techniques. The book also may be useful for those in sister disciplines (particularly production geology and reservoir engineering) who are using the interpretations supplied by petrophysicists.

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C H A P T E R

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BASICS

1.1 TERMINOLOGY Like most professions, petroleum engineering is beset with jargon. Therefore, it will make things simpler if I first go through some of the basic terms that will be used throughout this book. Petroleum engineering is principally concerned with building static and dynamic models of oil and gas reservoirs. Static models are concerned with characterizing and quantifying the structure prior to any production from the field. Hence, key parameters that the models aim to determine are:

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STOIIP = stock tank oil initially in place; usually measured in stock tank barrels (stb) GIIP = gas initially in place; usually measured in billion standard cubic feet (Bcf) GBV = gross bulk volume; the total rock volume of the reservoir containing hydrocarbon NPV = net pore volume; the porespace of the reservoir HCPV = hydrocarbon pore volume; the porespace actually containing hydrocarbon f = porosity; the proportion of the formation that contains fluids k = permeability; usually expressed in millidarcies (md) Sw = water saturation; the proportion of the porosity that contains water Sh = hydrocarbon saturation; the proportion of the porosity that contains hydrocarbon FWL = free water level; the depth at which the capillary pressure in the reservoir is zero; effectively the depth below which no producible hydrocarbons will be found

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Well Logging and Formation Evaluation

HWC = hydrocarbon/water contact; the depth below which the formation is water bearing as encountered in a particular well. Likewise, OWC for oil and GWC for gas GOC = gas oil contact; the depth below which any gas in the reservoir will be dissolved in the oil Gross thickness = the total thickness of the formation as encountered in a particular well Net thickness = the part of the gross thickness that contains porous rock subject to given cutoff criteria Pay thickness = the part of the net thickness that is considered to be capable of producing hydrocarbons in a particular well

Because of inherent uncertainties in all the parameters used to determine STOIIP or GIIP, geologists will usually develop probabilistic models, in which all the parameters are allowed to vary according to distribution functions between low, expected, and high values. The resulting static models may then be analyzed statistically to generate the following values, which are used for subsequent economic analyses:

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P50 STOIIP: the value of the STOIIP for which there is a 50% chance that the true value lies either above or below the value P15 STOIIP: the value of the STOIIP for which there is only a 15% chance that the true value exceeds the value. Often called the high case. P85 STOIIP: the value of the STOIIP for which there is an 85% chance that the true value exceeds the value. Often called the low case. Expected STOIIP: the value of the STOIIP derived by taking the integral of the probability density function for the STOIIP times the STOIIP. For a symmetric distribution, this will equal the P50 value.

Similar terminology applies to GIIP. In order to predict the hydrocarbons that may be actually produced from a field (the reserves), it is necessary to construct a dynamic model of the field. This will generate production profiles for individual wells, subject to various production scenarios. Additional terminology that comes into play includes:

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Reserves = the part of the STOIIP or GIIP that may be actually produced for a given development scenario. Oil companies have their own rules for how reserves are categorized depending on the extent to which they are regarded as proven and accessible through wells. Terms fre-

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quently used are proven reserves, developed reserves, scope for recovery reserves, probable reserves, and possible reserves. Remaining reserves = that part of the reserves that has not yet been produced Cumulative production = that part of the reserves that has already been produced UR = ultimate recovery; the total volume of reserves that will be produced prior to abandonment of the field NPV = net present value; the future economic value of the field, taking into account all future present value costs and revenues RF = recovery factor; the reserves as a proportion of the STOIIP (or GIIP) Bo = oil volume factor; the factor used to convert reservoir volumes of oil to surface (stock tank) conditions. Likewise Bg for gas.

In order to produce the hydrocarbons, wells are needed and a development strategy needs to be constructed. This strategy will typically be presented in a document called the field development plan (FDP), which contains a summary of current knowledge about the field and the plans for future development. Once an FDP has been approved, the drilling campaign will consist of well proposals, in which the costs, well trajectory, geological prognosis, and data-gathering requirements are specified. The petrophysicist plays a part in the preparation of the well proposal in specifying which logs need to be acquired in the various hole sections. 1.2 BASIC LOG TYPES Below is a list of the main types of logs that may be run, and why they are run. 1.2.1 Logging While Drilling (LWD)

Traditionally, petrophysicists were concerned only with wireline logging, that is, the data acquired by running tools on a cable from a winch after the hole had been drilled. However, advances in drilling/logging technology have allowed the acquisition of log data via tools placed in the actual drilling assembly. These tools may transmit data to the surface on a real-time basis or store the data in a downhole memory from which it may be downloaded when the assembly is brought back to the surface.

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Well Logging and Formation Evaluation

LWD tools present a complication for drilling, as well as additional expense. However, their use may be justified when:

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Real-time information is required for operational reasons, such as steering a well (e.g., a horizontal trajectory) in a particular formation or picking of formation tops, coring points, and/or casing setting depths Acquiring data prior to the hole washing out or invasion occurring Safeguarding information if there is a risk of losing the hole The trajectory is such as to make wireline acquisition difficult (e.g., in horizontal wells)

LWD data may be stored downhole in the tools memory and retrieved when the tool is brought to the surface and/or transmitted as pulses in the mud column in real time while drilling. In a typical operation, both modes will be used, with the memory data superseding the pulsed data once the tool is retrieved. However, factors that might limit the ability to fully use both sets of data are:

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Drilling mode: Data may be pulsed only if the drillstring is having mud pumped through it. Battery life: Depending on the tools in the string, tools may work in memory mode only between 40 and 90 hours. Memory size: Most LWD tools have a memory size limited to a few megabytes. Once the memory is full, the data will start to be overwritten. Depending on how many parameters are being recorded, the memory may become full within 20–120 hours. Tool failure: It is not uncommon for a fault to develop in the tool such that the pulse data and/or memory data are not transmissible/ recordable.

Some of the data recorded may be usable only if the toolstring is rotating while drilling, which may not always be the case if a steerable mud motor is being used. In these situations, the petrophysicist may need to request drilling to reacquire data over particular intervals while in reaming/rotating mode. This may also be required if the rate of penetration (ROP) has been so high as to affect the accuracy of statistically based tools (e.g., density/neutron) or the sampling interval for tools working on a fixed time sampling increment. Another important consideration with LWD tools is how close to the bit they may be placed in the drilling string. While the petrophysicist will obviously want the tools as close to the bit as possible, there may be

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limitations placed by drilling, whose ability to steer the well and achieve a high ROP is influenced by the placement of the LWD toolstring. LWD data that may typically be acquired include the following:

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GR: natural gamma ray emission from the formation Density: formation density as measured by gamma ray Compton scattering via a radioactive source and gamma ray detectors. This may also include a photoelectric effect (Pe) measurement. Neutron porosity: formation porosity derived from the hydrogen index (HI) as measured by the gamma rays emitted when injected thermal or epithermal neutrons from a source in the string are captured in the formation Sonic: the transit time of compressional sound waves in the formation Resistivity: the formation resistivity for multiple depths of investigation as measured by an induction-type wave resistivity tool

Some contractors offer LWD-GR, -density, and -neutron as separate up/down or left/right curves, separating the contributions from different quadrants in the borehole. These data may be extremely useful in steering horizontal wells, where it is important to determine the proximity of neighboring formation boundaries before they are actually penetrated. Resistivity data may also be processed to produce a borehole resistivity image, useful for establishing the stratigraphic or sedimentary dip and/or presence of fractures/vugs. Other types of tool that are currently in development for LWD mode include nuclear magnetic resonance (NMR), formation pressure, and shear sonic. 1.2.2 Wireline Openhole Logging

Once a section of hole has been completed, the bit is pulled out of the hole and there is an opportunity to acquire further openhole logs either via wireline or on the drillstring before the hole is either cased or abandoned. Wireline versions of the LWD tools described above are available, and the following additional tools may be run:

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Gamma ray: This tool measures the strength of the natural radioactivity present in the formation. It is particularly useful in distinguishing sands from shales in siliciclastic environments. Natural gamma ray spectroscopy: This tool works on the same principal as the gamma ray, although it separates the gamma ray counts into

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Well Logging and Formation Evaluation

three energy windows to determine the relative contributions arising from (1) uranium, (2) potassium, and (3) thorium in the formation. As described later in the book, these data may be used to determine the relative proportions of certain minerals in the formation. Spontaneous potential (SP): This tool measures the potential difference naturally occurring when mud filtrate of a certain salinity invades the formation containing water of a different salinity. It may be used to estimate the extent of invasion and in some cases the formation water salinity. Caliper: This tool measures the geometry of the hole using either two or four arms. It returns the diameter seen by the tool over either the major or both the major and minor axes. Density: The wireline version of this tool will typically have a much stronger source than its LWD counterpart and also include a Pe curve, useful in complex lithology evaluation. Neutron porosity: The “standard” neutron most commonly run is a thermal neutron device. However, newer-generation devices often use epithermal neutrons (having the advantage of less salinity dependence) and rely on minitron-type neutron generators rather than chemical sources. Full-waveform sonic: In addition to the basic compressional velocity (Vp) of the formation, advanced tools may measure the shear velocity, Stonely velocity, and various other sound modes in the borehole, borehole/formation interface, and formation. Resistivity: These tools fall into two main categories: laterolog and induction type. Laterolog tools use low-frequency currents (hence requiring water-based mud [WBM]) to measure the potential caused by a current source over an array of detectors. Induction-type tools use primary coils to induce eddy currents in the formation and then a secondary array of coils to measure the magnetic fields caused by these currents. Since they operate at high frequencies, they can be used in oil-based mud (OBM) systems. Tools are designed to see a range of depths of investigation into the formation. The shallower readings have a better vertical resolution than the deep readings. Microresistivity: These tools are designed to measure the formation resistivity in the invaded zone close to the borehole wall. They operate using low-frequency current, so are not suitable for OBM. They are used to estimate the invaded-zone saturation and to pick up bedding features too small to be resolved by the deeper reading tools. Imaging tools: These work either on an acoustic or a resistivity principle and are designed to provide an image of the borehole wall that may

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be used for establishing the stratigraphic or sedimentary dip and/or presence of fractures/vugs. Formation pressure/sampling: Unlike the above tools, which all “log” an interval of the formation, formation-testing tools are designed to measure the formation pressure and/or acquire formation samples at a discrete point in the formation. When in probe mode, ...