Geological Core Analysis: Application to Reservoir Characterization (SpringerBriefs in Petroleum Geoscience & Engineering) 3319780263, 9783319780269

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SPRINGER BRIEFS IN PETROLEUM GEOSCIENCE & ENGINEERING

Vahid Tavakoli

Geological Core Analysis Application to Reservoir Characterization

SpringerBriefs in Petroleum Geoscience & Engineering Series editors Dorrik Stow, Heriot-Watt University, Edinburgh, UK Mark Bentley, AGR TRACS International Ltd, Aberdeen, UK Jebraeel Gholinezhad, University of Portsmouth, Portsmouth, UK Lateef Akanji, King’s College, University of Aberdeen, Aberdeen, UK Khalik Mohamad Sabil, Heriot-Watt University, Putrajaya, Malaysia Susan Agar, Houston, USA Kenichi Soga, Department of Civil and Environmental Engineering, University of California, Berkeley, USA A. A. Sulaimon, Department of Petroleum Engineering, Universiti Teknologi PETRONAS, Seri Iskandar, Malaysia

The SpringerBriefs series in Petroleum Geoscience & Engineering promotes and expedites the dissemination of substantive new research results, state-of-the-art subject reviews and tutorial overviews in the field of petroleum exploration, petroleum engineering and production technology. The subject focus is on upstream exploration and production, subsurface geoscience and engineering. These concise summaries (50–125 pages) will include cutting-edge research, analytical methods, advanced modelling techniques and practical applications. Coverage will extend to all theoretical and applied aspects of the field, including traditional drilling, shale-gas fracking, deepwater sedimentology, seismic exploration, pore-flow modelling and petroleum economics. Topics include but are not limited to: • • • • • • • • • • • • • • • • • • •

Petroleum Geology & Geophysics Exploration: Conventional and Unconventional Seismic Interpretation Formation Evaluation (well logging) Drilling and Completion Hydraulic Fracturing Geomechanics Reservoir Simulation and Modelling Flow in Porous Media: from nano- to field-scale Reservoir Engineering Production Engineering Well Engineering; Design, Decommissioning and Abandonment Petroleum Systems; Instrumentation and Control Flow Assurance, Mineral Scale & Hydrates Reservoir and Well Intervention Reservoir Stimulation Oilfield Chemistry Risk and Uncertainty Petroleum Economics and Energy Policy

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Vahid Tavakoli

Geological Core Analysis Application to Reservoir Characterization

123

Vahid Tavakoli School of Geology, College of Science University of Tehran Tehran Iran

ISSN 2509-3126 ISSN 2509-3134 (electronic) SpringerBriefs in Petroleum Geoscience & Engineering ISBN 978-3-319-78026-9 ISBN 978-3-319-78027-6 (eBook) https://doi.org/10.1007/978-3-319-78027-6 Library of Congress Control Number: 2018934945 © The Author(s) 2018 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, express or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. Printed on acid-free paper This Springer imprint is published by the registered company Springer International Publishing AG part of Springer Nature The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

Preface

Cores are the most important and reliable source of subsurface information in reservoir studies. Despite this, few books have been published on this subject thus far and fewer on the geological section of core analysis projects. Many students ask me where we should start and what we should do after data gathering. This book tries to fill this gap. It starts with an introduction and continues with the preparation stages, actually, what happens before starting geological analysis of the cores. Also, this introduction is important because porosity and permeability data are integrated with the geological results to build a perfect framework for reservoir modeling and property distribution within the reservoir. The book continues with microscopic studies. What should be recorded and how? Macroscopic studies are considered and data of interest are explained. Geochemistry helps to a better understanding of the geological properties and therefore its principles and applications are considered. The final chapter covers the integration of geological and petrophysical data to determine the rock types as the main building blocks of the reservoir. The book covers both academic and industrial aspects of geological core analysis and thus is applicable for both groups. Although written for petroleum geologists and reservoir engineers, the book can be useful as a reference for any student, researcher, industry professional, or anyone who deals with cores. This book evolved from my industrial experience on managing and analyzing cores from various hydrocarbon fields and also my graduate courses on petroleum geology. I did not include many photos in the text because I think that readers can observe many of them with a simple search. Instead, I explain more about the fundamental principles and use schematic illustrations for better understanding of the processes or mechanisms. The author is thankful to Dr. Mehrangiz Naderi-Khujin for designing and illustrating most figures of the book. She also read the first version of the manuscript and provided useful comments and suggestions for which I am grateful. She is a talented geologist who is beside me during all stages of my academic and industrial activities. The preparation of the book was made possible through the help of my colleagues and students at the University of Tehran. I also appreciate the cooperation of the private core analysis laboratories and the National Iranian Oil v

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Preface

Company (NIOC) who have helped me develop this book. In addition, I want to thank all my family for their patience during the preparation of this book. I know that with all care and attention, it is possible that I missed some points. Therefore any critique, idea, or suggestion is welcome. Tehran, Iran February 2018

Vahid Tavakoli

Contents

1 Core Analysis: An Introduction . . . . . . . . . . . . . . . . . 1.1 Purpose of the Book . . . . . . . . . . . . . . . . . . . . . . 1.2 Core Analysis Role in Reservoir Characterization . 1.3 Core Analysis Plan . . . . . . . . . . . . . . . . . . . . . . . 1.4 Coring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5 Core Preservation and Transfer . . . . . . . . . . . . . . 1.6 Retrieved Data . . . . . . . . . . . . . . . . . . . . . . . . . . 1.7 Routine Core Analysis . . . . . . . . . . . . . . . . . . . . 1.8 Special Core Analysis . . . . . . . . . . . . . . . . . . . . . 1.9 Wire Line Log Evaluation . . . . . . . . . . . . . . . . . . 1.10 Core Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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2 Preparing for Analysis . . . . . . . 2.1 Core Gamma Logging . . . 2.2 Core–Log Depth Matching 2.3 Core CT-Scanning . . . . . . 2.4 Core Opening and Layout . 2.5 Dean–Stark Extraction . . . 2.6 Core Cleaning . . . . . . . . . 2.7 Marking . . . . . . . . . . . . . . 2.8 Plugging and Trimming . . 2.9 Soxhlet Extraction . . . . . . 2.10 Sidewall Coring . . . . . . . . References . . . . . . . . . . . . . . . . .

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3 Microscopic Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Thin Section Preparation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.1 Thin Section Staining . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Contents

3.2

Quantitative Carbonate Petrography . . . . . . . 3.2.1 Quantitative Siliciclastic Petrography 3.3 Paleontology . . . . . . . . . . . . . . . . . . . . . . . 3.4 XRD Analysis . . . . . . . . . . . . . . . . . . . . . . 3.4.1 Sample Selection . . . . . . . . . . . . . . . 3.4.2 Bulk XRD Analysis . . . . . . . . . . . . . 3.4.3 Clay Mineralogy . . . . . . . . . . . . . . . 3.5 SEM Analysis . . . . . . . . . . . . . . . . . . . . . . 3.5.1 Sample Selection . . . . . . . . . . . . . . . 3.5.2 EDX Analysis . . . . . . . . . . . . . . . . . 3.6 Microscopic Uncertainties . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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4 Macroscopic Studies . . . . . . . . . . . . . . . . 4.1 Core Slabbing and Resination . . . . . 4.2 Core Description . . . . . . . . . . . . . . . 4.2.1 Core Photography . . . . . . . . 4.3 Fracture Presentation . . . . . . . . . . . . 4.4 Core Log Preparation . . . . . . . . . . . 4.5 Sequence Stratigraphy and Reservoir 4.6 Macroscopic Uncertainties . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . .

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5 Geochemical Analysis . . . . . . . 5.1 Sample Selection . . . . . . 5.2 Isotopes . . . . . . . . . . . . . 5.2.1 Carbon Isotope . . 5.2.2 Oxygen Isotope . . 5.2.3 Strontium Isotope 5.3 Elemental Analysis . . . . . 5.4 Uranium Geochemistry . . References . . . . . . . . . . . . . . . .

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6 Rock Typing . . . . . . . . . . . . . . . . . . 6.1 Geological Rock Typing . . . . . 6.2 Hydraulic Flow Units (HFU) . . 6.3 Reservoir Data Integration . . . . 6.4 Defining Electrofacies . . . . . . . 6.5 Comparison and Final Results . References . . . . . . . . . . . . . . . . . . . .

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Chapter 1

Core Analysis: An Introduction

Abstract Cores are a fundamental source of information for exploration, evaluation, development, and production of any hydrocarbon field. Cores are a unique source of some datatypes such as rock textural parameters or permeability. They can be calculated or estimated based on other data sources and cannot be gained directly from those data. Some others, such as porosity, are calibrated against core analysis results. Cores are direct samples from the reservoir rocks that can be tested, analyzed, and viewed by the researcher. A core analysis project starts from the coring plan, coring, and core preservation, and continues with three main phases including routine, geological, and special core analysis. Some additional stages are also included such as geomechanics or geochemistry. Various experts are involved in a core planning task. They consider all variables including requirement, cost, and risk to decide the different aspects of coring and core analysis. After coring, cores are transferred to the laboratory. Core analysis starts with the core gamma logging and whole core CT-scanning. Basic petrophysical parameters using single-phase fluid are measured on the cores in the routine stage. This step also includes core handling and preparation for routine, special, and geological analysis. Geological analysis includes thin section preparation, microscopic and macroscopic studies, and rock typing. Final data are compared with the wire line logs and distributed to the interwell space. Dynamic data are provided using multiphase fluid tests in a special section. All data are integrated to reconstruct the rock and fluid distribution within the reservoir.

1.1

Purpose of the Book

Now, much time has passed from the first coring in a reservoir. A lot of data and experience have been gathered from coring and core analysis of the hydrocarbon reservoirs. There are still more uncertainties in petroleum exploration and production. Various disciplines such as geology, reservoir engineering, petrophysics, geochemistry, and geomechanics are involved in a core analysis project, from core planning to core archiving. Regarding the importance of the cores and core analysis, © The Author(s) 2018 V. Tavakoli, Geological Core Analysis, SpringerBriefs in Petroleum Geoscience & Engineering, https://doi.org/10.1007/978-3-319-78027-6_1

1

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Core Analysis: An Introduction

some textbooks have been written (e.g., McPhee et al. 2015) for this purpose. Other texts cover some aspects of this task, especially on reservoir engineering discipline (e.g., Tiab and Donaldson 2015). These books have little information on the geological aspects of core analysis, from microscopic to macroscopic steps. The methods for geological data integration with basic petrophysical parameters for better understanding of the geological effects on reservoir behavior are also not yet understood perfectly. The purpose of this book is to explain the geological part of a core analysis project from both scientific and industrial points of view. As a matter of fact, geology is the base of any reservoir evaluation and thus direct geological data from cores are very important for the reservoir analysis team. The book explains the geological core analysis from core preparation to the end of analysis and archiving. Both microscopic and macroscopic analyses are included. Furthermore, geochemical measurements and analysis complete the previous tasks and the final results are integrated to construct the building block of the reservoir, the rock types. Subsequently, these findings are arranged based on sequence stratigraphic concepts for reservoir zonation.

1.2

Core Analysis Role in Reservoir Characterization

The basic information for reservoir characterization includes porosity, permeability, water saturation, and net-to-gross ratio. These data are retrieved from two general sources including direct and indirect measurements. The direct sources of reservoir information include core and cutting samples and indirect methods include wire line logging, well tests, and geophysical surveys. Drill cuttings, small pieces of rocks cut by the bit, give a limited type of information. Porosity and permeability cannot be retrieved from the cuttings. The problem of lag time between drilling and their collection time at the well top is a serious error in analyzing these samples. Also, it is possible that a fragment of rock detaches from the well wall after drilling and before casing and mixes with the cuttings of the other intervals. The preliminary coring tools were developed at the end of the 1900s. At the beginning of the 1920s, the first effective coring tools were introduced to the drilling industry (Anderson 1975). Considerable improvements were made in the following years. Currently, there are several types of coring tools. Selecting the coring tool is dictated by the type of reservoir rocks and core analysis purposes. Regardless of the coring method, the result is a cylindrical rock sample from the reservoir. These samples are representative of the reservoir rocks and the most reliable source of information for reservoir studies. They are direct samples of the rocks that could be viewed and touched by humans and tested by laboratory instruments. The static and dynamic data are retrieved from the cores to understand the exact and accurate rock properties and their behavior. Basic as well as advanced petrophysical parameters and fluid flow properties using both single- and multiphase fluids can be obtained from the cores. Wire line logs are calibrated with core data. The most accurate

1.2 Core Analysis Role in Reservoir Characterization

3

Fig. 1.1 Data retrieved from core analysis and their role in reservoir characterization (Courtesy of M. Naderi)

porosity, for example, is obtained from the cores. Calculating the sonic velocity in a rock matrix is another example. Geochemical and geomechanical tests on the core samples reveal many aspects of the reservoir rocks. Most of the geological data such as rock texture, pore type, sedimentary structures, and clay mineralogy are derived from the cores. These data could also be retrieved from other sources but cores are the most accurate source in many cases. Data from cores are compared with the other sources and their integration helps to determine the most accurate static and dynamic characteristics of the reservoir rocks (Fig. 1.1).

1.3

Core Analysis Plan

The first and main question before starting a coring job is about the importance of the cores for the reservoir evaluations. Is this really necessary? In most cases the answer is yes. Coring and core analysis are not expensive compared to the overall

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Core Analysis: An Introduction

budget of well drilling and completion. Nevertheless, cores have vital information for reservoir evaluations and assessments. A team of geologists, petrophysicists, reservoir engineers, drillers, and production personnel begin the core planning by listing the objectives of the job. The ultimate goal is to have more understanding of the reservoir properties. Constraints in timing and budget should also be considered. Selecting the coring tools is based on the rock properties of the target zone. The hole size and environmental conditions such as temperature and pressure also play an important role in this selection. Along with a coring plan, a core analysis plan also should be prepared. This is very important because it determines the future of the cores and type of data retrieved from them. The period of analysis for any task must be completely scheduled. A work breakdown structure (WBS) should be prepared for each part of the analysis. An example of a geological core analysis plan is illustrated in Table 1.1. It is worth mentioning that coring and core analysis are designed for each well individually and are specific for that well. Which part of the analysis, including routine, geological, special, geochemistry, and geomechanics, is really necessary? The prepared data should satisfy the purpose.

Table 1.1 An example of a geological core analysis program for 100 m of cores. The number of samples and time duration are flexible based on available core length, laboratory potential, and number of personnel No.

Task

1 1.1 1.2 1.3 1.4 1.5 2 2.1 2.2 3 3.1 3.2 4 4.1 4.2 4.3

Microscopic studies Thin section preparation Petrographical analysis Micropaleontology Sequence stratigraphy Reservoir rock typing XRD analysis Selection and preparation XRD analysis SEM analysis and imaging Selection and preparation SEM photography Macroscopic core analysis Macroscopic core description Fracture study Core photography (as whole cores and close‐up) Core log preparation Final report preparation

4.4 5

Quantity

Unit

400 400 400 100 400

Sample Sample Sample Meter Sample

20 20

Sample Sample

20 20

Sample Sample

100 100 100

Meter Meter Meter

100

Meter

Month 1 2

3

4

5

6

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8

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1.3 Core Analysis Plan

5

Project management is very important in a core analysis job. Various experts from different disciplines are involved in the project. Coordinating a huge team including coring, transfer, geology, RCAL (routine core analysis), SCAL (special core analysis), and other personnel is a complicated task. The project manager and controller are responsible for observing the time and comparing the planned and actual progress of the core analysis project. Any delay should be monitored carefully and compensated with appropriate arrangements. In a geological core analysis section, the main milestone is thin section petrography. Many other analyses depend on this task. The average time for study of 20 thin sections is one day for a two-person team. Thus 100 thin sections are studied in one working week. Using two teams is not recommended unless they have completely matched before. If time is really a concern, dividing the study into facies and diagenesis parts is an appropriate selection.

1.4

Coring

The coring interval is defined in the forecast program of the well and confirmed by the coring plan team. Drilling is stopped and the string is pulled out of the well. The coring head is attached to the end of the drill string and it runs in the hole. The cutters of the head are made of synthetic diamond or tungsten. The bit cuts the rocks and the cores pass through the hollow center of the bit and enter the core barrel. The core head is selected based on the rock properties subject to drilling. Routine coring systems consist of inner and outer core barrels. The outer core barrel is attached to the drill string. The coring bit is placed at the bottom of the outer barrel. A core catcher at the bottom of the inner core barrel fixes the core sample and prevents it from moving out of the barrel. Drilling fluid is pumped through the annulus between the inner and outer core barrels. Conventional coring tools cut cores with a diameter between 5 cm (2 in.) and 15 cm (6 in.). Each core barrel is 9 m long and the length of about a 27 m (90 ft) barrel for one run is common (three barrels). The cores are cut in 1 m lengths for easy transfer to the laboratory. The sleeves (barrels) are fiberglass in most cases (Fig. 1.2a, b). The inner smooth surface eases core entry. Fiberglass is inert and the mud fluid has no considerable effect on it even during core storage. Aluminum barrels are also used in some cases (Fig. 1.2c). Fiberglass is lighter than aluminum but it has temperature (about 150 °C) and pressure limitations and is less resistant to core jamming during the coring process (McPhee et al. 2015). Some sleeves can be opened longitudinally and allow core visualization and sampling at the wellsite. These sleeves have a hole that lets the drilling fluid out and reduces the hydraulic pressure inside the barrel. Each barrel has two longitudinal parallel lines with two different colors that show the top and bottom of the core (Fig. 1.2b). The natural fluid of the rock changes by mud filtrate invasion into the core sample, gas expansion and expulsion, and fluid vaporization during the coring process in most cases. The last is negligible if the cores are handled and preserved

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Core Analysis: An Introduction

Fig. 1.2 Fiberglass (a, b) and aluminum sleeves (c)

carefully and the cores are analyzed in a reasonable time after coring (maximum of six months). The amount of invasion depends on many parameters including coring method, porosity and permeability of the sample, filtrate and reservoir fluid viscosity, and pressure difference between the mud and net formation pressure. The water-based mud filtrate also reacts with sensitive clay minerals. New systems such as sponge coring try to reduce the fluid invasion into the core sample and so provide more accurate water and oil saturation measurements. Anyway, the direct saturation measurement on the core samples (Dean–Stark test) needs special attention to the coring situations. Gas is expelled from the oil immediately after pressure release in the coring or core opening process. For gas reservoirs, all of the hydrocarbon fluids are expelled before any analysis. Water saturation can still be measured if other conditions are ideal.

1.5 Core Preservation and Transfer

1.5

7

Core Preservation and Transfer

During the core handling and preservation process, any physical alteration of the rock material should be minimized. As mentioned, cores are cut into one-meter sleeves and transported in wooden boxes. Preserving the cores with wax is more effective but this is only routinely done for some sensitive parts of the core or when cores are not to be tested for a long time after the coring process. For example, some reservoir parts of the cores are selected at the wellsite for SCAL tests. These parts are wrapped in high-quality, nonreactive plastic films and aluminum foil and then sunk in molten wax. Cores are extracted from the wax at the time of the planned test. It is recommended to analyze the core just after coring. Fluids react with the barrel and evaporation changes the natural properties of the fluids.

1.6

Retrieved Data

Cores are the main source of information in any reservoir evaluation and characterization project. Significant data from various disciplines are obtained from this source. • Geological evaluations include: – Lithology. The mineral constituents of the rocks and their exact amount using petrographical studies. – Depositional environments. Help to reconstruct the geometry of the reservoir body and determine the possible extent of each facies association. The type of sedimentary environment and sub-environments determines the facies distribution pattern in a 3D reservoir model. – Absolute age dating and chronological sequence establishment. Using fossil records. – Regional scale correlation. Using fossils, geochemical proxies, and sedimentological properties. – Diagenesis. The processes that have affected the rocks after deposition. They have a major role on reservoir properties in many cases. – Fracture analysis. These studies have some limitations on cores but still valuable information can be retrieved. – Pore typing. Using petrographical studies. – Geochemistry. Both organic and inorganic geochemistry help in more accurate and effective analysis and interpretation of the source and reservoir rocks. – Geological rock typing. The basis of the heterogeneity reduction in the reservoir.

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Core Analysis: An Introduction

• Reservoir engineering evaluation: – – – – – – – – – – – – – –

Porosity determination Permeability measurement Reservoir rock typing and hydraulic flow unit determination Oil–water or gas–water contacts Fluid saturation Acoustic velocity Gamma radiation Calibration of wire line logs using engineering data retrieved from the cores (such as porosity, acoustic velocity, or gamma radiation) Grain density Electrical properties Wettability Relative permeability Capillary pressure Pore volume compressibility

• Geomechanical properties: – – – –

1.7

Compressive strength Young’s modulus Poisson ratio Hardness

Routine Core Analysis

Routine core analysis or conventional core analysis (CCAL) is the measurement of basic petrophysical properties of plug samples. The process involves measuring static parameters with a single-phase fluid sample. Core analysis routinely starts with starting RCAL and RCAL starts with core gamma logging. Whole core CT-scanning would be part of the project if it is scheduled in the core analysis plan. Core scanning could be before or after the gamma logging. The project continues with the depth matching, core layout, Dean–Stark sample selection and water saturation measurement, core cleaning, routine sample selection, core plugging, Soxhlet extraction, drying, porosity and permeability measurements, slabbing, photography and imaging, and resination. The sample selection and preparation steps as well as CT-scanning and gamma logging are considered in Chap. 2. The remaining parts including porosity and permeability measurements are considered here. Porosity is defined as the ratio of space available for fluid storage to the bulk volume of the sample. The bulk volume is routinely determined by mercury using Archimedes’ law or by geometric calculations. Mercury is a nonwetting phase and does not wet the surface of the sample. Thus it is completely separate from the sample after the experiment. Bulk volume measurement using mercury

1.7 Routine Core Analysis

9

Fig. 1.3 Schematic design of a standard porosimeter

displacement is not appropriate for samples with vuggy porosity because mercury remains in some spaces of these samples. Mercury is a toxic material and therefore the geometric method is preferred in most cases. The diameter and height of the plug is measured at three to five points and the average value is used to calculate the bulk volume. Porosity is measured using Boyle’s law with a porosimeter. A standard porosimeter consists of a reference chamber, a cell, or sample chamber and pipes. Two gauges measure the pressure at various stages of the test (Fig. 1.3). Porosity is measured in the following steps. 1. Helium gas is expanded from a storage capsule into a reference cell of known volume (V1). Valve 1 is open and valve 2 is closed; thus the gas fills the reference cell and connector pipes. The valve is closed and the system is disconnected from the source. The pressure recorded on gauge 1 is P1. The volume of gas is V1. This is a known value because the volumes of the reference chamber and connecting pipes are specified. 2. Valve 2 is opened. The gas expands from the reference cell to the sample cell and occupies the cell and pipes minus the grain volume. The pressure is recorded on gauge 2 (P2). The plug sample in the cell reduces the space by grain volume. According to Boyle’s law: P1 V1 ¼ P2 V2

ð1:1Þ

This means that the initial pressure multiplied by the initial volume is equal to the second pressure multiplied by the total volume of the cells and pipes minus the space occupied by the solid part of the plug (Vg). Knowing the total volume,

10

1

Core Analysis: An Introduction

including the chambers and pipes, the Vg is calculated. The total volume of the rock is Vb and therefore: Vp ¼ Vb  Vg

ð1:2Þ

If the Vp is known, the porosity is: PorosityðUÞ ¼ Vp =Vb

ð1:3Þ

Grain density is obtained by dividing the weight of the plug by its grain volume. Grain density data are valuable for lithology determination and wire line log data calibration. The important point is that the porosity is included in the bulk density wire line tool whereas only grain density is involved in photoelectric factor measurements in the well. In these definitions, matrix and grain have the same meaning. They form the solid part of the rock. Permeability is defined as the ability of a porous rock to transfer fluids. Only absolute permeability (permeability of a single-phase fluid) is determined in the RCAL section of the core analysis project. This variable is measured by passing a fluid through a porous rock according to Darcy’s law (Eq. 1.4). K ¼ QLl=ADP

ð1:4Þ

where K is permeability (Darcy), Q is the flow rate (cm3/s), L is length (cm), l is fluid viscosity (cP), A is the cross-sectional area (cm2), and DP is the fluid pressure gradient between the input and output points. The SI unit for permeability is m2 but Darcy is more convenient in reservoir studies. A rock sample with a permeability of 1 Darcy, named after Henry Darcy, permits a fluid with viscosity of 1 cP (1 mPa s) flow through 1 cm3/s under a pressure gradient of 1 atm/cm in an area of 1 cm2. It is obvious that 1 Darcy is a very high permeability compared to most reservoir rocks. Therefore the milidarcy (mD) unit is widely used in the petroleum industry. The range of permeability in most reservoirs is between 0.1 and 100 mD. More or fewer permeabilities are also possible, but values lower than 0.1 mD are not sufficient to produce crude oil economically. The cutoff value of 0.01 mD is also applicable for gas reservoirs. Permeabilities lower than 0.01 mD could not carry any fluid for production purposes. The routine part of a core analysis project ends with the SCAL sample selection based on integrated geological and RCAL rock typing (see Chap. 6).

1.8

Special Core Analysis

Special core analyses are advanced tests on core plugs mainly dealing with fluid flow and conductivity of more than one fluid. They are expensive tests needing weeks or months of advanced laboratory measurements and therefore the samples

1.8 Special Core Analysis

11

must be chosen very carefully to obtain the most beneficial data from the reservoir. It is recommended to select the samples after the geological and RCAL studies and measurements. The basic units for SCAL sample selection are rock types (see Chap. 6). All selected samples should be CT-scanned for considering any damages, fractures, stylolites, or other barriers or carriers in the plug. These tests include but are not limited to: • • • • • • • • •

Mercury injection capillary pressure tests (MICP) Relative permeability of two- or three-phase fluids Wettability Reservoir condition petrophysical properties Improved oil recovery (IOR, EOR) studies Determination of Archie exponents: a, m, n NMR core analysis Pore volume compressibility Formation damage effects

1.9

Wire Line Log Evaluation

Wire line logs are the most available data in reservoir studies. They are accessible from almost all wells and reservoir intervals. Actually, extending and developing the core data into the 3D interwell space is based on their comparison with logs. There are various types of wire line logs but the conventional set of logs includes natural gamma radiation (GR), neutron porosity (NPHI), bulk density (RHOB), electrical resistivity (R), and sonic velocity (DT). Data are recorded in LAS format. This format uses the ASCII (American Standard Code for Information Interchange) codes for recording the data. The standard depth increment for wire line logs is 0.1524 m or 15 cm. As the plugging is routinely every 30 cm, core and log data do not have exactly the same depths in the same interval. This fact should be considered when these data are compared with each other. Upscaling the data solves the problem in most cases. A simple linear interpolation also is a good solution in many cases. When the changes in logs and core data are plotted against depth and compared to each other, actually the software is interpolating both of them to draw a line of changes. Wire line log evaluation before core opening is very useful. The log data are analyzed by two methods including probabilistic and deterministic petrophysics (see Kennedy 2015). Both methods are applicable but the probabilistic approach uses all data types and calculates the effect of each variable on the final result. Therefore the latter is preferred. The results are very useful for understanding core and fluid properties before core opening (Fig. 1.4). Net pays are almost clear on logs, the contacts could be defined, and an insight to the core properties is provided. Defining electrofacies and correlating them with final rock types is one of the main parts of reservoir studies (see Chap. 6).

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Core Analysis: An Introduction

Fig. 1.4 An example of wire line log data analysis in a Permian–Triassic age gas reservoir (Kangan and Dalan formations) in the Persian Gulf. Lithology, porosity, and saturations are calculated before core opening (Courtesy of M. Nazemi)

1.10

Core Storage

After completing all analyses, cores must be archived. Rocks are not very sensitive to ambient temperature and humidity. The main part of the fluids is vaporized or cleaned before storage. There are no strict conditions for core maintenance. This is different for Holocene sediment cores in which the environmental conditions are very important for their repository. About the reservoir cores, the subject of this book, the important problems are preventing mildew formation and physical damage during core storage. An accurate system is necessary to find the desired cores in a repository easily. There is a fully automated system in many repositories that can find and move the cores to the study site. A working table suitable for core viewing and description is recommended. Cores must be available for any future

1.10

Core Storage

13

Fig. 1.5 Core storage frames for the whole core (a, b) and thin sections (c)

work. Strong and secure racks are very useful. As with any other repository, health and safety problems must be considered. The core-derived materials such as plugs, trims, and thin sections are also collected and stored after project finalization. Thus a core repository must have the appropriate space for plugs, trims, thin sections, and also cuttings (Fig. 1.5).

References Anderson G (1975) Coring and core analysis handbook. Petroleum Publication Company, USA Kennedy M (2015) Practical petrophysics. Elsevier, Netherlands McPhee C, Reed J, Zubizarreta I (2015) Core analysis: a best practice guide. Elsevier, United Kingdom Tiab D, Donaldson EC (2015) Petrophysics theory and practice of measuring reservoir rock and fluid transport properties. Gulf Professional Publishing, USA

Chapter 2

Preparing for Analysis

Abstract Routine core analysis starts before geological section. This analysis includes core gamma logging, depth matching, CT-scanning, saturation determination, core cleaning, marking, plugging, and trimming the plugs. Natural gamma radiation is measured from the cores for depth matching. This is a very important stage for core–log data comparison and correlation. The depth should also be matched between the various runs of the wire line logs. In the next step, for virtual viewing of fractures before opening, CT-scan images are prepared from the cores. The CT-scan images can also be used for evaluation of some petrophysical parameters. Water saturation of some plugs is measured. Special attention should be given because water-based mud can change the water saturation of the samples. Cores are cleaned for the first stage of macroscopic description and the marking process. Routinely, three horizontal and one vertical plug are prepared from each meter of core. This could be changed according to the project purpose and the number of planned tests. Plugs are cleaned by the Soxhlet extraction method. Two sides of each plug are trimmed. The cleaning process is also applied to the trims in the case of heavy oil content. These trims are used for thin section preparation and starting the geological section of the study. In some cases, plugs are prepared using the sidewall coring method. After sidewall sampling, the other processes are the same. Sidewall coring is suitable in some exceptional cases.

2.1

Core Gamma Logging

Drilling a well is a multidisciplinary work; each section measures the depth individually by its specific tool. Because of using different tools for these measurements, different depths are provided for a distinct point in the well. For example, the logger depth for the bottom hole may be 2010 m whereas this is 2011 m for the driller. As all data should be integrated in the reservoir studies, the same depth must be considered for a specific point. In reservoir modeling, for example, a building block (a cell) has a unique porosity value that is gained based on wire line log and core porosity data integration. This is more vital for very thin reservoir layers, such © The Author(s) 2018 V. Tavakoli, Geological Core Analysis, SpringerBriefs in Petroleum Geoscience & Engineering, https://doi.org/10.1007/978-3-319-78027-6_2

15

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2 Preparing for Analysis

as Kazhdumi (equivalent to Nahr Umr) sandstones in the Persian Gulf Basin. For matching all data in a well, a reference depth is needed, in order that all other downhole information can be shifted accordingly. This reference is the depth of natural gamma ray (GR) data. Almost all tools working in a well have a GR detector that measures the natural GR of the formation. The natural gamma radiation of the reservoir rocks is the result of thorium, potassium, and uranium isotope decay. These radiations are recorded by a detector and calibrate to an API unit. The API unit varies from 0 to 200 for clean to completely shaly formations, respectively. The GR of the cores is also determined before opening. The basic parts of a core gamma logger are a GR detector and a conveyor belt, both mounted on a base (Fig. 2.1). The tool is calibrated before any job. The standard Th, U, and K containers with certain gamma radiation are used for this purpose. As the cores are transferred to the laboratory in one meter length, they are arranged in order of depth before starting the task. After starting the machine, the detector records the background radiation and then the conveyor belt pulls the samples through the detector. The detector measures the quantity of each radioactive element (Th, K, and U) based on their different energy levels. These quantities as well as the total GR count are recorded as a function of depth by the appropriate software connected to the detector. Most of the core gamma loggers record the results based on count per second (CPS) of the radiated GR. It is obvious that there is linear relationship between this count and the natural gamma radiation of the cores. The amount of counted GRs depends on the radioactive elemental concentration, the volume of rock that is scanned, the distance between the source and the detector, and the density of the rock (Ellis and Singer 2007). The depth of investigation for a wire

Fig. 2.1 A core gamma logger and one meter of core on the conveyor belt

2.1 Core Gamma Logging

17

line GR log is about 25 cm (Kennedy 2015). This means that the detector in a well measures GR from a spherical volume with radius of 25 cm. Thus a core with lower volume (a cylinder volume with about 5 cm radius) routinely has lower GR quantities. Ignoring intralayer heterogeneity, both of them measure the GR of the same rocks and have the same GR trend (peaks and troughs). Other factors influencing the gamma ray counts are reservoir and environmental conditions such as fluids, drilling mud, and invasion. In general, there is a linear mathematical relationship between two points of core and well GR data and all others could be transferred based on this relationship. A linear regression line based on all datapoints is a better solution for converting core to log measurements. Such a transformation is known as horizontal shifting or log normalization. This horizontal shifting is not necessary in most cases because the purpose is just marking the variations and matching the depths of cores and wire line log data. This is only necessary when the user wants to calculate a petrophysical property using these two measurements. Because of different measurement conditions such as investigated rock volume, mud filtrate invasion, and formation pressure and temperature, the radiation is not the same for core samples and the borehole wall. In fact, the conditions are not the same even for different runs in one well. Therefore the values are never exactly the same. Figure 2.2 shows three repeated GR measurements of one core compared with the corresponding wire line GR data of the well. As seen, the major trends are similar but the values are not exactly the same.

2.2

Core–Log Depth Matching

After core GR logging, the GR values of cores and well logs are illustrated beside each other and depth matching is performed core by core. The values of each element or the total gamma could be used for this purpose. The total gamma is used in most cases because this measurement includes the variations of all elements. The well log data are a continuous record from all intervals or at least from the reservoir parts, but cores are taken from some reservoir intervals and are discontinuous in some cases. Therefore the depth of well log GR is routinely considered as the base reference and the core depths are shifted, based on the comparison of major peaks and troughs. The sampling interval of the core and well log GR may be different (Fig. 2.2). This is not a major problem in most cases, as the main variations are the same. In the depth-matching process, a key bed such as a thin layer of shale could be a useful guide (Fig. 2.3). When the user shifts a point, all other points are also shifted. Once the first point is shifted, the others are routinely placed almost in the correct position but the process continues until all major variations are exactly matched. This is a time-consuming task that often needs several re-evaluations, but is certainly necessary.

18

2 Preparing for Analysis

Fig. 2.2 Three core gamma measurements from a carbonate Permian core sample of the Persian Gulf Basin (left) and the corresponding wire line data (right)

2.3

Core CT-Scanning

The whole cores are routinely scanned before the core gamma logging. Selected plugs for special core analysis (SCAL) or rock mechanical tests also scan for detection of any fracture prior to test. Specialized core scanners are used in many cases but hospital scanners are also functional. In a routine process, many cross-sectional slices are prepared using an X-ray scanner. The number of slices depends on the tool resolution, purpose, and budget of the project but it is more than a routine human body scan. The result of a CT-scan illustrated by the grayscale spectrum varies from pure white to pure black. Denser material adsorbs more X-rays and so appears white. Porosities are black to dark gray according to their fluids. Note that the hydrocarbon gases are expelled from the cores even before opening. Cement-filled spaces are mostly bright because they are denser than the surrounding matrix (anhydrite cements, e.g.). Fractures are black if they contain fluids, and white if they have been filled by cement during diagenetic processes. The images are also used to evaluate the core heterogeneity. Special software can integrate all slices and produce a 3D image of the core. The main purpose of CT-scanning is recognizing any fractures prior to the core opening (Fig. 2.4).

2.3 Core CT-Scanning

19

Fig. 2.3 GR depth-matching log is composed of original and shifted core logs compared with wire line log data. The table of shifts is also included

Nowadays, high-resolution CT images are used for calculating petrophysical properties of the samples. These images form the basis of a new developing analysis called digital petrophysics.

2.4

Core Opening and Layout

After core gamma logging and CT-scanning, the sleeve cap is removed and the core pushed out from the sleeve. Caps are made from plastic and are bound to the top and bottom of the core using stainless-steel clamps (Fig. 2.5a). Routinely, cores are easily pushed out by slightly tilting the core barrel. Hitting the barrel with a plastic

20

2 Preparing for Analysis

Fig. 2.4 An example of anhydrite-filled fractures on CT-scan images. Cross-sectional slices (a), the longitudinal whole core image (b), and slabbed core photo (c) are also illustrated

hammer is also useful. The hammer must be used with care because it can induce fractures in the core sample. If it is not possible, the barrel is cut out and the core is brought out. This is done by fixed or portable power saws. After opening 1 m of core, the Dean–Stark samples are taken immediately and preserved for later saturation measurement (see Sect. 2.4). The core is then laid out on the appropriate tables. These tables have some gutter or pyramid shape positions to prevent core rotation. The tables are normally made of steel and thus putting a half UPVC pipe with the same core size below the core is recommended to prevent any core damage (Fig. 2.5b). After opening, two parallel longitudinal lines with different colors are drawn on the cores using waterproof markers. They show the top and bottom and prevent core rotation during the plugging process (Fig. 2.5c).

2.5 Dean–Stark Extraction

21

Fig. 2.5 The layout process. Opening the caps (a), laying out the cores on the table (b), and drawing two parallel lines on the cores (c)

2.5

Dean–Stark Extraction

Dean–Stark extraction is the first evaluation of the water saturation (Sw) of the samples. A plug is prepared just after opening the core sleeve using an oil-based lubricating fluid and then is placed in a distillation extraction system (Fig. 2.6). The boiling solvent (toluene in most cases) vaporizes the water content of the sample. Both solvent and water condense and collect in a graded tube. The water is denser and is collected at the bottom of the container and the solvent overflows and returns to the flask. The process continues until no more water is collected. This takes about two days depending on core porosity, permeability, and hydrocarbon viscosity. The water volume is recorded. The plug is cleaned using the Soxhlet extraction method and the pore volume is measured using Boyle’s law (see Sect. 1.7). After that, the water saturation of the sample is calculated by dividing the water volume to the pore volume of the sample. It should be noted that the water-based mud routinely filtrates some water to the core and thus cores that are drilled with oil-based mud are preferred for this test.

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2 Preparing for Analysis

Fig. 2.6 Dean–Stark water saturation measurement apparatus

2.6

Core Cleaning

After core opening and Dean–Stark sampling, the cores are cleaned. This is different from plug cleaning using Soxhlet extraction. The cores are cleaned with water if there are no water-sensitive minerals in the cores such as clays or halite. If there are, they are cleaned with only a nylon brush. This process is ignored for the unconsolidated cores as they disaggregate during this process. This is also not possible for oil reservoirs, especially cores containing heavy oil. The cleaning process removes the remaining drilling mud from the core surface (Fig. 2.7). A preliminary core description and fracture analysis is done after the cleaning process. The core cleaning process also prepares the cores for the marking stage. It is possible to cover some selected parts of the core with nylon and aluminum foil for sensitive tests such as geochemical analysis (Fig. 2.7).

2.7

Marking

After cleaning, the plug locations are determined on the cores. A petrophysical evaluation of the wire line logs before the marking process is very useful because the marking policy depends on the reservoir properties of the rocks in most cases. Routinely, three horizontal and one vertical plug are prepared from each meter of core. Thus three horizontal plugs are prepared every meter. There is no strict rule for selecting the location of a vertical plug on 1 m of core. It is recommended to

2.7 Marking

23

Fig. 2.7 Core cleaning process using water and a nylon brush for consolidated cores. Some parts could be covered for sensitive tests (the T marked part at the center of image)

prepare it wherever there is a horizontal fracture in the core and therefore there is no need for further core cutting. Each plug type is marked with a special symbol using a waterproof marker (Fig. 2.8a). Additional plugs such as plugs needed for rock mechanical or special tests also are marked with different symbols or colors. The project’s geologist, reservoir engineer, and petrophysicist as well as lab operator supervise the core marking process. One of the most important aspects of core marking is how the team looks at the reservoir and nonreservoir parts and the heterogeneity of the rocks. It is possible to ignore the nonreservoir intervals or reduce the plug frequency in these parts but the important point is that such changes should be considered in all aspects of future studies. As many experts work with the numerical values, ignoring the nonreservoir sections may cause misunderstanding of the reservoir behavior. If the team ignores a 2-m thick anhydrite layer, it must be considered in reservoir modeling. This is also the same for some intervals with no plugs, such as shale layers. In most cases, it is not possible to prepare the plugs from shaly intervals because they disaggregate in the plugging process. Anyway, they have a major role in reservoir performance and compartmentalization. In the core description process all macroscopic properties are recorded. They should be integrated with any large-scale reservoir studies.

24

2 Preparing for Analysis

Fig. 2.8 The process of marking (a) and plugging (b)

Another important point in the marking process is the location of contacts. Below the oil–water or gas–water contact, the rocks have less interest in reservoir studies. Below these contacts, the Sw is 1 and thus no hydrocarbon will flow. Therefore, the plug frequency is reduced. For example, one plug for each meter of core is an appropriate selection.

2.8

Plugging and Trimming

Cores are prepared from vertical wells in most cases. Horizontal plugs are prepared perpendicular to the core length; they are horizontal if you imagine them in their original position in the reservoir. Vertical plugs are prepared parallel to the core axis (Fig. 2.8b). In cores with high angle layering, horizontal plugs are prepared parallel to layering. In a homogeneous rock, porosity is a scalar intrinsic property of the rock and is not direction-dependent. In contrast, permeability is a vector property and depends on the flow direction. Absolute permeability is also an intrinsic property of the rock and does not depend on fluid properties. It is measured in 100%

2.8 Plugging and Trimming

25

saturation of a single-phase fluid. Therefore the direction of the plug has no effect on porosity or geological properties, but permeabilities are different in various directions. Routinely, the horizontal permeability is more than the vertical because the grains are deposited perpendicular to their maximum projection area. The process of plugging is the same for all plugs except the Dean–Stark samples that are prepared using an oil-based cooler fluid. The plugs are 2.5–5 cm in diameter and 5–10 cm in length. They are prepared based on job priority. It means that the plugs of the most important task are taken first. If, for example, the rock mechanical studies are more important for the reservoir, their plugs are prepared first. After their plugging, the routine plugging for porosity and permeability studies starts. Double plugs are taken as close as possible if there is any need for nearly the same plugs for various tests (such as overburden and relative permeability). A cylindrical drill cuts the sample using a cooler fluid, mostly water. If there is any water-sensitive mineral in the rock, an oil-based cooling fluid is used. After the plugging process, a cylindrical sample with rough up and down surfaces is available. In the trimming process, these two surfaces are cut and two chips of rocks are available (Fig. 2.9). They are put in a bag with their identity information and sent for thin section preparation. More trims could be cut if additional ones are needed. For oil formations, especially heavy oil reservoirs, trims are also cleaned using Soxhlet extraction. The process of cleaning is exactly the same as for plugs.

Fig. 2.9 Plugs are used for other petrophysical and reservoir tests whereas trims are used for thin section preparation and geological studies

26

2.9

2 Preparing for Analysis

Soxhlet Extraction

The Soxhlet extraction method is used for cleaning plugs in a core analysis job (Fig. 2.10). The plug contains hydrocarbons and salt water; both must be removed before other analyses such as porosity or permeability measurements. The trims are also cleaned if the samples contain crude oil, especially heavy oil. A Soxhlet extraction assembly is composed of a heater, flask that contains the solvent (methanol or toluene), side arm, siphon arm, sample chamber, and condenser system. The vaporized solvent travels up the side arm, condensates, and falls down to the chamber. The distilled liquid solves the plug contaminations. The process continues until the level of solvent reaches the siphon point. Then all the liquid containing the solvent, crude oil, and salts refluxes from the chamber, returning to the flask. With this method, the solvent recycles each time of refluxing and the distilled clean liquid is in contact with the plugs. The process starts with toluene to remove the crude oil from the plugs. The cleaning time depends on the sample properties (such as porosity and permeability) and the oil density. The process may take about one month for plug samples containing heavy oil. Samples can be checked with UV light to see any remaining contamination. After cleaning with toluene, the Soxhlet cleaning continues with methanol to remove the remaining salts. Samples are dried using an oven. The plugs are ready for other routine core analysis (RCAL) tests and trims are now suitable for thin section preparation. As mentioned previously, this process is not necessary for trims of a gas reservoir. There are also some other methods for plug cleaning (see McPhee et al. 2015).

Fig. 2.10 Schematic illustration of Soxhlet extraction system for cleaning the plug (or trim) samples

2.10

2.10

Sidewall Coring

27

Sidewall Coring

Sidewall is not really a coring method. It is more like a plugging method from the borehole wall. A percussion or rotary sidewall corer is placed against the interval of interest using a wire line tool. In the percussion method, hollow tubes with sharp edges are shot into the wellbore wall. The tube is forced into the formation using explosive charges and a cylindrical sample, the same as a plug, is picked up from the formation. It is obvious that this method is not applicable to tight consolidated formations such as tight carbonates. The high pressure used for tube penetration changes the texture of the unconsolidated form and fractures the harder rock samples. Therefore the percussion method has been almost completely replaced by rotary sidewall coring. In this method, a hollow tube rotates against the borehole wall. A bit that has been assigned to the head of the tube cuts the sample and collects it in the tool. The tool is taken back to the surface. The number of samples collected in each run depends on the tool. It could be between 20 and 60 plugs. The plugging distance is variable based on the project need. The old sidewall plugs were smaller than the standard sizes used for routine reservoir studies but today the standard plugs are prepared by various companies. Many plugs are deformed in sidewall coring by both percussion and rotary methods. Sidewall coring is recommended when the routine coring process with full recovery is not possible or the reservoir has enough data. In the latter case, just a special test or data from an interval are necessary. For example, if everything is known about a reservoir from previously cored and logged wells and there is just an unconventional mud lost in a new well, a sidewall coring is necessary. Sidewall coring is also useful for soft formations such as loose sands. Sidewall coring is cheaper and faster than the routine coring method, but there are many disadvantages. At first, the full recovery of the reservoir is not available. This is a main problem, as many fluid behaviors in the reservoir depend on some specific layers. The mud pressures used in drilling and filtrate invasion both change the nature of the sample. These samples are not appropriate for reservoir mechanical tests. They are not even eligible for porosity and permeability measurements. The fluid content also has been changed during the coring process. However, they are still suitable for geological studies.

References Ellis D, Singer JM (2007) Well logging for earth scientists. Springer, Amsterdam Kennedy M (2015) Practical petrophysics. Elsevier, Amsterdam McPhee C, Reed J, Zubizarreta I (2015) Core analysis: a best practice guide. Elsevier, United Kingdom

Chapter 3

Microscopic Studies

Abstract Microscopic observations are one of the main sources of information for geological studies. This is more important in core analysis with limited macroscopic samples. Routine microscopic studies of a core sample include petrographical analysis to understand facies properties and diagenetic processes, paleontological studies for absolute age dating, X-ray diffraction for mineral identification (especially clays), scanning electron microscopy equipped with energy dispersive spectroscopy for pore and pore throat determination, mineral identification, and elemental analysis. The static reservoir properties of a sample depend completely on primary (facies) or secondary (diagenesis) characteristics of the rocks. The rock mineralogy, constituents, sedimentary environment, microscopic porosities, cements, compaction features, and many other parameters are gained by study of a rock sample under a polarizing microscope. They are recorded on standard sheets and compared with other rock properties derived from routine or special core analysis sections. Paleontological studies are used for absolute age dating and make it possible to correlate the strata in a chronostratigraphic framework. Such a framework is integrated with other microscopic and macroscopic geological data and provides the reservoir zonation scheme and understanding of reservoir geometry. Fine-size minerals, especially clays, are identified by the X-ray method. They play a vital role in reservoir properties and future drilling in the field. Pore types and pore throats determine the fluid flow properties and major rock types of the reservoir. They have a major effect on reservoir heterogeneity. Final results are combined with other sources and characterize the geological role in micro and regional scale distribution of reservoir properties.

3.1

Thin Section Preparation

Petrography is the basis of any geological core analysis task. After trimming the plugs, trims are used for thin section preparation. If there is any oil staining, especially in heavy oil fields, trim cleaning is necessary. Trims are cleaned with the Soxhlet extraction system, the same as plug samples. There is no need for removing © The Author(s) 2018 V. Tavakoli, Geological Core Analysis, SpringerBriefs in Petroleum Geoscience & Engineering, https://doi.org/10.1007/978-3-319-78027-6_3

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3 Microscopic Studies

drilling salts from the trims. They are routinely removed during thin section preparation stages. It should be mentioned that thin sections could also be prepared from anywhere in the core. Just a small sample is enough. The trims have at least one flat surface that is attached to a glass slide using epoxy. If the sample is not a trim, it has no flat and smooth surface and therefore a first cut is necessary. The slide must be frosted before attaching the sample. This is to roughen the surface in order for the epoxy to bind well. The other side is cut using a diamond saw (Fig. 3.1a, b) and what remains is ground away until the desired thickness is reached. This is a very important stage because there is a high risk of rock damage in this step. Go slow and be careful. The user should check the thickness in short intervals until light passes through the sample. This calls for a great deal of experience. Most of the core samples are composed of carbonates or siliciclastic minerals. Checking is more important when working with mud-dominated or mixed siliciclastic–carbonate samples because they are more prone to damage. The grinding process starts with 400-grit carborundum on a rotating steel disk (Fig. 3.1c) and continues with the 600-grit carborundum on a glass plate (Fig. 3.1d). The final optional stage is smoothing the surface with 1000-grit carborundum. Thin section slides are typically 25 mm
45 mm but larger ones are also produced. They are routinely covered with another glass slide (Fig. 3.1e, f) using epoxy again. The rock sample is about 30 lm (0.03 mm) thick and light passes through the rock and glasses. Every mineral has its special properties in normal or polarized lights. All visible parameters from the rock are recorded.

Fig. 3.1 Thin section preparation steps. Cutting the sample with a saw (a), automatic grinding disk (b), manual disk (c), and final grinding on glass (d). Final result (e, f). Courtesy of A. Rezazadeh

3.1 Thin Section Preparation

3.1.1

31

Thin Section Staining

Mineral staining is used for rapid and accurate identification of some common minerals. New techniques such as scanning electron microscopy (SEM) or cathodoluminescence can also display such information more reliably than staining, but due to the availability and low cost of staining, it is still used for this purpose. There are different techniques for staining various minerals. Carbonate staining is used for distinguishing calcite from dolomite or aragonite. Mineral staining has a long history. The most widely used methods for carbonates are a dilute hydrochloric acid containing alizarin red S (ARS), potassium ferricyanide, or a mixture of both (Dickson 1965; Evamy 1963). Alizarin is a plant root-derived chemical compound that produces a red stain on hydrochloric acid-reacted carbonates. The calcite and aragonite stain red but dolomite and other minerals remain unstained. The reaction time is very short, from 10 s to about 3 min depending on the acid concentration and the rate of reaction between the sample and acid solution. Use of 8–10 cc HCL plus 100 cc distilled water is recommended in almost all the literature (Friedman 1959; Dickson 1965). The acid is cold, at room temperature, in all cases. Potassium ferricyanide (PF) is used for distinguishing ferroan calcite and dolomite. A pale to deep turquoise blue is produced in the reaction. Rhodochrosite (MnCO3) stains pale brown. The treatment time depends on the reaction rate of the carbonate with the acid solution. As dolomite reacts less vigorously than calcite, the intensity of color is not indicative of the Fe content. There is a nonlinear relationship between iron content and color intensity in pure calcite (Reeder 1983). Hydrochloric acid is used in both methods and thus the sample will react with the solution. The final result is thinner than the original rock sample. Both ARS and FP are useful in carbonate staining and a mixture containing these two materials is recommended (Fig. 3.2).

Fig. 3.2 Staining of carbonate minerals by ARS, PF, and combination [data from Friedman (1959) and Dickson (1965)]

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3.2

3 Microscopic Studies

Quantitative Carbonate Petrography

Petrography is a description of the rocks aided by the microscopic studies of thin sections. This task is fundamental to a geological description of the rocks, and therefore it should be done very carefully with the help of a trained eye. User experience is very important especially in complicated textures, overlapped diagenetic processes, and optical quantitative estimation of the rock constituents. The parameters are clearer and easy to recognize in a qualified thin section. In the study of heavy oil fields, Soxhlet extraction is recommended for the trims, as the oil is not removed in the thin section preparation process and covers the surface of the thin section. In reservoir geology, all parameters are compared to each other in order to understand and interpret the reservoir properties in space and time. To reconstruct such a distribution, the results should be as quantitative as possible. Qualitative descriptions are converted to quantitative variations using a numerical scale. For example, intraclast frequency in a rock could be expressed by none, rare, common, abundant, and very abundant, qualitatively. They are converted to 0–4 in a quantitative description. As this is not exactly the number of intraclasts in the rock, the word semiquantitative is preferable. The numerical frequency can be plotted in a sedimentological log against depth and compared with the porosity or permeability distribution. Digital recording is more applicable as these parameters could be compared with other numerical data. Prepare a sheet containing the headers. Separate the sheet into facies and diagenesis parts (Fig. 3.3). Slightly different parameters are recorded in various projects but the main characters are constant. These parameters include: • General information of the sample. This information includes row number in the database, core number, box number, plug number (if thin section is from the plug), and depth. • Lithology. Generally, all samples are carbonate but other constituents are also present. Minor amounts of quartz and clays are present in most cases. Anhydrite is one of the ingredients in a carbonate–evaporite reservoir. The main lithology is marked by its abbreviation (e.g., L for limestone, D for dolomite, A for anhydrite, etc.). The amount of various carbonate minerals is also important. Calcite and dolomite are dominant in most cases but siderite also can be seen. It is better to evaluate the percentage of each mineral individually. Visual comparison charts are suitable for this purpose (Fig. 3.4). The lithology determines the behavior of reservoir properties in many cases. Wettability is one of the parameters influenced by lithology. Porosity and permeability are controlled partly by the amount of each mineral component in many cases (calcite and dolomite, e.g.). • Allochems. The framework of grain-dominated carbonates is composed of allochems. They are also present in some mud-dominated samples with less frequency. Bioclast, ooid, intraclast, pellet, peloid, and oncoid are the most common allochems. Each represents a distinct environmental condition. Facies classification is mostly based on the micrite frequency, which reflects the

3.2 Quantitative Carbonate Petrography

33

Fig. 3.3 An example of a quantitative carbonate petrography sheet. Parameters are interchangeable based on the project objectives

depositional energy, and the amount of allochems. Point counting is a method to quantify thin section components. A point counter is attached to a microscope stage and moves the thin section with constant increments along a line each time the petrographer pushes a button. Each button is reserved for one component before starting the count (Fig. 3.5). At the end of the line, the operator moves the slide to the beginning of the next line. A counter counts the number of

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3 Microscopic Studies

Fig. 3.4 Visual comparison charts for estimating rock constituents under the microscope [compiled from Bebou and Loucks (1984) and Scholle and Ulmer-Scholle (2006)]

Fig. 3.5 A point counter attached to a polarizing microscope (a) and point counting in JMicroVision (v. 1.27) software (b). Some parts of the figure (b) changed graphically for better view

3.2 Quantitative Carbonate Petrography

35

pushes of each button. Using the number of total points, the percentage of each component is calculated. A total of 300–500 points is recommended. There is also special software for the point counting based on photos that are prepared from the slide. The overall process is the same. There are some limitations such as rotating the stage and seeing the polarizing characters of the minerals in the software. There are also some advantages such as automatic calculations and showing the results with various charts and diagrams immediately. The results of the point counting process are accurate enough to compare with the other reservoir parameters. • Sedimentary features. Many sedimentary features in addition to the allochems and lithology components are used in geological interpretations. These features are different from project to project and vary based on the research purpose. Some of these features include bioturbation, opaque minerals, lamination, mud crack, brecciation, and fenestral fabric of the rock. • Facies name. In general, all sedimentary rock attributes could be used to define a facies (Reading 1986). These characters include lithology (lithofacies), fossil content (biofacies), or even the depositional current (turbidity facies). The parameters of interest reflect the primary depositional conditions of the sample. Thus any diagenetic process and feature is ignored before naming the facies. For example, a pseudomatrix created by disaggregation of mud clasts in a sandstone is not related to the primary depositional environment and is subtracted from the overall matrix content of the rock for facies nomenclature. Dunham (1962) classification modified by Embry and Klovan (1971) is the most employed classification of carbonate facies (Fig. 3.6).

Fig. 3.6 Dunham (1962) classification of carbonates modified by Embry and Klovan (1971)

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This classification is well applicable in the petroleum industry because it is based on rock texture which reflects the reservoir properties of the samples. The point is that actually the microfacies are classifying but it is routine to use the word facies. In carbonates, microfacies include all microscopic and macroscopic features of the rock (Flugel 2010). After core description, the macroscopic features also are attributed to the microscopic facies. The classification is based on the energy of the depositional environment. Thus the frequency of micrite versus allochems is the key factor for facies determination. Classification based on rock texture is not adequately enough in most cases, because allochems play an important role in interpretation of sedimentary environments. The most frequent allochems (more than 10%) are also used in the name of facies. For example, an ooid grainstone is a mud-free carbonate rock with ooids as the most frequent allochem. The two most frequent allochems are also used in order of frequency. For example, a bioclast peloid wackestone is a mud-dominated carbonate sample and the main allochem is peloid but bioclasts are also present with more than 10% frequency. Carbonates are very heterogeneous and this type of classification yields a lot of names. Most of these rocks have been deposited in the same depositional conditions. Bioclast wackestone and peloid wackestone both are deposited in a lagoon of the ramp environment (Flugel 2010). Therefore they are merged in one facies group, bioclasts/peloid wackestone. The problem may be different for the intraclast and ooid grainstones that deposit in shoal and leeward shoal environments, respectively. The purpose of facies determination is interpretation of the primary depositional setting and this goal should be kept in mind in facies merging to build facies groups. An example of facies merging in Permian– Triassic carbonates of the Persian Gulf Basin is illustrated in Table 3.1. Plotting the appropriate charts for illustrating the distribution of various facies in a facies group is a good guide for further interpretations (Fig. 3.7). The final result is used for defining facies associations that belong to one environment. For example, all facies deposited in a ramp peritidal setting are integrated to build a peritidal zone environment. It is recommended to assign a code number to each facies. This code is used in drawing charts, columns, and any comparison with other reservoir properties. They are arranged based on related depositional environments, routinely from land to sea. • Sedimentary environments. As mentioned previously, facies groups are merged to build a facies association. Each association is related to a particular depositional setting. The facies and sedimentary environments are some of the most useful data in sequence stratigraphy of a reservoir. • The amount of porosity and pore types. The porosity value is determined with visual estimation, point counting, or image analysis using various software. In visual estimation, porosity value is determined using comparison charts for visual estimation under the microscope. The results of porosity values derived from the point counting are comparable to laboratory tests. It is obvious that the visual and laboratory values are not exactly the same in most cases. Commonly, visual estimates of porosity from thin sections are lower than the routine core

3.2 Quantitative Carbonate Petrography

37

Table 3.1 An example of facies merging in Permian–Triassic carbonates of the Persian Gulf Basin Facies code

Facies groups

Included

Environment

F1 F2 F3

Anhydrite Claystone Mudstone often with evaporites Stromatolite boundstone Thrombolite boundstone Fossiliferous mudstone

Anhydrite Claystone Mudstone/dolomudstone

Supratidal Peritidal Peritidal

Stromatolite boundstone

Peritidal

Thrombolite boundstone

Peritidal

Fossiliferous mudstone/fossiliferous dolomudstone

F7

Peloid, bioclast wackestone

F8

Oncoid/peloid packstone

F9

Ooid, bioclast packstone

F10

Oncoid, bioclast/ ooid grainstone

F11

Peloid ooid/ bioclast grainstone

Peloid wackestone, bioclast wackestone, peloid bioclast wackestone, bioclast peloid wackestone, intraclast bioclast wackestone, intraclast wackestone, ooid wackestone, ooid peloid wackestone, peloid ooid wackestone, intraclast ooid wackestone, intraclast peloid wackestone, oncoid bioclast wackestone, oncoid ooid wackestone, oncoid wackestone, peloid intraclast wackestone, peloid oncoid wackestone Peloid packstone, peloid bioclast packstone, bioclast peloid packstone, bioclast oncoid packstone, intraclast oncoid packstone, oncoid bioclast packstone, oncoid intraclast packstone, oncoid packstone, oncoid peloid packstone, peloid oncoid packstone, oncoid ooid packstone Bioclast packstone, bioclast ooid packstone, intraclast bioclast packstone, intraclast ooid packstone, ooid bioclast packstone, ooid packstone, ooid peloid packstone, peloid intraclast packstone, peloid ooid packstone, intraclast ooid packstone, intraclast packstone, oncoid ooid packstone, ooid intraclast packstone, ooid oncoid packstone Oncoid grainstone, oncoid bioclast grainstone, oncoid ooid grainstone, Bioclast oncoid grainstone, ooid oncoid grainstone, peloid oncoid grainstone Ooid peloid grainstone, peloid ooid grainstone, bioclast peloid grainstone, peloid bioclast grainstone, peloid grainstone

Peritidal/ Lagoon/ open marine Lagoon

F4 F5 F6

Lagoon

Leeward shoal

Leeward shoal

Shoal

(continued)

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Table 3.1 (continued) Facies code

Facies groups

Included

Environment

F12

Bioclast/ooid grainstone

Shoal

F13

Intraclast bioclast/ ooid grainstone/ packstone

F14

Crystalline carbonate

Ooid grainstone, ooid bioclast grainstone, bioclast ooid grainstone, bioclast grainstone Intraclast grainstone, intraclast bioclast grainstone, bioclast intraclast grainstone, bioclast intraclast packstone, intraclast ooid grainstone, ooid intraclast grainstone, ooid intraclast packstone, intraclast peloid grainstone, intraclast peloid packstone, peloid intraclast grainstone, intraclast packstone, intraclast oncoid grainstone Crystalline carbonate

Seaward shoal

None

Fig. 3.7 An example of facies distribution within a facies group (F7 of Table 3.1, Peloid, bioclast wackestone). The main allochems in about 75% of facies are peloid and bioclasts. Other facies have been deposited in the same sedimentary environment

analysis (RCAL) tests. This is because there are microporosities in the sample that cannot be seen in optical microscope scale. These include microporosity between the micrite particles, calcite cements, dolomite crystals, and also within the micritic envelopes of the grains. There are also different methods for evaluating porosity from thin sections using automated image analysis techniques. Image binarization is recommended to separate the matrix and porosity effectively before analysis. Binarization is the process of dividing the whole pixels of the image into two classes, usually black and white. The problem is complicated

3.2 Quantitative Carbonate Petrography

39

as minerals have various colors with different intensities under polarizing light. Preparing thin sections with blue-dye stained resin facilitates porosity recognition. The one-side flat sample is impregnated with the mixture of blue dye and epoxy resin using a vacuum chamber. The colored resins fill the porosities. Pore types determine some petrophysical properties of the reservoir samples, such as porosity–permeability relationships. Pore typing is also an appropriate method for rock typing and grouping the samples to reduce reservoir heterogeneity (e.g., Ahr 2008). Various types of macropores, pores that are visible under the light microscope, are determined at this stage. The results are comparable with laboratory measurements such as mercury injection capillary pressure (MICP) or nuclear magnetic resonance (NMR) data. • Fractures. The most important point is that fracture study based on thin sections or even plugs is not an accurate method. Plugs and thin sections are prepared from the nonfractured intervals and thus the fractures seen on thin sections or plugs are not good indicators of the fractures in the reservoir. However, fracture intensity (frequency), size, and filling are recorded. The fracturing mechanism is also recorded, if possible (see Sect. 4.3). • Cementation. Type and frequency of cements have major effects on reservoir properties. In carbonates, isopachous, blocky, bladed, drusy, and anhydrite cements are more common. • Compaction features. Stylolites and solution seams represent chemical compaction. They have major effects on reservoir properties in some cases (e.g., Mehrabi et al. 2016). Concave–convex contacts, suture surfaces between the grains, and microfracturing within the grains can be combined in a physical compaction item. The compaction rate shows the integrated effect of compaction indicators. • Dolomites and the dolomitization process. These change the porosity and permeability, their relationships, rock density, pore throat size distribution, and wettability of the reservoir. Types and frequency of various dolomites are very important. Dolomites are divided based on their size and shape. One of the early classifications was made by Friedman (1965). Sibley and Gregg (1987) represented a more complete classification based on size and crystal boundary relationships. Various classifications could be used but generally dolomites are divided into planner and nonplanner according to their shape, and sucrosic and dolomicrite based on their size. Sucrosic dolomites are coarse-grained, usually euhedral rhombs with crystals between 20 and 120 lm (Warren 2000). Smaller dolomites (less than 20 lm) are dolomicrites. The rate of the dolomitization is also recorded. Compromise boundaries with many crystal-face junctions represent the planar dolomites. Nonplanar dolomites are characterized by irregular boundaries. Dolomites can also be classified based on their relationships with the precursor fabric. If they follow the original fabric, they are fabric-retentive (mimic) and if the depositional fabric is obscured by dolomitization, fabric-destructive (nonmimic) dolomites are formed.

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There are also some other features that cannot be related to a group. For example, neomorphism, micritization, micrite envelope, and anhydrite nodules could be recorded. They are used for recognizing sedimentary environments, diagenetic processes, sequence stratigraphic boundaries, and interpreting reservoir quality variations within a reservoir. Selecting samples for any other analysis such as SEM, XRD, blue-dye thin section preparation, geochemical studies, or any other tests are recorded in separate columns. A tick mark can be recorded for every selected sample in its column. The geologist easily filters the data and sees the various characteristics of the selected samples. This also results in saving time when the analyst wants to know about the various analyses, number of samples, their facies characteristics, and diagenetic processes. The laboratory tests of the plugs are recorded beside the thin section parameters. Porosity, permeability, and grain density are common parameters recorded in the thin section study sheet. This is important because the next step is comparing laboratory results with the geological characters. Recording all parameters in one database facilitates such comparisons. Porosity and permeability distribution within every geological group (such as facies or rock type) can be observed easily. For example, a simple filtering based on facies code and drawing a scatterplot with porosity and permeability data constitute a first look at the reservoir quality of that facies (see Sect. 6.3). It is more convenient to record the results of various rock typing methods such as Lucia, Winland, FZI, and Lorenz (see Chap. 6) beside the results of thin section studies. With this method, the geological parameters of each rock type are easily recognizable and comparable with the rock types resulting from the geological methods. There are always some uncommon parameters in any reservoir. Therefore the last column is “Remarks.” Properties that are not included in the database and also are not a routine characteristic of the reservoir are recorded here. This column is used for better understanding and interpretation of other variations.

3.2.1

Quantitative Siliciclastic Petrography

Many parameters are the same in carbonate and siliciclastic petrography. Some other parameters can be applied with some modifications (Fig. 3.8). • General information and depth are exactly the same. • Lithology is composed of three main components including quartz, feldspars, and rock fragments (lithics). These three components represent the energy and duration time of the transportation. Quartz is the most stable constituent. High amounts of quartz are evidence of high energy and longtime transportation of the sediments. Lithics are good representations of the provenance rocks. They are the most unstable particles and easily disaggregate in a high-energy transportation system. Feldspars are also sensitive to environmental situations. They transform to other minerals, especially clays, in humid conditions. Such change also depends on time. In coastal sediments with a long history of wave erosion

3.2 Quantitative Carbonate Petrography

41

Fig. 3.8 An example of a quantitative siliciclastic petrography sheet. Parameters are interchangeable based on the project objectives

and deposition, the main component is quartz. In a meandering river with humid environmental conditions, feldspars are altered into clays. In some cases, carbonate grains (mostly bioclasts) are also present. These grains are formed in a depositional environment in most cases. Thus carbonate grains represent a mixed siliciclastic–carbonate setting if they are present in considerable amounts. Evaluating the amount of each component is exactly the same as the carbonates. • The size of grains in a siliciclastic rock characterizes the energy of the transporting media and the depositional environment. In carbonates, the size is mostly affected by the dimension of the organism and therefore it is not as

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important as clastics. The grain size is generally divided into gravel (>2 mm), sand (0.063 to 60 lm)

Uniform Patchy

Intraparticle Moldic

Vuggy Mudstone microporosity

Micropores (20–30 lm) Micropores (