GRI - CBM Gas in Placasdfe Analysis

®

Coalbed Reservoir Gas-In-Place Analysis

Coalbed Reservoir Gas-in-Place Analysis A Short Course Published by Gas Research Institute Chicago, Illinois, U.S.A. Printed in the U.S.A.

Prepared by Matt Mavor Tesseract Corporation Park City, Utah

Charles R. Nelson Gas Research Institute Chicago, Illinois

GRI Reference No. GRI-97/0263

Basic Research Group

October 1997

Coal Reservoir Gas-in-Place Analysis

Copyright
1997 by Gas Research Institute All Rights Reserved.

This work is the property of Gas Research Institute. No part of this work may be used or reproduced without prior written permission from Gas Research Institute, and no part of this work may be transmitted to any other party in any form or by any means, electronic or mechanical, including without limitation, photocopy, record or input into any information storage or retrieval system without prior written permission from Gas Research Institute. Requests for permission to reproduce any part of the work should be mailed to Contract and License Management Group Gas Research Institute 8600 West Bryn Mawr Avenue Chicago, Illinois 60631 LEGAL NOTICE This publication was prepared as an account of work sponsored by Gas Research Institute (GRI) and other organizations. Neither GRI, members of GRI, nor any person or organization acting on behalf of either; A.

MAKES ANY WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED WITH RESPECT TO THE ACCURACY, COMPLETENESS, OR USEFULNESS OF THE INFORMATION CONTAINED IN THIS PUBLICATION, THAT THE USE OF ANY INFORMATION, APPARATUS, METHOD, OR PROCESS DISCLOSED IN THIS PUBLICATION MAY NOT INFRINGE PRIVATELY OWNED RIGHTS, OR

B.

ASSUMES ANY LIABILITY WITH RESPECT TO THE USE OF, OR DAMAGES RESULTING FROM THE USE OF, ANY INFORMATION, APPARATUS, METHOD, OR PROCESS DISCLOSED IN THIS PUBLICATION.

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About This Book This book is a technical reference of procedures used for determining the gas-in-place volume of coalbed reservoirs. Gas-in-place is the volume of gas stored within a specific bulk reservoir rock volume. Accurate gas-in-place analysis is crucial to reliably evaluating coalbed gas exploration prospects, forecasting the gas production rates of coalbed reservoirs, and evaluating the potential severity of natural gas emissions during coal mining operations. Coalbed reservoir gas-in-place analysis is a very complex process. Four physical reservoir parameters are needed to calculate the gas-in-place volume: reservoir or well drainage area; gross reservoir rock thickness (consisting of both coal and other organic-bearing rock types); average reservoir rock density; and average in-situ gas content. Accurately determining these four reservoir parameters presents numerous data collection and analysis challenges. Most of the methods commonly used for determining these reservoir parameters have inherent shortcomings that significantly affect the accuracy and comparability of gas-in-place analysis results. Three major sources of gas-in-place error are underestimation of the gross reservoir thickness, average reservoir rock density, and average in-situ gas content. The emphasis in this book is on providing practical information, guidelines, and procedures for analyzing coalbed reservoir data. We have included insights into sources of error and the comparative accuracy of commonly used analysis procedures rather than lengthy technical explanations of the theories behind these procedures. Example problems and exercises are given throughout the text to promote understanding of the analysis procedures and to facilitate independent, self-paced training by practicing petroleum geologists and reservoir engineers. The text in each chapter is supplemented by references identifying literature sources containing additional information. Specifically, this book will help you to:






Approach your specific analysis problems more systematically and effectively. Improve your ability to account for variations in sample composition and gas content. Understand the major sources of errors in gas-in-place estimates. Understand the comparative accuracy of commonly used analysis procedures. Understand the value added by using best practice analysis procedures.

The information in this book represents the accumulated knowledge and expertise of specialists from many disciplines. Most of this information is the product of more than a decade of basic coal science and field-based coalbed reservoir engineering research sponsored by the Gas Research Institute. The new data, technical insights, guidelines, and procedures that resulted from this research can help you to more reliably evaluate the development potential of coalbed gas reservoir prospects and to optimize the recovery and economics of existing coalbed gas production operations. Several coalbed gas producers and service laboratories have independently evaluated and documented the applicability and practical value of these guidelines in basins throughout the United States and other countries throughout the world. In short, the information in this book can help you make better informed decisions about developing this important natural gas resource.

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Coalbed Reservoir Gas-in-Place Analysis

Acknowledgments Mr. Matt Mavor of Tesseract Corporation and Dr. Charles R. Nelson of Gas Research Institute (GRI) prepared this book under funding provided by the Basic Research Group of GRI. The methodology and material are the results of efforts of many persons. In particular, Mr. Timothy J. Pratt of TICORA Geosciences, Inc. and Dr. Jay C. Close of Burlington Resources, Inc., were instrumental in the development, implementation, and improvement of the technology. EnerVest San Juan Operating LLC allowed us to include data collected from their properties that was not part of GRI efforts. The following reviewers helped in the development of this book and the course materials. Ms. Tom Ann Casey Dr. Jay C. Close Mr. Timothy J. Pratt Mr. John R. Robinson

EnerVest San Juan Operating LLC Burlington Resources, Inc. TICORA Geosciences Inc. Tesseract Corporation

About the Authors Matt Mavor is a petroleum reservoir engineer with twenty-three years of educational, engineering, field operations, and research experience in the oil and natural gas production industry. Matt received B.S. and M.S. degrees in Petroleum Engineering from Stanford University in 1977 and 1978. Since November of 1988, Matt managed or participated in coalbed reservoir research projects funded by the Gas Research Institute. These projects were designed to quantify the properties of coalbed reservoir reservoirs, to predict fluid production rates from and through these reservoirs, to design and optimize well drilling and completion procedures, and to transfer the technology to the natural gas industry. He has extensive publications in the technology of extracting gas from coal seams. He is currently located in Park City, Utah. Charles R. Nelson, Ph.D. is the manager of the Basic Coal Sciences Program at the Gas Research Institute (GRI). Since joining GRI in 1981 he has directed a broad range of research studies involving coalbed reservoir geochemistry, porosity, permeability, gas content, and gas-in-place analysis, and has authored numerous technical reports, papers, and presentations dealing with this research. He has served on several government advisory committees concerned with fossil energy research, the Society of Petroleum Engineers Emerging and Peripheral Technology Committee (1991-1994), and the 1997 International Coalbed Methane Symposium Executive Committee. He developed and was the editor of the book Chemistry of Coal Weathering published by Elsevier Science Publishers in 1989 and was a co-editor of the book A Guide to Determining Coalbed Gas Content published by GRI in 1995. He is a member of the American Association of Petroleum Geologists, Society of Petroleum Engineers, and American Chemical Society. Dr. Nelson received his B.S. degree in 1970 from North Carolina State University and earned post-graduate degrees in organic chemistry from the University of Montana (M.S.) in 1973 and North Carolina State University (Ph.D.) in 1976. Prior to joining GRI, Dr. Nelson worked as a research chemist at STFI in Stockholm, Sweden and at the Massachusetts Institute of Technology where he conducted environmental geochemistry research.

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Table of Contents

Table of Contents Chapter 1 Gas-in-Place Analysis Overview .......................................................................................... 1-1 Reservoir Types......................................................................................................................................1-1 Conventional Gas Reservoirs............................................................................................................1-1 Gas Condensate Reservoirs................................................................................................................1-2 Unconventional Gas Reservoirs .........................................................................................................1-2 Coalbed Gas Reservoirs .....................................................................................................................1-2 Gas-Bearing Shale Reservoirs............................................................................................................1-3 Coalbed Gas Recovery ...........................................................................................................................1-4 Coalbed Gas Content Analysis...............................................................................................................1-4 Pressure Coring ..................................................................................................................................1-5 Direct Method Analysis .....................................................................................................................1-5 Indirect Method Analysis ...................................................................................................................1-6 Gas Resource Assessment ......................................................................................................................1-8 Additional Analysis Challenges .............................................................................................................1-8 Accuracy Benchmarking ........................................................................................................................1-9 Chapter 1 References .............................................................................................................................1-9 Chapter 2 Gas-in-Place Methodology and Error Summary.................................................................. 2-1 Gas-in-Place Relationship ......................................................................................................................2-1 Gas-in-Place Estimate Errors .................................................................................................................2-3 Drainage Area Errors .........................................................................................................................2-3 Gross Coal Thickness Errors..............................................................................................................2-3 Average In-Situ Density Errors..........................................................................................................2-4 Gas Content Errors.............................................................................................................................2-4 Eight Step Evaluation Procedure............................................................................................................2-8 Summary ................................................................................................................................................2-8 Additional Reading ................................................................................................................................2-9 Chapter 2 References .............................................................................................................................2-9 Chapter 3 Coal Sample Gas Content Evaluation.................................................................................. 3-1 Desorption Measurement Procedure ......................................................................................................3-1 Residual Gas Content .............................................................................................................................3-3 Gas Composition Measurements............................................................................................................3-4 Sample Composition ..............................................................................................................................3-4 Proximate Analysis ............................................................................................................................3-6 Ultimate Analysis...............................................................................................................................3-7 Desorption Data Requirements ..............................................................................................................3-7 Desorption Data Correction ...................................................................................................................3-8 Direct Method ......................................................................................................................................3-11 Interpretation Equations ...................................................................................................................3-12 Diffusivity ........................................................................................................................................3-13 Saturated Reservoir Time Zero ........................................................................................................3-14 Undersaturated Reservoir Time Zero...............................................................................................3-16 Desorption Time Correction ............................................................................................................3-16 Temperature Recovery Time............................................................................................................3-17

v

Coalbed Reservoir Gas-in-Place Analysis Ambient Temperature Direct Method ..............................................................................................3-18 Direct Method Calculations .............................................................................................................3-19 Smith & Williams Method ...................................................................................................................3-20 Amoco Method.....................................................................................................................................3-20 Summary ..............................................................................................................................................3-20 Additional Reading ..............................................................................................................................3-20 Chapter 3 References ...........................................................................................................................3-21

Chapter 4 Multiple Sample Analysis ..................................................................................................... 4-1 Composition and Density Relationship..................................................................................................4-3 Equilibrium Moisture Content ...............................................................................................................4-8 Number of Sample Required..................................................................................................................4-9 Drill Cutting Gas Content vs. Inorganic Content Correlations ............................................................4-11 Summary ..............................................................................................................................................4-13 Additional Reading ..............................................................................................................................4-13 Chapter 4 References ...........................................................................................................................4-14 Chapter 5 Thickness, Density, and Gas-in-Place Estimates................................................................ 5-1 Gross Thickness and Average Density Estimates ..................................................................................5-1 Individual Reservoir Identification ........................................................................................................5-2 In-Situ Ash Content................................................................................................................................5-3 In-Situ Gas Content................................................................................................................................5-4 In-Situ Density and Gas Content Distributions ......................................................................................5-5 Gas-in-Place Estimates...........................................................................................................................5-6 Summary ................................................................................................................................................5-7 Additional Reading ................................................................................................................................5-7 Chapter 5 References .............................................................................................................................5-7 Chapter 6 Coal Gas Sorption & Storage Capacity................................................................................ 6-1 Sorption at the Molecular Level.............................................................................................................6-1 The Langmuir Isotherm..........................................................................................................................6-2 Isotherms for Multiple Gas Components ...............................................................................................6-4 Free Gas-in-Place Volume .....................................................................................................................6-6 Solution Gas-in-Place Volume...............................................................................................................6-7 Use of Isotherm Data for Saturated Reservoirs......................................................................................6-8 Summary ................................................................................................................................................6-9 Additional Reading ................................................................................................................................6-9 Chapter 6 References ...........................................................................................................................6-10 Chapter 7 Additional Problems ............................................................................................................. 7-1 Problem 7-1. Valencia Canyon 32-1 Gas-in-Place.................................................................................7-1 Problem 7-1. Solution ............................................................................................................................7-2 Problem 7-2. Desorption Volume Correction and Gas Content.............................................................7-3 Problem 7-2. Solution ............................................................................................................................7-6 Problem 7-3. Time Zero and Direct Method Horizontal Axis Value.....................................................7-7 Problem 7-3. Solution ............................................................................................................................7-9 Problem 7-4. Recognition of Desorption Measurement Conditions ....................................................7-11

vi

Table of Contents Problem 7-4. Solution ..........................................................................................................................7-12 Problem 7-5. Direct Method Analysis..................................................................................................7-13 Problem 7-5 Solution ...........................................................................................................................7-16 Problem 7-6. Reservoir Temperature Direct Method Analysis............................................................7-18 Problem 7-6. Solution ..........................................................................................................................7-20 Problem 7-7. Multiple Sample Analysis...............................................................................................7-21 Problem 7-7. Solution ..........................................................................................................................7-22 Problem 7-8. Density-Ash Content Relationship.................................................................................7-24 Problem 7-8. Solution ..........................................................................................................................7-26 Problem 7-9. Core Density Evalution...................................................................................................7-27 Problem 7-9. Solution ..........................................................................................................................7-29 Problem 7-10. Number of Valencia Canyon Core Samples.................................................................7-30 Problem 7-10. Solution ........................................................................................................................7-32 Problem 7-11. Interval Thickness and Density....................................................................................7-33 Problem 7-11. Solution ........................................................................................................................7-34 Problem 7-12. Valencia Canyon 32-1 Ash and Gas Content...............................................................7-35 Problem 7-12. Solution ........................................................................................................................7-36 Problem 7-13. Maximum Possible Gas Recovery................................................................................7-37 Problem 7-13. Solution ........................................................................................................................7-38 Problem 7-14. Extension of Valencia Canyon 32-1 Gas Content Data...............................................7-39 Problem 7-14. Solution ........................................................................................................................7-41 Problem 7-15. Gas-In-Place for the Southern Ute 5-7.........................................................................7-43 Problem 7-15. Solution ........................................................................................................................7-48

Nomenclature Summary.......................................................................................................8-1 Glossary................................................................................................................................9-1

List of Tables Table 1-1. Table 1-2.

Fruitland Formation Coalbed Reservoir Property Data ................................................... 1-7 Fruitland Formation Gas-in-Place Estimates.................................................................... 1-8

Table 2-1. Table 2-2.

Agreement between Direct Method and Benchmark Gas Contents.................................... 2-5 Summary of Common Gas Content Mass Bases................................................................. 2-7

Table 3-1. Table 3-2. Table 3-3.

Summary of the Core Desorption Procedure. .................................................................... 3-1 Example Core Desorption Data Sheet ............................................................................... 3-9 Sorption Time Shape Factors. .......................................................................................... 3-14

Table 4-1. Table 4-2. Table 4-3. Table 4-4.

Summary of Published Maceral Density Ranges. .............................................................. 4-6 Fruitland Formation Organic Fraction Density Estimates................................................ 4-6 Summary of Equation 4-5 Organic Density Estimates ....................................................... 4-7 Hypothetical Example of Drill Cutting Gas Content vs. Ash Content.............................. 4-12

Table 5-1.

GRI #2 Upper Reservoir Gas-in-Place Summary. ............................................................. 5-6

Table 7-1. Table 7-2. Table 7-3. Table 7-4. Table 7-5. Table 7-6.

Problem 7-1 Parameters. ................................................................................................... 7-1 Problem 7-1 Solution.......................................................................................................... 7-2 Problem 7-2 Core Desorption Data Sheet. ........................................................................ 7-5 Completed Problem 7-3 Desorption Data Sheet. ............................................................. 7-10 Valencia Canyon 32-1 Gas Desorption Summary............................................................ 7-18 Problem 7-7 Ash Content Values. .................................................................................... 7-21 vii

Coalbed Reservoir Gas-in-Place Analysis Table 7-7. Table 7-8. Table 7-9. Table 7-10. Table 7-11. Table 7-12. Table 7-13. Table 7-14. Table 7-15. Table 7-16. Table 7-17. Table 7-18.

Problem 7-7 Solution........................................................................................................ 7-22 Valencia Canyon 32-1 Core Density vs. Ash and Inorganic Content. ............................. 7-24 Problem 7-10 Solution...................................................................................................... 7-31 Problem 7-12 Input Data.................................................................................................. 7-34 Problem 7-12 Solution...................................................................................................... 7-35 Valencia Canyon 32-1 Reservoir Properties.................................................................... 7-37 Valencia Canyon 32-3 Coal Gas Reservoir Property Estimates...................................... 7-39 Southern Ute 5-7 Reservoir Temperature Core Desorption Data.................................... 7-40 Southern Ute 5-7 Gas Content – Inorganic Content Relationship. .................................. 7-45 Southern Ute 5-7 Upper Coal Interval Log Analysis Summary. ...................................... 7-46 Southern Ute 5-7 Lower Coal Interval Log Analysis Summary. ...................................... 7-47 Southern Ute 5-7 Gas-in-Place Summary. ....................................................................... 7-47

List of Figures Figure 1-1. Figure 1-2. Figure 1-3. Figure 1-4.

Fruitland Coal and Conventional Gas Reservoir Storage Capacity Comparison ............. 1-3 U.S. Lower-48 Coalbed Gas Resources ............................................................................. 1-4 Comparison of Saturated and Undersaturated Production Behavior................................ 1-6 Fruitland Gas Content and Vitrinite Reflectance Relationship.......................................... 1-7

Figure 2-1. Figure 2-2.

Coal Gas Reservoir Geometry............................................................................................ 2-3 Comparison Between Direct and Other Total Gas Content Estimates. ............................. 2-5

Figure 3-1. Figure 3-2. Figure 3-3. Figure 3-4. Figure 3-5. Figure 3-6.

Desorption Canister Schematic.......................................................................................... 3-2 Gas Volume Measurement Apparatus. ............................................................................... 3-3 Size Scale Dependent Heterogeneity of Coal Seams .......................................................... 3-5 Example Direct Method Graph. ....................................................................................... 3-12 Sample Internal Temperature Changes............................................................................ 3-17 Comparison of Ambient & Reservoir Temperature Desorption Data.............................. 3-19

Figure 4-1. Figure 4-2. Figure 4-3. Figure 4-4. Figure 4-5. Figure 4-6. Figure 4-7.

GRI #2, Air-Dry Gas Content vs. Inorganic Content. ........................................................ 4-1 GRI #1 Air-Dry Gas Content vs. Inorganic Content. ......................................................... 4-2 Relationship between Sample Density and Ash Content. ................................................... 4-5 Valencia Canyon 32-1 Equilibrium Moisture Content vs. Temperature............................ 4-8 Operating Characteristic Curves ....................................................................................... 4-9 Southern Ute 5-7 Air-Dry Gas Content vs. Inorganic Content. ....................................... 4-11 Hypothetical Example of Drill Cutting Gas Content vs. Ash Content.............................. 4-13

Figure 5-1. Figure 5-2. Figure 5-3. Figure 5-4. Figure 5-5.

GRI #2 Coal Log ................................................................................................................ 5-1 San Juan 30-5 Density and Production Log Data ............................................................. 5-2 Comparison of S. U. 36-1 Ash Content from Logs and Core Data .................................... 5-3 Comparison of S. U. 36-1 Gas Content from Logs and Core Data.................................... 5-4 GRI #2 Upper Reservoir Gas-In-Place Distribution.......................................................... 5-6

Figure 6-1. Figure 6-2.

Example Langmuir Isotherm Relationship. ........................................................................ 6-3 COAL Site Multicomponent Isotherm Relationships.......................................................... 6-6

Figure 7-1. Figure 7-2. Figure 7-3

Example Direct Method Graphs....................................................................................... 7-11 Problem 7-4 Solution........................................................................................................ 7-12 Problem 7-5 Direct Method Graph .................................................................................. 7-15

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Table of Contents Figure 7-4. Figure 7-5. Figure 7-6. Figure 7-7. Figure 7-8. Figure 7-9. Figure 7-10. Figure 7-11. Figure 7-12. Figure 7-13. Figure 7-14. Figure 7-15. Figure 7-16. Figure 7-17.

Problem 7-5 Direct Method Graph Solution.................................................................... 7-16 Problem 7-6 Gas vs. Inorganic Content Graph ............................................................... 7-19 Problem 7-6 Gas vs. Inorganic Content Graph Solution ................................................. 7-20 Problem 7-7 Density vs. Inorganic Content. .................................................................... 7-23 Problem 7-8 Core Density Analysis Graph...................................................................... 7-25 Problem 7-8 Core Density Analysis Graph Solution........................................................ 7-26 Operating Characteristic Curves for Problem 7-9........................................................... 7-27 Problem 7-8 Solution........................................................................................................ 7-29 Valencia Canyon Intermediate Coal Interval Log. .......................................................... 7-30 Valencia Canyon Section 32 Basal Coal Interval Structure Map. ................................... 7-36 Final Problem Gas Content vs. Inorganic Content Graph .............................................. 7-41 Southern Ute 5-7 Upper Coal Interval Log...................................................................... 7-42 Southern Ute 5-7 Lower Coal Interval Log...................................................................... 7-43 Southern Ute 5-7 Gas Content – Inorganic Content Relationship. .................................. 7-45

List of Examples Example 2-1. Gas-In-Place at the COAL Site. ......................................................................................... 2-2 Example 3-1. Example 3-2. Example 3-3. Example 3-4. Example 3-5.

Correction of Desorption Data. ....................................................................................... 3-11 Calculate Time Zero for Desorption. ............................................................................... 3-15 Compute the Direct Method Horizontal Axis. .................................................................. 3-17 Estimate the Temperature Recovery Time........................................................................ 3-18 Direct Method Gas Content, Diffusivity, and Sorption Time. .......................................... 3-19

Example 4-1. Average Dry, Ash-Free Gas Content Estimates for Low Confidence Data Sets. ............... 4-2 Example 4-2. Relationship between Density & Inorganic Content. ......................................................... 4-3 Example 4-3. Number of COAL Site Core Samples Required ................................................................ 4-10 Example 5-1. In-Situ Ash & Gas Content Calculations............................................................................ 5-5 Example 5-2. GRI #2 Average Density, Thickness, and Gas Content. ..................................................... 5-8 Example 6-1. Example 6-2. Example 6-3. Example 6-4.

Estimate Important Reservoir Conditions. ......................................................................... 6-4 COAL Site Multicomponent Storage Capacity................................................................... 6-5 Maximum Gas-In-Place in the COAL Site Natural Fracture System................................. 6-7 COAL Site Isotherm-Based Gas Content Estimate............................................................. 6-9

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1 Chapter

G

Gas-In-Place Analysis Overview

as-in-place is the volume of gas stored within a specific bulk reservoir rock volume. A gas-in-place analysis is generally performed for a specific purpose such as gas resource assessment, reservoir production modeling, or geologic hazard evaluation. Gas resource assessments play an important role in the evaluation of new reservoir exploration prospects. Accurate production modeling is critical to achieving optimal development decisions and reliable production potential forecasts for natural gas reservoirs. Gas-in-place analysis is also used in the mining industry to determine if natural gas emissions will be a hazard during tunnel construction or during the mining of coal, oil shale, trona, and potash. Gas-in-place analysis is a very complex process that involves numerous data collection and analysis challenges. The complexity is due, in part, to the fact that most reservoir parameters used for calculating the gas-in-place cannot be measured directly but must instead be indirectly estimated using data obtained by analysis of various rock properties. Four reservoir parameters are needed to calculate the gas-in-place for conventional gas reservoirs: reservoir or well drainage area; reservoir thickness; reservoir rock porosity; and the vapor phase saturation within the porosity. The equivalent four properties for coal gas reservoirs are the area, thickness, reservoir rock density, and in-situ gas content. The reservoir or well drainage area and the reservoir thickness are usually determined through analysis of geophysical well logs, seismic data, and structure maps. The reservoir rock porosity, vapor phase saturation, density, and gas content are usually determined using data obtained from well logs or

laboratory analysis of drill cuttings and core samples.1 The methodology used for determining the insitu gas content varies considerably depending upon such factors as the analysis type, purpose, and, most important, the reservoir type. The analysis type refers to the basic geologic unit being assessed such as a basin, region, or reservoir. The analysis purpose refers to whether the objective is gas resource appraisal, reservoir production modeling, or geologic hazard evaluation. The reservoir type refers to the physical reservoir environment and gas storage mechanism. There are four principal gas storage mechanisms within reservoir rocks. • • • •

Compression of gas molecules within rock pores. Absorption of gas molecules by crude oil or brine. Inclusion of gas molecules within solid, crys talline water molecule lattices. Adsorption of gas molecules within micropores.

Another cause of gas-in-place analysis complexity is the fact that reservoir rock compositional properties and gas content are not uniform throughout a given formation but vary both vertically and laterally as a function of numerous geologic variables. Thus, geologic descriptions and physical property data derived from drill cuttings, cores, and well logs are only single sampling point measurements and may not be representative of the average in-situ rock properties throughout a reservoir. The greater the reservoir heterogeneity,

1.1

Chapter

1

Gas-In-Place Analysis Overview

the greater the number of samples and sampling sites needed for adequate characterization of the average insitu rock properties.

the reservoir gas is not a constant composition fluid but separates into vapors and liquids upon pressure reduction.2

Reservoir Types

Unconventional Gas Reservoirs. When rock pores contain liquid phase fluids such as brine or crude oil, some natural gas can be stored as an absorbed phase. The solubility of natural gas in brine and crude oil varies as a function of the reservoir temperature and pressure, the molecular properties of the liquid phase fluid, and the molecular properties of the gas constituents.5,6 If natural gas and water occur together within the pores of rocks in permafrost zones or outer continental shelf margin regions, the gas is stored by inclusion within solid, crystalline compounds called gas hydrates.7,8 The gas content of the hydrate phase varies as a function of the reservoir temperature and pressure, hydrate crystal structure, and the molecular properties of the gas constituents. A single cubic foot of methane hydrate can store as much as 164 standard cubic feet of methane gas.8 The in-place gas hydrate resources worldwide are estimated to total 6.6x105 Tscf.8 Worldwide, significant amounts of natural gas are stored by absorption in crude oil reservoirs (called dissolved or solution gas), in aquifer reservoirs (called brine gas), and in geopressured reservoirs (called geopressured gas). Brine gas is commercially produced in small quantities in several areas of the U.S., Japan, China, and elsewhere throughout the world.9 Technology has not yet been developed for economically recovering natural gas from geopressured and gas hydrate reservoirs, and these types of gas reservoirs are generally regarded as potential gas kick or blowout hazards if encountered during well drilling operations.7

There is a variety of reservoir types with substantial differences due to the gas storage mechanism. These include conventional gas reservoirs, gas condensate reservoirs, unconventional gas reservoirs, coalbed gas reservoirs, and gas-bearing shale reservoirs. Conventional Gas Reservoirs In conventional natural gas reservoirs the gas molecules are stored by compression within rock pores. The gasin-place analysis is a straightforward volumetric calculation since the total gas volume within the reservoir is solely a function of the total pore space volume containing gas and the in-situ gas content within a unit volume of pore space.1 In general, there is no significant gas molecule-reservoir rock interaction, and the reservoir functions as a constant-volume tank, i.e., the rock porosity does not vary significantly as a function of pressure change. When natural gas is a constant composition fluid, i.e., does not undergo phase change upon reduction in reservoir pressure, the amount of natural gas stored by compression within a specified rock pore volume can be calculated using temperature, pressure and volume relationships derived from fundamental gas laws. Thus, the in-situ gas content is a direct function of the effective rock porosity, reservoir temperature and pressure, and gas composition.1,2 Because the pores of conventional reservoir rocks contain formation water, the water saturation must be estimated to determine the volume of gas within the porosity. Gas-Condensate Reservoirs At reservoir temperatures and pressures greater than 200 °F and 2,000 psia, respectively, natural gas can dissolve significant amounts of non-volatile hydrocarbons.3 If the non-volatile hydrocarbon concentration is greater than about 0.7 mole percent, the reservoir is referred to as a gas-condensate reservoir.4 Gas-inplace analysis is not straightforward for gas-condensate reservoirs and special engineering and operating methods are needed for maximizing gas recovery since

1.2

Coalbed Gas Reservoirs In coalbed reservoirs the natural gas is predominantly stored (~98%) as a molecularly adsorbed phase within micropores. A small amount of natural gas (~2%) is stored by a combination of compression within natural fractures and absorption in formation water. Very little natural gas can be stored by compression in coalbed reservoirs because the fracture porosity generally ranges from less than 1% to 5% and is

typically more than 90% water saturated at initial reservoir conditions.9 Coalbed gas reservoirs result from a unique set of geologic processes wherein the coal performs the dual roles of organic source and reservoir for hydrocarbon gases formed as co-genetic products of the natural coalification process.10,11 The gas storage capacity of a coalbed reservoir varies as a function of the reservoir temperature and pressure, the coal compositional properties, the micropore structure and its surface properties, and the molecular properties of the adsorbed gas constituents.10,11 However, the actual in-situ adsorbed phase gas content is also a complex function of geologic factors which affected the retention of adsorbed phase gas within the reservoir. Thus, an accurate in-situ gas content value cannot be calculated solely from knowledge of physical coal properties but instead must be directly determined through measurements performed on freshly-cut reservoir coal samples. The primary characteristic of coalbed reservoirs which makes them commercially attractive as sources of natural gas is their ability to store extraordinarily high gas-in-place volumes at relatively shallow depths. The high gas storage capacity is due to the adsorbed phase natural gas having a liquid-like density.13 For example, Figure 1-1 illustrates a comparison of the gas-in-place per unit reservoir volume for a typical coalbed gas reservoir in the San Juan Basin, Fruitland Formation compared to that of a conventional sandstone reservoir of 25% porosity and 70% gas saturation. A greater volume of gas is stored in the coal at pressures less than 2,250 psia. This pressure equates to a depth of roughly 5,000 feet. Gas-Bearing Shale Reservoirs In gas-bearing shale reservoirs the gas molecules are stored by a combination of compression within matrix and fracture porosity, absorption by bitumen, and adsorption by organic carbon and clay minerals.14 The gas storage capacity of

shale reservoirs varies as a function of the reservoir temperature and pressure, porosity, total organic carbon content, clay mineral content, and the molecular properties of adsorbed gas constituents. Adsorption generally accounts for over 50% of the total stored gas volume in gas-bearing shale reservoirs.15 In 1994, gas-bearing shale reservoirs provided nearly 1.5% (259 Bscf) of the total natural gas production in the United States.16 Currently, the most active plays for gas-bearing shales in the United States are the Antrium shale in the Michigan Basin, the Devonian shales in the Appalachian Basin, the Barnett shale in the Fort Worth Basin, the Niobrara shale in the Denver Basin, and the New Albany shale in the Illinois Basin. A recently published assessment for the Upper Cretaceous Lewis Formation shale in the San Juan Basin of Colorado and New Mexico indicates that this shale formation contains in-place natural gas resources estimated to total 96 Tscf.17

Coalbed Gas Recovery The earliest record of gas recovery from coalbed reservoirs was in China in 900 A.D. where natural gas

Figure 1-1. Fruitland Coal and Conventional Gas Reservoir Storage Capacity Comparison.

1.3

Chapter

1

Gas-In-Place Analysis Overview

issuing from coalbeds was transported in bamboo pipes and used as fuel to generate heat for manufacturing salt by brine evaporation.18 In the United States, the earliest record of gas recovery from coalbed reservoirs was in the early 1900s when a water well drilled into a coal seam in the Powder River Basin was capped and the produced natural gas used as a heating fuel.10 However, prior to the 1950s the petroleum industry regarded coalbeds only as sources of gas-kicks and blowout hazards during well drill operations. The first deliberate attempts to target coalbed reservoirs in the United States as gas well completion objectives was in the early 1950s in the San Juan Basin.19 Significant commercial coalbed gas production did not begin in the United States until the early 1980s.10 Today, technology for economically producing natural gas from coalbed reservoirs has reached a state of demonstrated maturity and these reservoirs are important natural gas exploration targets.20 In 1995, coalbed reservoirs accounted for 5% (956 Bscf) of the total natural gas production and 6% of the total natural gas reserves in the United States.21 It is estimated that coalbed reservoirs hold 14% (147 Tscf) of the total recoverable natural gas resources in the United States.22 The in-place coalbed gas resources in the U.S. lower-48 states are estimated to total over 675 Tscf.23 Figure 1-2 shows the geographic distribution of the U.S. lower-48 coalbed gas resources. Information about these coalbed gas resources can be found in References 16, 21, and 24 . Alaska also has huge coal deposits which contain inplace coalbed gas resources estimated to total 1,000 Tscf.25 The success of coalbed gas production in the United States has sparked intense interest worldwide in this new gas resource, particularly in coalrich nations in Eastern Europe and Asia.

data since this parameter is the basis for forecasts of the gas production rates and cumulative gas production volumes from these reservoirs. The in-situ gas content is a crucial parameter in the formula used to calculate the gas-in-place volume, but the accurate determination of in-situ gas content is neither simple nor straightforward. It is not currently possible to use geophysical logging technology to accurately determine the volume of gas stored in-situ by molecular adsorption. This limitation occurs since the presence of adsorbed phase natural gas has little effect upon the physical properties of the bulk reservoir rock. For example, an in-situ adsorbed phase methane content of 400 scf/ton would increase the density of a 100% organic content sample having a density of 1.295 g/cm3 by only 0.010 g/cm3, or 0.8%.26 Three methods are commonly used for determining in-situ gas content values: pressure coring; direct methods; and indirect methods.27 Each of these methods has inherent shortcomings which can significantly affect the accuracy and comparability of gas content analysis results.

Pressure Coring The pressure coring method involves trapping a cored rock sample downhole within a sealed barrel

Coalbed Gas Content Analysis The growing importance of commercial coalbed gas production has dictated the critical need for accurate gas-in-place

Figure 1-2. U.S. Lower-48 Coalbed Gas Resources.

1.4

thereby preventing any loss of gas by desorption while the sample is being retrieved to the surface. The in-situ gas content is then determined by measuring the total volume of gas that desorbs from the sample. The primary advantage of pressure coring is that it is the only method capable of directly measuring the total in-situ gas content of the cored rock sample. However, this method requires specialized equipment that is difficult to successfully operate on a routine basis in the field. Pressure coring is also about five times as expensive as conventional coring methods and its use has generally been restricted to research studies.28

Figure 1-3. Comparison of Saturated and Undersaturated Production Behavior.

Direct Method Analysis The direct method analysis procedure was originally developed by the coal mining industry to evaluate the potential severity of natural gas emissions during underground mining operations.27,29,30,31,32 This mining industry method involves sealing freshly cut drill cuttings or conventional core samples in an airtight desorption canister and then measuring the volume of gas that desorbs as a function of time at ambient temperature and pressure conditions. The measured desorbed gas volume is not equal to the total in-situ gas content since some gas desorbs and is lost during the sample collection process and some gas is usually retained by the coal at ambient temperature and pressure desorption conditions. The lost gas volume is commonly estimated by graphical analysis of the measured gas desorption data. The residual gas volume is determined by measuring the volume of gas released when the coal sample is crushed and heated at the conclusion of the desorption measurements. The total gas volume of the coal is equal to the sum of the estimated lost gas volume, the measured desorbed gas volume, and the measured residual gas volume. The chief limitation of the direct method analysis procedure is that it yields widely different in-situ gas content estimates depending upon the coal sample type and collection methodology, analysis conditions, and

data analysis methods.26,28,33,34,35,36 This method-dependent gas content analysis result variation warrants careful consideration when planning or conducting a coalbed reservoir gas-in-place analysis since it indicates that some sample types, analysis conditions, and data analysis methods have inherent shortcomings which bias the gas content analysis result accuracy. For example, the in-situ gas content estimates obtained by analysis of drill cuttings and conventional core gas desorption data commonly differ by 25% or more.26,28,34 Gas content errors of this magnitude cause very large errors in the gas production rates and cumulative recovery estimated using reservoir simulation techniques. Figure 1-3 illustrates the differences in predicted gas production rate and cumulative recovery that results from a 30% gas content under-prediction for a typical high productivity San Juan Basin coalbed gas well. The maximum gas production rate was under-predicted by 82%, and the ultimate recovery (gas reserves) was underestimated by 63%.28 It is not uncommon for the cumulative gas volumes obtained from coalbed reservoir and gas-bearing shale wells with long production histories to be substantially less than or even greatly exceed the initial, producible reserve estimates.19,36 As an example, the 10 year cumulative gas production for 23 coalbed gas

1.5

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Gas-In-Place Analysis Overview

wells at the Oak Grove field in the Black Warrior Basin of Alabama was 3.2 Bscf, but only 1.55 Bscf of initial gas-in-place was originally calculated to be contained within the coal comprising the reservoirs.37 The discrepancy was believed to be due to low reservoir volume estimates and low initial gas content estimates. Variances between initial gas-in-place and cumulative gas production volumes of this magnitude warrant careful scrutiny since they indicate a significant potential for reserve growth in existing fields and for expanding the recoverable gas resource base by exploiting coalbed gas and gas-bearing shale resources that are currently viewed as uneconomic.

Figure 1-4. Fruitland Gas Content and Vitrinite Reflectance Relationship.

very unreliable since coalbed reservoir gas content variation trends can be very erratic throughout a basin. Indirect Method Analysis For example, Table 1-1 shows reservoir property data The indirect method is used when reservoir coal collected during Gas Research Institute cooperative samples are not available and basically involves evaluresearch projects at five Upper Cretaceous Fruitland ating the in-situ gas content using empirical correlations which relate known variations in gas content or Formation coalbed gas wells34in the San Juan Basin of Colorado and New Mexico. For the entire data set storage capacity against variations in easily measured there is no significant linear relationship between diindependent geologic variables such as coal rank or rect method in-situ gas content values and other easily reservoir depth.27,38,39 Plots of measured in-situ gas measured geologic variables such as vitrinite refleccontent values against vitrinite reflectance or reservoir tance, depth, and reservoir pressure. depth often exhibit apparent linear trends. However, Figure 1-4 is a graph of the variation of direct the empirical correlations derived from such data trends method in-situ gas content as a function of vitrinite generally have very little predictive utility since there reflectance for the data given in Table 1-1. In this graph, is no fundamental relationship between the dependent four wells exhibit an apparent linear trend of increasing and independent variables. Thus, the coefficients in the in-situ gas content with increasing vitrinite reflectance. empirical correlations are highly sample set specific However, the empirical correlation derived from this which biases their predictive accuracy. Indirect method in-situ gas content values can be apparent gas content-vitrinite reflectance relationship would have significantly over estimated the pressure core-deWell Vitrinite Direct Method Depth Pressure rived in-situ Reflectance Dry, Ash-Free gas content Gas Content value for the % Ro scf/ton feet psia Southern FC Federal #12 0.59 225 2,235 890 Ute Mobil 36-1 well. Valencia Canyon 32-1 0.76 623 1,910 913 Southern Ute 5-7 0.80 503 1,460 620 GRI COAL Site 0.90 913 3,180 1,550 Southern Ute Mobil 36-1 1.34 601 2,440 1,366

Table 1-1.

1.6

Fruitland Formation Coalbed Reservoir Property Data.

Analysis Type Basin Basin COAL Site Reservoir COAL Site Reservoir

Analysis Method Indirect Method Indirect Method Indirect Method Direct Method

Gas-In-Place 31 Tscf 50 Tscf 26.9 Bscf per Square Mile 60.3 Bscf per Square Mile

Reference 41 42 42 34

Table 1-2 Fruitland Formation Gas-In-Place Estimates

Coalbed reservoir gas content values can also vary dramatically among wells in close proximity to one another. For example, the Pottsville Formation, Mary Lee - Blue Creek Group coal recovered from corehole M-612 at the Gas Research Institute’s Big Indian Creek research site in the Black Warrior Basin, Alabama had an in-situ gas content of 431 cubic feet per ton in-place coal. However, the in-situ gas content of the reservoir coal samples collected at two adjacent coreholes were 3 to 17 times lower.40 Subsequent geologic analyses attributed the lower gas content values to a combination of paleotopography and paleoclimate factors which reduced the hydrostatic pressure within a localized area of this coalbed reservoir thereby allowing natural degasification of the coal to occur.40

Gas Resource Assessments In-place coalbed gas resource assessments are commonly based upon indirect method gas content values. Table 1-2 compares published in-place gas resource estimates for the Fruitland Formation coal in the San Juan Basin of Colorado and New Mexico.41,42 The indirect method in-place gas resource estimates differ by nearly a factor of two. The lower resource estimate (31 Tscf) was obtained using drill cuttings-derived gas content-depth correlations while the higher resource estimate (50 Tscf) was obtained using conventional core-derived gas content-depth correlations. By contrast, the direct method in-situ gas content of San Juan Basin Fruitland Formation coal recovered from a well at the Gas Research Institute’s COAL Site research location was 512.4 scf/ton or 110% greater than the 244 scf/ton value predicted by the indirect method gas content-depth correlation.34 A gas content error of this magnitude causes a very large error in the gas-in-place estimate which for the COAL site reservoir increases from 26.9 to 60.3 Bscf per square mile, a gain of 124%.

These comparisons demonstrate that empirical gas content-depth correlations used for conducting in-place gas resource assessments are not adequate for conducting reservoir gas-in-place analysis.

Additional Gas-InPlace Anaysis Other common sources of error in gas-in-place analysis are underestimation of the gross reservoir thickness and average reservoir rock density.36 Coal compositional properties and gas content are not uniform throughout the bulk rock comprising a coalbed reservoir but vary both vertically and laterally as a function of such geologic variables as coal rank, depth, ash content, and maceral composition. Analysis data from samples having a broad range of compositional values are needed for reliable determination of the gross reservoir thickness, average reservoir rock density and average in-situ gas content.26,36 Coal samples must also be carefully handled at the well site and during transport, storage and testing in order to preserve their original in-situ compositional properties.26,27,34 Air exposure, for example, results in time-dependent alteration of coal’s gas emission and compositional properties due to a progressive degradation phenomenon known as weathering.43 If freshly cut reservoir coal samples are sealed in desorption canisters with a large headspace air volume the subsequent chemical reaction between the oxygen in the air and the coal can cause a significant underestimation error in the desorbed gas volume.44 Clearly, obtaining accurate gas-in-place values for coalbed reservoirs involves numerous data collection and analysis challenges. The key requirement for obtaining accurate values for average in-situ gas content, gross reservoir thickness, and average reservoir rock density is the use of proper sampling, testing, and data analysis methods.26,27,28,34,35,36 The following chapters

1.7

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Gas-In-Place Analysis Overview

in this book provide a state-of-the-art technical reference of the procedures used for determining the gas-inplace volume of coalbed reservoirs. The emphasis is on providing practical information, guidelines, and procedures for analyzing coalbed reservoir property data. We have included insights into sources of error and the comparative accuracy of commonly used analysis methods rather than lengthy technical explanations of the theories behind these methods. Example problems and exercises are given throughout the text to promote practical understanding of the analysis methods and to facilitate independent, self-paced training by practicing petroleum geologists and reservoir engineers. The text in each chapter is supplemented by references identifying literature sources containing additional information.

Accuracy Benchmarking This book evolved from notes and data sets developed and used by the authors for reports, lectures, workshops, and Gas Research Institute sponsored training courses on the general topics of coalbed reservoir gas content and gas-in-place analysis. Most of the information and data in this book are the products of over a decade of basic coal science and field-based coalbed reservoir engineering research sponsored by the Gas Research Institute. We used this research information and data to systematically evaluate the accuracy and identify the major sources of errors associated with gas content and gas-in-place volume estimates. These evaluations differ from previous studies in three important ways. First, we rigorously established benchmark or “ground truth” values for the insitu gas content value of each reservoir. These benchmark values were determined using either pressure core-derived gas content data or adsorption isotherm data measured in pressure cells under in-situ reservoir conditions.26,28,34,35 Second, we used these benchmark gas content values as the reference basis for establishing the absolute accuracy and comparing the relative accuracy of different analysis methods.26,28,34,35,36 The full details of these analyses as well as the complete data sets used for these analyses have been published by the Gas Research Institute and are publicly accessible for examination and use by others. 26,28,34,35,36,45

1.8

Finally, the quantitative results and error source insights obtained from these evaluations formed the basis for the analysis procedure guidelines and recommendations given throughout the text of this book. Several coalbed gas producers and service laboratories have independently evaluated and documented the applicability and practical value of these analysis procedure guidelines and recommendations in basins throughout the United States and other countries throughout the world. The information in this book represents the current state of knowledge regarding what is clearly a very complex technical subject. It is anticipated that as additional research is conducted and new data become available, that further refinements and improvements in the methods used for coalbed reservoir gas-in-place analysis will occur. We anticipate that some of the readers of this book will contribute to making these refinements and improvements possible.

Chapter 1 References 1.

Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenbaas, J.R., and Weinaug, C.F.: Handbook of Natural Gas Engineering, McGraw-Hill, New York (1959) pp. 456-462.

2.

Ikoku, C.U.: Natural Gas Reservoir Engineering, John Wiley & Sons, New York (1984) 503 p.

3.

Price, L.C., Wenger, L.M., Ging, T., and Blount, C.W.: “Solubility of Crude Oil in Methane as a Function of Pressure and Temperature,” Organic Geochemistry, Vol. 4 (1983) pp. 201-221.

4.

McCain, W.D.: “Heavy Components Control Reservoir Fluid Behavior,” Journal of Petroleum Technology, Vol. 46 (September 1994) pp. 746-750.

5.

Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenbaas, J.R., and Weinaug, C.F.: Handbook of Natural Gas Engineering, McGraw-Hill, New York (1959) pp. 204-207.

6.

Price, L.C.: “Aqueous Solubility of Methane at Elevated Pressures and Temperatures,” American Association of Petroleum Geologists Bulletin, Vol. 63 (1979) pp. 1527-1533.

7.

Cox, J.L. (editor): Natural Gas Hydrates: Properties, Occurrence and Recovery, Butterworth, Boston, MA (1983) 125 p.

8.

Kvenvolden, K.A.: “A Primer on Gas Hydrates,” in Howell, D.G., et al. (editors), The Future of Energy Gases, U.S. Geological Survey Professional Paper 1570, United States Department of the Interior, Washington, D.C. (1993) pp. 279-291.

9.

Marsden, S.: “A Survey of Natural Gas Dissolved in Brine,” in Howell, D.G., et al. (editors), The Future of Energy Gases, U.S. Geological Survey Professional Paper 1570, United States Department of the Interior, Washington, D.C. (1993) pp. 383-387.

10. Rightmire, C.T.: “Coalbed Methane Resource,” in Rightmire, C.T., Eddy, G.E., and Kirr, J.N., (editors), Coalbed Methane Resources of the United States, American Association of Petroleum Geologists, Tulsa, Oklahoma (1984) pp. 1-13. 11. Tissot, B.P. and Welte D.H.: Petroleum Formation and Occurrence, Springer-Verlag, Berlin (1984) 699 p. 12. Jones, A.H., Bell, G.J., and Schraufnagel, R.A.: “A Review of the Physical and Mechanical Properties of Coal with Implications for Coal-Bed Methane Well Completion and Production,” in Fassett, J.E. (editor) Geology and Coal-Bed Methane Resources of the Northern San Juan Basin, Colorado and New Mexico, Rocky Mountain Association of Geologists, Denver, Colorado (1988) pp. 169-181. 13. Van der Sommen, J., Zwietering, P., Eillebrecht, J.M., and van Krevelen, D.W.: “Chemical Structure and Properties of Coal, XII - Sorption Capacity For Methane,” Fuel, Vol. 34 (1955) pp. 444-448. 14. Decker, A.D., Wicks, D.E., and Coates, J-M.: Gas Content Measurements and Log Based Correlations in the Antrim Shale, Gas Research Institute Topical Report No. GRI-93/0293, Chicago, Illinois (July 1993) 81 p. 15. Lu, X-C., Li, F-C., and Watson, A.T.: “Adsorption Measurements in Devonian Shales,” Fuel, Vol. 74 (1995) pp. 599-603. 16. Kelso, B.S., Lombardi, T.E., and Kuuskraa, J.A.: Drilling and Production Statistics for Major U.S. Coalbed Methane and Gas Shale Reservoirs: Gas Research Institute Topical Report No. GRI-96/0052, Chicago, Illinois (December 1995) 50 p.

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17. Jennings, G.L., Greaves, K.H. and Bereskin, S.R.: “Natural Gas Resource Potential of the Lewis Shale, San Juan Basin, New Mexico and Colorado,” Paper 9766, Proceedings of the 1997 International Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, Alabama (May 12-17, 1997) pp. 557-565. 18. Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenbaas, J.R., and Weinaug, C.F.: Handbook of Natural Gas Engineering, McGraw-Hill, New York (1959) p. 298. 19. Dugan, T.A. and Williams, B.L.: “History of Gas Produced from Coal Seams in the San Juan Basin,” in Fassett, J.E. (editor): Geology and Coal-Bed Methane Resources of the Northern San Juan Basin, Colorado and New Mexico, Rocky Mountain Association of Geologists, Denver, Colorado (1988) pp. 1-9. 20. Schraufnagel, R.A., Hill, D.G., and McBane, R.A.: “Coalbed Methane - A Decade of Success,” Paper SPE 28581, 69th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, New Orleans, Louisiana (September 25-28, 1994). 21. Schwochow, S. (editor): The International Coal Seam Gas Report, Cairn Point Publishing, Inc., Denver, Colorado (1997) p. 9. 22. Curtis, J.B.: “How Well Do We Know the Size of the U.S. Natural Gas Resource Base,” Journal of Petroleum Technology, Vol. 48 (1996) pp. 75-81. 23. Tyler, R., Kaiser, W.R., Scott, A.R., and Hamilton, D.S.: “Coalbed Gas Potential of the Greater Green River Basin, Southwest Wyoming and Northwest Colorado,” Paper 9502, Proceedings INTERGAS ’95, The University of Alabama/Tuscaloosa, Alabama (May 14-20, 1995) p. 23-38. 24. Rightmire, C.T., Eddy, G.E., and Kirr, J.N. (editors): Coalbed Methane Resources of the United States, AAPG Studies in Geology Series #17, American Association of Petroleum Geologists, Tulsa, Oklahoma (1984) 375 p. 25. Smith, T.N.: “Coalbed Methane Potential for Alaska and Drilling Results for the Upper Cook Inlet Basin,” Paper 9501, Proceedings INTERGAS ’95, The University of Alabama/Tuscaloosa, Alabama (May 14-20, 1995) p. 1-21. 26. Mavor, M.J., Pratt, T.J., and Nelson, C.R.: “Quantitative Evaluation of Coal Seam Gas Content Estimate Accuracy,” Paper SPE 29577, 1995 Joint Rocky Mountain Regional / Low-Permeability Reservoirs Symposium, Denver, Colorado (March 20-22, 1995). 27. McLennan, J.D., Schafer, P.S., and Pratt, T.J.: A Guide to Determining Coalbed Gas Content, Gas Research Institute Report No. GRI-94/0396, Chicago, Illinois (1995) 182 p. 28. Mavor, M.J., Pratt, T.J., and Nelson, C.R.: “Quantify the Accuracy of Coal Seam Gas Content,” Petroleum Engineer International, Vol. 68 (October 1995) pp. 37-42. 29. Bertard, C., Bruyet, B., and Gunther, J.: “Determination of Desorbable Gas Concentration of Coal (Direct Method),” International Journal of Rock Mechanics and Mining Science, Vol. 7 (1970) pp. 43-65. 30. Kissell, F.N., McCulloch, C.M., and Elder, C.H.: The Direct Method of Determining Methane Content of Coalbeds for Ventilation Design, Report of Investigations 7767, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1973) 17 p. 31. McCulloch, C.M., Levine, J.R., Kissell, F.N., and Deul, M.: Measuring the Methane Content of Bituminous Coalbeds, Report of Investigations 8043, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1975) 22 p.

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32. Diamond, W.P. and Levine, J.R.: Direct Method Determination of the Gas Content of Coal: Procedures and Results, Report of Investigations 8515, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1981) 36 p. 33. Close, J.C. and Erwin, T.M.: “Significance and Determination of Gas Content Data as Related to Coalbed Methane Reservoir Evaluation and Production Implications,” Paper 8922, Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, Alabama (April 17-20, 1989) pp. 37-55. 34. Mavor, M.J., Pratt, T.J., and Britton, R.N.: Improved Methodology for Determining Total Gas Content, Volume I. Canister Gas Desorption Data Summary, Gas Research Institute Topical Report No. GRI-93/ 0410, Chicago, Illinois (May 1994) 230 p. 35. Mavor, M.J. and Pratt, T.J.: Improved Methodology for Determining Total Gas Content, Volume II. Comparative Evaluation of the Accuracy of Gas-In-Place Estimates and Review of Lost Gas Models, Gas Research Institute Topical Report No. GRI-94/0429, Chicago, Illinois (March 1996) 167 p. 36. Mavor, M.J., Pratt, T.J., Nelson, C.R., and Casey, T.A.: “Improved Gas-In-Place Determination for Coal Gas Reservoirs,” Paper SPE 35623, Gas Technology Symposium, Calgary, Alberta, Canada (April 28 May 1, 1996). 37. Diamond, W.P., Bodden, W.R., III, Zuber, M.D., and Schraufnagel, R.A.: “Measuring the Extent of Coalbed Gas Drainage After 10 Years of Production at the Oak Grove Pattern, Alabama,” Paper 8961, Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, Alabama (April 17-20, 1989) pp. 185-193. 38. Kim, A.G.: Estimating Methane Content of Bituminous Coalbeds From Adsorption Data, Report of Investigations 8245, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1977) 22 p. 39. Hawkins, J.M., Schraufnagel, R.A., and Olszewski, A.J.: “Estimating Coalbed Gas Content and Sorption Isotherm Using Well Log Data,” Paper SPE 24905, 67th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Washington, D.C. (October 4-7, 1992). 40. Malone, P.G., Briscoe, F.H., Camp, B.S., and Boyer, C.M., II: “Discovery and Explanation of Low Gas Contents Encountered in Coalbeds at the GRI/USSC Big Indian Creek Site, Warrior Basin, Alabama,” Paper 8715, Proceedings of the 1987 Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, Alabama (November 16-19, 1987) pp. 185-193. 41. Choate, R., Lent, J., and Rightmire, C.T.: “Upper Cretaceous Geology, Coal, and the Potential for Methane Recovery from Coalbeds in San Juan Basin - Colorado and New Mexico,” in Rightmire, C.T., Eddy, G.E., and Kirr, J.N. (editors), Coalbed Methane Resources of the United States, American Association of Petroleum Geologists, Tulsa, Oklahoma (1984) pp. 185-222. 42. Kelso, B.S., Wicks, D.E., and Kuuskraa, V.A.: A Geologic Assessment of Natural Gas From Coal Seams in the Fruitland Formation, San Juan Basin, Gas Research Institute Topical Report No. GRI-87/0341, Chicago, Illinois (March 1988) 56 p. 43. Nelson, C.R. (editor), Chemistry of Coal Weathering, Elsevier Science Publishers, New York (1989) 230 p. 44. Ulery, J.P. and Hyman, D.M.: “The Modified Direct Method of Gas Content Determination: Applications and Results,” Paper 9163, Proceedings of the 1991 International Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, Alabama (May 13-16, 1991) pp. 489-500. 45. Mavor, M.J. and Pratt, T.J.: COREGAS Database,  Gas Research Institute, Chicago, Illinois (May 1994).

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2 Chapter

Gas-In-Place Methodology and Error Summary

Y

ou can make gas-in-place estimates with a simple equation with parameters including the drainage area, thickness, density, and gas content of a reservoir. Difficulties in application are due to errors in the parameters, not in the equation. We found that three essential items are required for accurate estimates, a geologic-engineering evaluation, measurement of core data, and measurement of open-hole density log data. Although you may need to adjust the methodology described in this book, we believe that you will still require these three essential items. Our gas-in-place methodology combines coal thickness and in-situ density data from well logs with multiple sample gas content estimates from core sample desorption measurements. Core measurements are required since currently available logging technology cannot quantify the volume of gas contained within the reservoirs. In this section, you will get an overview of the eight-step methodology developed by GRI. You will be acquainted with the details and examples of the eight steps later.

Gas-In-Place Relationship We define gas content for coalbed gas reservoirs as the in-situ gas volume per unit weight of rock. The unit weight of rock contains both organic and inorganic components within coal and other organic-bearing rock types. The gas volume is reported at standard pressure and temperature conditions. These vary but are often 60 oF and 14.696 psia. The gas-in-place estimate is dependent upon the bulk volume (areagross thickness product), the average in-situ density, and the average in-situ sorbed gas content in the reser-

voirs. Commercial gas production requires that sufficient gas-in-place is contained within minute pore spaces, and that natural fractures connect the gas-inplace to production wells. Discussion of natural fractures and flow to wells is outside the scope of this book. Refer to Reference 1 if you wish more information on these subjects. The gas-in-place equation is: (2-1)

G = 1359.7 Ahr Gc Where: G A h

= = = =

ρ

G c

gas-in-place volume, scf reservoir area, acres reservoir thickness, feet average in-situ rock density at the average insitu rock composition, g/cm3 = average gas content at the average in-situ rock composition, scf/ton

Example 2-1 illustrates application of Equation 21. You will usually apply this equation to individual reservoirs or coal seams in close vertical proximity that have similar characteristics. Sometimes, we will group reservoirs when they are of similar coal rank, sorptive capacity, and pressure. When you are interested in multiple reservoirs or groups, you sum the results of Equation 2-1 for each reservoir to obtain the total gasin-place volume.

2.1

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Gas-In-Place Methodology and Error Summary

Example 2-1. Gas-In-Place at the COAL Site READ ME

At the GRI COAL Site research location in the San Juan Basin, the Fruitland Formation coal gas reservoirs are contained in two primary intervals referred to as the basal and upper. Each of these intervals had multiple coal seams that we grouped together since the coal rank, gas storage capacity, and reservoir pressure were similar in each interval. The following table lists properties required for the gas-in-place estimates for each interval. The area that we were interested in was the square mile section in which the research site was located. Property

Units

Drainage area Thickness Average in-situ density Average gas content at the average rock composition Initial gas-in-place per square mile

acres feet g/cm 3 scf/ton Bscf

Upper Coal Interval Value 640 28.3 1.833 343.2 15.49

Basal Coal Interval Value 640 61.7 1.628 512.4 44.79

The total initial gas-in-place volume for both intervals was 60.28(109) scf or 60.28 Bscf (billion standard cubic feet) per square mile. The calculation is straight forward as performed below for the basal coal interval. G = 1,359.7 (640 )(61.7 )(1.628 )(512.4 ) = 4.479 10 10 scf or 44.79 Bscf

(

The combination of the drainage area and the thickness in Equation 2-1 is the bulk volume of the reservoir. The bulk volume usually contains coal (rock with an organic content greater than 70% by volume and greater than 50% by weight1 ), carbonaceous shale (containing organic material in which gas is sorbed) and rocks devoid of organic material. You will generally ignore the inorganic rock for gas-in-place estimates unless it contains producible gas. An analyst’s selection of the drainage area is often based on surface surveys, ownership limits, or the well spacing used to develop the reservoirs. More properly though, the area should be determined by a combination of geological, geophysical, and engineering methods. A discussion of these methods is outside the scope of this book. Examples of coal gas reservoir geologic evaluations are included in Reference 3 and 4. Reference 5 presents an example of the use of geophysical and reservoir simulation methods. GRI presented a summary of coal gas reservoir engineering and simulation technology that you can use.1 We will cover the methods we used to estimate the thickness from density logs. You may also need to estimate thickness from a combination of other wireline

2.2

)

and mud logs when a density log is not available. We need the in-situ density estimate to convert gas content on a volume per weight basis to a volume per volume basis. We will determine the in-situ density from open-hole density log data. We will use the density data to determine the depths of organic-bearing rocks from open-hole density data. Most gas content estimate methods involve placing freshly cut coal samples in airtight gas desorption canisters. The total gas content is the sum of three components, 1. the gas content lost prior to sealing the canister, 2. the measured gas content, and 3. the residual gas content remaining in the samples at the end of the measurements. The most common units for gas content are scf (standard cubic feet) per ton (2,000 lbm [pounds mass]) or g/cm3 (grams per cubic centimeter). One scf/ton is equal to 32.0368 g/cm3. We will estimate the total gas content by analysis of the gas volume released vs. time from core samples reheated to reservoir temperature. These data are ana-

Well Well Well lyzed to determine the lost gas volPermeability A B C ume. The samples are crushed at Facies Change the completion of desorption to determine the residual gas content. The gas content estimates from Channel multiple samples should be correSandstone Belt lated to the inorganic content of the samples to allow estimates of the Coal Pinch in-situ gas content. This procedure Out is superior to averaging the estimates from multiple samples. Fault Core data should be measured Offset to determine the density of the organic and inorganic portions of the samples. These data allow the gas content to be correlated with density. We have used the density correlations to show that the density Figure 2-1. range from which gas can be desCoal Gas Recovery Geometry. orbed includes both coal and carbonaceous shale. The gas-in-place in the carbonaceous shale intervals must be included gas reservoir geometry. The uncertainty or error in producible gas-in-place for accurate gas-in-place estimates. Once the gas content data is correlated to inorganic estimates caused by natural geologic variability can content and hence density, it is possible to estimate the be very significant. You should include a geologic in-situ gas content from the open-hole density data. The evaluation of the structural and stratigraphic changes in-situ gas content estimate is made at the average in- in reservoirs to obtain accurate estimates of the gassitu inorganic content to provide a single in-situ gas in-place and the gas that may be recovered by existing or infill wells. Unfortunately, the presence content estimate for use in the gas-in-place equation. of the discontinuities is often not apparent in the Gas-In-Place Estimate Errors geologic evaluation. The locations of discontinuities often cannot be determined until you identify Uncertainties or errors in each parameter included unusual patterns in gas and/or water production in Equation 2-1 limit the accuracy of coal gas-in-place behavior. volume estimates. These parameters are the drainage Three-dimensional seismic technology has been area, the thickness, the average in-situ density, and the used to improve estimates of drainage region extent in average in-situ gas content. coal gas reservoirs. In the San Juan Basin, estimates of Drainage Area Errors locations of rock discontinuities determined from seisGeologists and engineers usually estimate the res- mic interpretation were consistent with the locations of ervoir drainage area from ground level areas such as flow barriers required in reservoir simulation models.5 survey limits, ownership boundaries, or well spacing. This combination of reservoir simulation and seismic However, geologic structural and stratigraphic varia- technology may someday, routinely improve the identions disrupt the lateral continuity of coalbeds. These tification of discontinuities beyond that possible with disruptions complicate determination of the reservoir traditional geologic or production interpretation methdrainage area. Figure 2-1 illustrates a schematic of coal ods.

2.3

Chapter

2

Gas-In-Place Methodology and Error Summary

Gross Coal Thickness Errors The primary data source for determining the thickness of coalbeds is geophysical logs. Interpretation of open-hole density logs results in the most accurate estimates. Recognizing coal is often easy since the density of organic material is low compared to that of inorganic rocks.1 You will calculate the total reservoir thickness by summing the thickness of rocks whose density values are less than a maximum density limit. The most commonly used maximum density limit for coal is 1.75 g/cm3. This limit may have come from the geologic definition of coal2 that states that coal contains more that 70% by volume and 50% by weight carbonaceous material. This limit corresponds to densities less than or equal to 1.75 g/cm3. However, 1.75 g/ cm3 excludes the gas contained in carbonaceous shale intervals and may result in low estimates of the gross reservoir thickness and high estimates of the average in-situ gas content. A more correct upper density limit for Fruitland Formation coal gas reservoirs is 2.1 to 2.5 g/cm3. Use of the lower “rule of thumb” value results in gas-in-place estimates that are low by up to 22%. Average In-Situ Density Errors Many analysts assume that the product of 1,359.7 and the average density in Equation 2-1 is equal to a value of 1,800 or 1,850 tons per acre-foot based upon information contained in Reference 7. The average density corresponding to these values is 1.324 to 1.361 g/cm3. The correct in-situ density should be estimated from open-hole density log data. The average in-situ density of San Juan Basin, Fruitland Formation coal gas reservoirs is often 1.5 to 1.85 g/cm3. Use of the correct average density value results in gas-in-place estimates that are 10 to 13% greater than obtained with the “rule-of-thumb” value. Gas Content Errors One of the key components of the gas-in-place estimate is the gas content of the reservoirs. Errors in gas content estimates are the greatest source of error in gas-in-place estimates. The errors usually cause the gas-in-place estimates to be low. We quantified the errors with benchmark gas content values. By comparing gas content estimates obtained by different meth-

2.4

ods to the benchmark values, we determined that gas content estimates are accurate if our methodology is followed. We obtained the benchmark gas content values from pressure core samples and sorption isotherm data. Pressure coring equipment seals core samples downhole allowing all of the gas content to be trapped without loss before retrieving the samples to surface. We used sorption isotherm data for benchmarks in reservoirs that we knew had in-situ gas contents that were equal to the in-situ gas storage capacity. We measured all of the gas content data that we used to design the gas-in-place methodology during the Western Cretaceous Coal Seam Project of GRI.3 References 9 ,10 , and 11 document the details of the benchmarking and error analysis that we performed. Table 2-1 presents the comparison between the benchmark standards and gas content values. We had two sets of pressure core samples available; one from San Juan Basin, Fruitland Formation, reservoirs and one from Piceance Basin, Mesa Verde Group, reservoirs. The pressure core and Direct Method conventional core gas content estimates were within 7.2% for the Slant Hole Completion Test #1 well and 5.8% for the Southern Ute - Mobil 36-1 well. The agreement for both wells was important because gas is lost from conventional core samples while the samples are retrieved to surface. Pressure core samples do not suffer this limitation. The agreement for the Slant Hole Completion Test #1 was especially significant since the conventional and pressure core samples were retrieved from reservoirs at a true vertical depth of 7,000 feet. The agreement between the pressure and conventional core estimates supported that our methods of estimating the lost gas volume are correct. In addition, expensive pressure coring technology is not required for accurate gas-in-place estimates if core data are properly measured and interpreted. Pressure core data were not available from other wells. We turned to sorption isotherm data to provide additional benchmarks. We computed benchmarks for five wells with extended Langmuir isotherm theory that accounted for the sorbed gas composition that included methane and carbon dioxide. Five Direct Method core gas content estimates were within 1 to

Well

Benchmark Type

Gas Content % of Benchmark Value Slant Hole Completion Test #1 Pressure Core 92.8 Southern Ute Mobil 36-1 Pressure Core 105.8 GRI Observation Well #1 Methane-Carbon Dioxide Isotherm Data 99.7 GRI Observation Well #2 Methane-Carbon Dioxide Isotherm Data 99.6 Southern Ute 5-7 Methane-Carbon Dioxide Isotherm Data 103.1 Valencia Canyon 32-1 Methane-Carbon Dioxide Isotherm Data 109.0 FC Federal #12 Methane Isotherm Data 119.7 South Shale Ridge #11-15 Methane Isotherm Data 120.3 Table 2-1. Agreement Between Direct Method and Benchmark Gas Content.

10% of the isotherm benchmark values. We felt that this agreement provided additional support for the accuracy of our lost and total gas content analysis methods. The two wells with the greatest apparent error in the gas content estimates were the South Shale Ridge #11-15 and FC Federal #12 wells. Both gas content estimates appeared to be about 20% high. This may have been due to errors in the benchmark values rather than the gas content values. The benchmarks for both these wells were methane isotherms since the sorbed carbon dioxide content was believed low. However, had the carbon dioxide content been as small as 5%, the gas content and benchmark values would have been equal. We used the benchmark data to evaluate the accuracy of the methods used to estimate the lost gas content. We evaluated three commonly used methods. These are: • Direct (U.S. Bureau of Mines) Method,12 ,13,14 ,15 • Smith & Williams Method,16 ,17 and • Amoco Method.18 ,19 We found that the Direct Method was the most accurate when used to evaluate core desorption data from samples reheated to reservoir temperature. The estimates based upon the Smith & Williams Method tended to be low while those obtained with the Amoco Method were usually high. Figure 2-2 illustrates a comparison of the estimates obtained with the three methods for the eight wells listed in Table 2-1. The common industry practice is to measure gas desorption data from canisters stored at ambient tem-

perature. Lower ambient temperatures than reservoir temperatures caused large errors. Two temperature related factors affected the accuracy of lost and total gas content estimates. First, gas desorption rates varied exponentially with temperature which greatly affected the volume of gas desorbed during the portion of the measurements used to estimate the lost gas content. Second, the coal gas sorptive capacity was inversely proportional to temperature which increased the residual gas volume and reduced the measured gas volume. Desorption of San Juan Basin samples at ambient temperature conditions caused errors of -30 to -33% in the total gas content estimates and -60% to -70% errors in lost gas content estimates. San Juan Basin Fruitland Formation temperatures range from 100 oF to 125 oF. Ambient temperature conditions vary depending upon the time of year and can range from -15 oF to 100 oF. Many researchers ignored temperature effects when they desorbed samples from reservoirs at lower temperatures than those of the San Juan Basin. However, since temperature effects are exponential in nature, errors may be significant for lower reservoir temperatures as well. Reheating samples to reservoir temperature reduces errors in almost all cases. The type of sample also has a large effect upon gas content estimates. Conventional or wireline coring methods are the preferred method for sample collection. Less gas is lost from cores than from more commonly used drill cutting samples. The accuracy of gas content estimates from drill cuttings suffers from two limitations. The primary

2.5

Chapter

2

Gas-In-Place Methodology and Error Summary

Percentage of Direct Method Estimate

200 180

S&W Method Estimates

160

Amoco Method Estimates Direct Method: 100%

140 120 100 80 60 40 20

Southern Ute Mobil 36-1

Slant Hole Completion Test #1

FC Federal #12

Valencia Canyon 32-1

GRI Obs. Well #1

GRI Obs. Well #2

South Shale Ridge #11-15

Southern Ute 5-7

0

Figure 2-2. Comparison Between Direct and Other Total Gas Content Estimates shortcoming is that the samples are crushed downhole, resulting in high gas desorption rates and loss of a large fraction of the original gas content during sample recovery. Total gas content estimates from Fruitland Formation coal drill cuttings samples were 25% less than those obtained from conventional core samples when desorption was performed at similar temperatures. The common practices of drill cutting sample desorption at ambient temperature results in gas content estimates that are 50% low based upon our results. The second problem with drill-cutting samples is that rock debris from outside coal gas reservoirs often contaminates the samples. Differences in the density between the debris and reservoir rocks increased the inaccuracy in estimating the organic fraction and insitu gas content. We expected gas content estimates from drilled sidewall cores to be accurate due to short retrieval time. However, we found that the estimates were as inaccurate as those obtained from cuttings for our limited data set.

2.6

Another source of error in in-situ gas-in-place estimates results from basing the gas content on an incorrect mass. The variety of masses used to compute the sorbed gas content value confuses many people. Table 2-2 summarizes the most common bases. We are interested in three of these bases. We will begin by using the air-dry gas content basis to interpret data from multiple samples. We will extrapolate the air-dry data to an organic fraction basis. We will use the organic fraction basis gas content to estimate the in-situ basis gas content. The most important is the in-situ basis. This is the correct gas content basis to use for estimates of gas-in-place or other reservoir engineering calculations. The air-dry and organic fraction bases are intermediate values that we require in the analysis. People often ask why can’t we use the air-dry basis values. This is because desorption samples do not have the same average inorganic content as the reservoir due to natural variation and contamination by water and extraneous material.

Basis Name Gross Basis Raw Basis

1.75 g/cm3 Float Basis Air-Dry Basis

As-Received Basis Dry, Ash-Free Basis Dry, Mineral-Matter -Free Basis Moist, MineralMatter-Free Basis Organic Fraction Basis In-Situ Basis

Mass Description Desorption sample mass based upon the difference between the filled and empty canister mass. Desorption sample mass measured after removal from the canister including water a inorganic components. Extraneous water and material might be removed from the original sample before mass measurement. The mass of the portion of a crushed desorption sample that floats in a 1.75 g/cm3 density fluid. This mass basis incorrectly assumes that all gas originates from the 1.75 g/cm3 and less sample density range. Desorption sample mass after drying for 24 to 48 hours at laboratory conditions. Extraneous water and material are often removed from the original sample before mass measurement. Sample mass at the moisture content present when received by a laboratory. Air-dry or as-received sample mass corrected to 100% organic content with proximate analysis derived ash and moisture content. Air-dry or as-received sample mass corrected to 100% organic content with long proximate analysis derived ash, moisture, and sulfur content. Air-dry or as-received sample mass with the inorganic rock component removed to estimate coal rank using ASTM procedures based upon energy content data. Gas content estimate corrected to 100% organic content based upon statistical analysis of multiple coal samples. Organic fraction basis gas content estimate corrected to average in-situ ash content and moisture content conditions. Table 2-2. Summary of Common Gas Content Mass Bases

The dry, ash-free basis or the mineral-mineralmatter-free bases are useful for comparing gas content or storage capacity estimates obtained from samples of differing composition. We do not use these bases to estimate gas-in-place volumes. A mineral-matter-free basis can be used when the sulfur content of coal is significant. When sulfur is present, the proximate analysis underestimates the mineral-matter content. A 1928 publication by Parr1 recommends a correction that has become known as the “Parr Formula.” In the nomenclature used in this book, the conversion to a dry, mineral-matter-free basis mass can be performed with Equation 2-2. m = m [1- (1.08w +0.55w )] mf

ad

as

s

(2-2)

Where: mmmf mad was ws

= mineral-matter-free mass, g = air-dry mass, g = moist-basis ash content adjusted for sul fur content, weight fraction = sulfur trioxide content, weight fraction

There are two problems in the use of the Parr Formula. The first is that the correlation was developed in 1928 on a limited set of coal samples. The correction may not be applicable to the coals that you are evaluating. Secondly, the measurements required by the Parr Formula are not commonly performed and the data is often unavailable for the correction. The use of ash

2.7

Chapter

2

Gas-In-Place Methodology and Error Summary

content rather than the mineral-matter content results in the same estimate of the in-situ gas content and gasin-place volume unless sample sulfur content varies dramatically. We based the methods in this book on the ash content. Keep in mind that error may be introduced in high sulfur content coal when the sulfur content varies.

Eight-Step Evaluation Procedure We found that the methodology described in this book results in higher accuracy gas-in-place estimates that possible with other currently available methods. The gain in accuracy during GRI research efforts resulted from improved accuracy of four items. These were: • improved gas content estimates from core samples, • excellent agreement between ash content estimates from core and open-hole density log data,21 • high correlation between gas content estimates and inorganic content of multiple samples, and • including gas contained within both coal and carbonaceous shale in the gas-in-place estimates. The gas-in-place methodology relies upon four critical components. These are: • performing desorption measurements on multiple core samples at reservoir temperature, • relating sample gas content to sample composition and density, • estimating the in-situ composition and density from density log data, and • converting measured gas content estimates to insitu conditions. We recommend that you include these four components even if you wish to use a variation of the procedure recommended in this book. We found that an eightstep process minimized the errors in the gas-in-place estimates. If not properly followed, serious errors can result in gas-in-place estimates. These errors usually cause the estimates to be too low. Our eight-step procedure is as follows.

2.8

1. Perform gas desorption measurements at reservoir temperature on conventional or wireline-retrieved core samples. 2. Estimate the total gas content of each sample using the Direct Method lost gas content procedure. 3. Relate the total gas content of multiple samples to sample composition. 4. Relate the sample composition to density. 5. Determine the in-situ moisture content from lab moisture measurements. 6. Estimate the gross thickness and average in-situ density from open-hole density log data. 7. Compute the in-situ gas content at the average reservoir density and moisture content. 8. Compute the gas-in-place volume with Equation 2-1.

Summary Gas-in-place can be estimated from a simple equation based upon the drainage area, thickness, in-situ density, and in-situ gas content. Most of the gas-inplace is stored by sorption within micropores of the organic material. Direct measurements of the volume of gas released from coal samples is required to determine the gas-in-place as sorbed gas has almost no affect upon wireline log measurements. However, log data are still required. Significant errors are introduced in the gas-inplace estimate due to errors in each of the four components of the gas-in-place equation. Estimates of the drainage area require evaluation by geologists and engineers. The thickness is best estimated from openhole density log data. The selection of gas-bearing intervals must be based upon a density range that includes both coal and carbonaceous shales in which gas is stored. The in-situ density should be estimated from density log data. The greatest errors are usually in the gas content estimates that tend to be low. The selections of sample type, measurement conditions,

and analysis procedures all affect the gas content estimate. The most accurate estimates are obtained from core samples that are reheated to reservoir temperature and evaluated with the Direct Method lost gas procedure. The accuracy of the gas content methodology was determined by comparison of gas content estimates to benchmark values. The most accurate gas-in-place estimates are obtained by following an eight step procedure that includes measurement and interpretation of both core and log data. While your application of the procedure may differ from that presented in this book, you should include three essential items: 1) a geologic and engineering evaluation, 2) measurement of core data, and 3) measurement of open-hole density log data.

Additional Reading GRI publications9,10 and SPE papers11,22 present the details of much of the material discussed in this section. GRI summarized details on gas content measurements and measurement procedures in Reference 23.

2.9

Chapter

2

Gas-In-Place Methodology and Error Summary

Chapter 2 References 1. Saulsberry, J.L., Schafer, P.S., and Schraufnagel, R.A. (Editors): A Guide to Coalbed Methane Reservoir Engineering, Gas Research Institute Report GRI-94/0397, Chicago, Illinois (March 1996) 346 p. 2. Bates, J.L. and Jackson, J.A.: Glossary of Geology, 2nd Edition, American Geological Institute, Falls Church, Virginia (1980) p. 120. 3. Ambrose, W.A. and Ayers, W.B., Jr.: “Geologic Controls on Coalbed Methane Occurrence and Producibility in the Fruitland Formation, Cedar Hill Field and COAL Site, San Juan Basin, Colorado and New Mexico,” in Schwochow, S.D., Murray, D.K., and Fahy, M.F. (editors), Coalbed Methane of Western North America, Rocky Mountain Association of Geologists, Denver, Colorado (1991) pp. 227-240. 4. Tyler, R., Scott, A.R., Kaiser, W.R., Nance, H.S., McMurry, R.G., Tremain, C.M., and Mavor, M.J.: Geologic and Hydrologic Controls Critical to Coalbed Methane Producibility and Resource Assessment: Williams Fork Formation, Piceance Basin, Northwest Colorado, GRI Report GRI-95/0532, Chicago, Illinois (February 1996) 398 p. 5. Heim, R.M. and van Kirk, C.W.: “Integration Resolves Faulting Effects,” The American Oil & Gas Reporter (September 1996) pp. 121-127. 6. Mavor, M.J.: “Coalbed Methane Reservoir Properties” in A Guide to Coalbed Methane Reservoir Engineering, Saulsberry, J.L., Schafer, P.S., and Schraufnagel, R.A. (Editors), Gas Research Institute Report GRI-94/ 0397, Chicago, Illinois (1996) pp. 4-20 to 4-26. 7. Averitt, P.: Coal Resources of the United States, United States Geological Survey Bulletin No. 1412 (1975) 131 p. 8. Logan, T.L. and Mavor, M.J.: Western Cretaceous Coal Seam Project, Gas Research Institute Final Report No. GRI-94/0089, Chicago, Illinois (March 1995) 155 p. 9. Mavor, M.J., Pratt, T.J., and Britton, R.N.: Improved Methodology for Determining Total Gas Content, Volume I. Canister Gas Desorption Data Summary, Gas Research Institute Report No. GRI-93/0410, Chicago, Illinois (May 1994) 230 p. 10. Mavor, M.J., and Pratt, T.J.: Improved Methodology for Determining Total Gas Content, Volume II. Comparative Evaluation of the Accuracy of Gas-In-Place Estimates and Review of Lost Gas Models, Gas Research Institute Report No. GRI-94/0429, Chicago, Illinois (March 1996) 167 p. 11. Mavor, M.J., Pratt, T.J., and Nelson, C.R.: “Quantitative Evaluation of Coal Seam Gas Content Estimate Accuracy,” Paper SPE 29577, 1995 Joint Rocky Mountain Regional / Low-Permeability Reservoirs Symposium, Denver, Colorado, March 20-22, 1995. 12. Bertard, C., Bruyet, B., and Gunther, J.: “Determination of Desorbable Gas Concentration of Coal (Direct Method),” International Journal of Rock Mechanics and Mining Science, Vol. 7 (1970) pp. 43-65. 13. Diamond, W.P. and Levine, J.R.: Direct Method Determination of the Gas Content of Coal: Procedures and Results, Report of Investigations 8515, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1981) 36 p. 14. Kissell, F.N., McCulloch, C.M., and Elder, C.H.: “The Direct Method of Determining Methane Content of Coalbeds for Ventilation Design,” Report of Investigations 7767, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1973) 17 p.

2.10

15. Ulery, J.P. and Hyman, D.M.: “The Modified Direct Method of Gas Content Determination: Applications and Results,” Paper 9163, Proceedings of the 1991 International Coalbed Methane Symposium, The University of Alabama / Tuscaloosa, Alabama (May 13-17, 1991) pp. 489-500. 16. Smith, D.M., and Williams, F.L.: “A New Technique for Determining the Methane Content of Coal,” Proceedings of the 16th Intersociety Energy Conservation Engineering Conference, Atlanta, Georgia, (1981) pp. 1,167-1,272. 17. Smith, D.M., Methane Diffusion and Desorption in Coal, Dissertation Submitted in Partial Fulfillment of the Requirements for the Degree of Doctor of Philosophy in Chemical Engineering, The University of New Mexico, Albuquerque, New Mexico (May 1982) 172 p. 18. Metcalfe, R.S., Yee, D., Seidle, J., and Puri, R.: “Review of Research Efforts in Coalbed Methane Recovery,” Paper SPE 23025, SPE Asia-Pacific Conference, Perth, Western Australia (November 4-7, 1991). 19. Yee, D., Seidle, J.P., and Hanson, W.B.: “Gas Sorption on Coal and Measurement of Gas Content,” in Law, B.E. and Rice, D.D. (editors): Hydrocarbons from Coal, AAPG Studies in Geology #38, American Association of Petroleum Geologists, Tulsa, Oklahoma (1993) pp. 203-218. 20. Parr, S.W.: The Classification of Coal, Bulletin No. 180, Engineering Experiment Station, University of Illinois (1928). Also in 1994 Annual Book of ASTM Standards, Section 5, Volume 05.05 Gaseous Fuels; Coal and Coke, American Society for Testing and Materials Philadelphia, Pennsylvania (1994) p. 171. 21. Mavor, M.J., Close, J.C., and McBane, R.A.: “Formation Evaluation of Exploration Coalbed Methane Wells,” Coalbed Methane, SPE Reprint Series No. 35, Society of Petroleum Engineers, Richardson, Texas (1992). pp. 27-45. also in SPE Formation Evaluation (December 1994) pp. 285-294. 22. Mavor, M.J., Pratt, T.J. Nelson, C.R., and Casey, T.A.: “Improved Gas-In-Place Estimates for Coal Gas Reservoirs,” SPE 35623, Gas Technology Symposium, Calgary, Alberta, Canada (April 28-May 1, 1996). 23. McLennan, J.D., Schafer, P.S., and Pratt, T.J.: A Guide to Determining Coalbed Gas Content, Gas Research Institute Report No. GRI-94/0396, Chicago, Illinois (1995) 182 p.

2.11

3 Chapter

G

Coal Sample Gas Content Evaluation

as-in-place estimates for conventional reservoirs are usually based upon estimates of the rock porosity and the gas saturation within the porosity. Evaluation of open-hole porosity and resistivity log data provides these estimates. Coal gas reservoir gas-in-place cannot be determined from open-hole log data alone. The sorbed gas has little affect upon log measurements. For example, an in-situ methane content of 400 scf/ ton increases the density of organic matter with a density of 1.295 g/cm3 by 0.010 g/cm3 or 0.8%. You must base gas-in-place estimates upon core measurements combined with log interpretation. Once core data are

Step 1 2 3 4 5 6 7 8 9 10 11 12 13

available, you can reduce the need for core measurements by developing correlations between core and log measurements. In this chapter, you will be introduced to the procedures for gas desorption measurements and the methods for interpreting the data. We will cover the first two steps of the gas-in-place estimate procedure in detail. These steps are: 1. Perform gas desorption measurements at reservoir temperature on conventional core samples. 2. Estimate the total gas content of each sample using the Direct Method lost gas content procedure.

Description Cut coal core samples into one-foot lengths. Insert the sample into a plastic sleeve. Place the sleeved sample into a desorption canister of known weight. Weigh the filled canister. Place the filled canister in a water bath maintained at reservoir temperature. Periodically measure and record the desorbed gas volume as a function of time. Measure and record the ambient temperature, ambient pressure, and canister or water bath temperature at the time of the volume measurement. Stop the measurements when desorbed gas volumes are less than 10 cm 3 per day for five consecutive days. Remove the sample from the canister and the plastic sleeve. Separate extraneous material from the sample. Dry the sample at room conditions for 24 to 48 hours. Reweigh the sample. Obtain a representative sample split and perform proximate analysis.

Table 3-1. Summary of the Core Desorption Procedure

3.1

Chapter

3

Coal Sample Gas Content Evaluation

Desorption Measurement Procedure There are a great many details for the acquisition of coal samples from wells and in performing the desorption experiments. Refer to Reference 1 for the details of the methods that we found to be accurate. Table 3-1 includes a summary of the measurement procedures for core samples. The procedure for drill cutting and sidewall core samples is similar with the exception that Step 1 is unnecessary. We cored reservoirs with conventional PVC or fiberglass-lined core barrels. We removed the inner core barrel from the coring equipment as soon as possible after reaching the surface. We then laid the inner core barrel on the catwalk below the drill floor and removed, inspected, and measured the entire core. Once we completed measurements, we cut the core samples with rock saws. We cut the samples into onefoot lengths to develop relationships between gas content and inorganic content, to minimize the effects of canister failures, and to increase the statistical reliability of the experimental results. We then slid the samples into plastic sleeves and sealed the samples in desorption canisters of known weight. We moved the canisters as fast as possible to an on-site laboratory. In the on-site laboratory, we weighed the filled canisters and then placed them in water baths regulated at reservoir temperature. We placed core samples in plastic sleeves for four reasons. First, the sleeves preserved the core integrity. Laboratory flow experiments and other whole core analyses required competent samples. Second, the sleeve reduced chemical reactions between the sample and the canister. Third, we could handle the samples easier. Fourth, we preserved the properties of the sample (weight, moisture, and ash content) by heat sealing the plastic sleeve when we pulled the samples from the canisters. We constructed desorption canisters from aluminum. Some service companies use PVC pipe that is prone to leakage. Figure 3-1 illustrates a schematic of one of the desorption canisters we used for core and cutting samples. You seal the canister by moving the cam lock arms upward. We measured the gas volume by displacing water from graduated burettes. The burettes were at ambient

3.2

Hose Barb Canister Exhaust Valve (Needle Valve)

0-30 psig Gauge

Lid Locking Assembly

O-Ring (inside canister lid) Cam Lock Assembly Top Flange (continuous weld)

Handle/Stabilizer

14 inches

Bottom Flange (continuous weld)

4 inches

Canister Outer Diameter

Figure 3-1. Desorption Canister Schematic pressure and temperature conditions. Figure 3-2 illustrates the device that we used during the GRI Western Cretaceous Coal Seam Project. Experienced personnel use this equipment quickly and accurately. We began gas desorption measurements as soon as we placed the canisters in a water bath. The delivery tube of one of the burettes was connected to the hose barb on the top of the canister. The gas escaped from the canister and displaced water from one of the burettes. We adjusted the height of the fluid reservoir so that the water level in the burette and the fluid reservoir were equal, eliminating the hydrostatic head of the displaced water. We then read and recorded the gas volume in the burette.

residual gas content was negligible for reservoir temperature desorption measurements. This may not be true for coal samples from other reservoirs. Were commend that you select at least three samples of widely differing inorganic content for the residual gas measurements. You must estimate the inorganic content visually since the proximate analysis data will not be available when you select the samples. We commonly selected samples that were partially rubblized to ease crushing. We split competent samples in half longitudinally. One half was saved for other purposes. We placed the other half Barometer in a mill containing steel balls and crushed it by spinning the mill on rollFunnel ers. Complete crushing took from minutes to hours. We reheated the Fluid Reservoir mill to the same temperature at which the desorption measurements 250 cm3 Burette were performed before (graduation: 1 cm3) releasing the residual gas. The volume was corrected in the same manner as for the des1000 cm3 Burette orption measurements. 3 (graduation: 5 cm ) The residual gas content was based upon the corrected volume divided Vacuum Pump by the air-dried mass of the crushed sample. Gas composition samples should be collected and analyzed as for desorption canisters. Once desorption is complete, a proximate analysis Protective Carrying Case should be performed on a representative sample split. Reference 1 provides additional details Figure 3-2. for these procedures. Gas Volume Measurement Apparatus

Residual Gas Content The residual gas content is determined by crushing all or a portion of the sample at the end of the desorption measurements. Generally, it is not necessary to crush all samples. We found that residual gas content can be a significant portion (12.6% to 15.8%) of the total gas content for some ambient temperature desorption measurements.2 In the San Juan (Fruitland Formation) and Piceance Basins (Mesaverde Group), we found that

Delivery Tube (sidewall core) Meniscus Sighting Tube

50cm3 Burette (graduation: 0.1 cm3)

Thermometer

Delivery Tube (conventional core)

Stopcock

3.3

Chapter

3

Coal Sample Gas Content Evaluation

Gas Composition Measurements Gas produced from coal seams often contains significant volumes of components other than methane. These components affect the value of the resource and the storage capacity. You should determine the composition of the desorbed gas to estimate the in-situ composition. Gas samples should be collected from two or more desorption canisters with samples from each reservoir interval. At least four gas samples from each canister are required throughout the desorption history. Reference 1 provides additional details for gas sampling. Sample Composition When we discuss the composition of a sample, it is important to keep in mind the heterogeneity of coal seams. We will find significant variations within coal seams regardless of the scale. For example, Figure 3-3 illustrates coal at four different scales, an open-hole log scale (tens of feet), an outcrop scale (eight feet), a desorption sample size scale (seven inches), and a microscopic scale (700 microns). A high degree of interbedding within the Fruitland Formation coal gas reservoirs results in gas production from coal, coaly shale, and carbonaceous shale. The presence of multiple rock types increases the rock thickness contributing to production. Proper evaluation of the gas-in-place that will ultimately contribute to production must include the gas contained within all rock types. Interbedding is visible from all size scales. Interbedding places low and high permeability rocks of varying gas and organic content in close vertical proximity. Gas contained within the organic material need travel only short distances to natural fractures. The gas then travels through fractures to reach wells. The natural fractures will serve as pathways as long as they are open and unplugged. The entire gross thickness that contains organic matter is capable of gas production as long as organic intervals are not isolated from intervals connected to wells. We supported this conclusion during GRI research efforts with production log data.3 Desorption samples are also interbedded. Even one sample has a significant variation in organic content and gas content. The organic content determined by

3.4

proximate analysis of a representative split is an average value. For example, a one-foot sample containing 80% inorganic material often contains thin gas-rich organic layers interbedded with inorganic rock of negligible gas content. It is unusual to observe a one-foot thick, low organic content Fruitland Formation sample that has a uniform organic distribution. As an example, Figure 3-3c is an x-ray radiograph of a 0.5-inch thick, 7-inch high polished Fruitland Formation core slice. The “Gray Level Density Profile” is a relative density indicator. Vertical heterogeneity is apparent both visually and in the density image. Natural fractures are evident in the radiograph due to carbonate mineralization. Also apparent is the transition from an organic-rich matrix to carbonaceous shale that contains detrital fragments of coal. The variation observed in the density profile closely resembles the variation observed on a much larger scale in open-hole density logs (Figure 3-3a). Flow toward wells begins at the microscopic scale (Figure 3-3d) by diffusion through microfractures and micropores into the natural fractures that you can see in the desorption sample (Figure 3-3c). Concentration gradients drive diffusion. Flow through the natural fractures occurs within the fractured, organic rich layers of Figures 3-3 a, b, and c to wells. Pressure gradients drive flow through natural fractures.

Proximate Analysis We will use a proximate analysis to obtain one number that is representative of the average composition of a desorption sample. Proximate analysis is a coal analysis technique with procedures specified in detail by the ASTM Standards.1 The proximate analysis consists of three separate laboratory procedures designed to separately determine the moisture, volatile matter, and ash fractions in the sample. The remaining fraction is assumed to be fixed carbon so that the total of the four components sums to one. Samples are dried and crushed during preparation. The sample preparation procedure is as follows. A mass of partially crushed coal much larger than the experimental sample mass is spread in pans and allowed to dry in a drying oven maintained at atmospheric pressure and a temperature that is 18 to 27 oF

Depth

Density g/cm3

feet 1.0

2.0

3.0

1,300 1,310

Coal Shale Coal Tonstein Coal

1,320 1,330 1,340 1,350 1,360 1,370

b. Outcrop Photograph

Coal Intervals Indicated by Shading

a. Open-Hole Density Log Tonstein

Bright Clarain

Vitrain lens

Fracture Mineralization (Calcite) Carbonaceous Shale Vitrain lenses

Coaly Shale

X-Ray Radiograph c. X-Ray Radiograph

Gray Level Density Profile d. Photomicrograph

Figure 3-3. Size Scale Dependent Heterogeneity of Coal Seams

3.5

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3

Coal Sample Gas Content Evaluation

above room temperature. If a drying oven is not available, the sample is dried at laboratory conditions. Drying continues until the reduction in weight due to moisture evaporation is less than 0.1% per hour. The gross sample or a portion thereof is crushed to pass through a No. 8 (2.36 mm opening size) screen. A portion of the crushed sample is selected and crushed further so that it will pass through a No. 60 (250 µm opening size) screen. The moisture content analysis procedure is as follows. A covered porcelain capsule (22 mm in depth by 44 mm in diameter) is weighed after one gram of an airdried, crushed sample is placed in the capsule. Weight measurements are to the nearest 0.1 mg. The cover is removed and the capsule containing the sample is placed in a preheated (104 to 110o C.) oven. The sample remains in the oven for one hour. Pre-dried air is circulated through the oven at a rate that is 2 to 4 times the oven volume per minute. The capsule is removed from the oven and allowed to cool in a desiccator over a desiccant. The capsule and sample are weighed to the nearest 0.1 mg. Moisture content is determined as the percentage loss in weight during the experiment. The sample used to determine the moisture content is then used to determine the ash content. Ash is the residue remaining after burning coal and coke. Ash differs in composition from the inorganic constituents present in the original coal sample. Incineration causes an expulsion of all water, the loss of carbon dioxide from carbonates, the conversion of iron pyrites into ferric oxide, as well as other chemical reactions. The ash content measurement procedure is as follows. The capsule and the sample contained therein are placed in a cold muffle furnace and heated gradually at a rate such that the furnace reaches 450 to 500o C. in one hour. Heating is continued so that a temperature of 700 to 750o C. is reached at the end of the second hour. The temperature is maintained between 700 and 750o C. until the sample is completely ashed. The capsule and sample are removed from the oven and allowed to cool in a desiccator over a desiccant. The capsule and sample are weighed to the nearest 0.1 mg. Ash content (dry basis) is determined as the percentage of the remaining weight relative to the dried weight.

3.6

The volatile matter is determined from the loss in weight resulting from heating a coal sample under rigidly controlled conditions. The value is used to establish the rank of coal, to indicate coke yield during carbonization processes, to provide a basis for purchasing or selling coal, or to establish coal burning characteristics. The sample is selected from the same sample from which the moisture and ash content samples was selected. The volatile matter measurement procedure is as follows. A one gram sample contained within a sealed platinum crucible is placed in a vertical electric tube furnace that is precisely maintained at 950o C. The crucible and sample are heated for exactly 7 minutes. The crucible and sample are removed from the oven and allowed to cool in a desiccator over a desiccant. The crucible and sample are weighed to the nearest 0.1 mg. The loss of weight divided by the sample mass minus the moisture content equals the volatile matter content. Core sample air-dry gas content estimates can be correlated to the results of these three measurements as we will discuss in Chapter 4.

Ultimate Analysis An ultimate analysis5 is used to determine the composition of the organic fraction of a sample. This analysis results in estimates of the carbon, hydrogen, nitrogen, sulfur, and oxygen content. The total is assumed to be one. The content of the first four elements are measured. Oxygen is determined by difference. We will use these data to estimate organic fraction density from a correlation discussed in Chapter 4. The sample for the ultimate analysis is selected from the same air-dried sample as used for the proximate analysis. An ultimate analysis consists of three separate experiments. The first experiment determines the carbon and hydrogen content, the second determines the sulfur content, and the third determines the nitrogen content. The carbon and hydrogen content apparatus consists of a combustion tube that is connected to an absorption train both of which are placed in a furnace heated to between 850 and 900 oC. A sample is placed

in the furnace for 20 minutes. The sample is vaporized and the carbon and hydrogen contents are computed from the increase in weight of carbon and hydrogen adsorbers. The sulfur content is determined by one of two methods. Both sulfur determination methods are based upon combustion of a weighed sample. During the first method, combustion is performed at 800o C in a muffle furnace for one hour or over a flame for 30 minutes. The sulfur is removed from the residual material by dissolution in water followed by precipitation. The second method precipitates sulfur from residual oxygen-bomb calorimeter material. The weight of sulfur relative to the original weight is equal to the fraction of sulfur contained in the original sample. Nitrogen content is determined by one of two procedures. In both procedures, a one gram sample is digested with a hot catalyzed mixture of concentrated sulfuric acid and potassium sulfate that converts nitrogenous compounds to ammonium salts. The salts are then decomposed in a hot alkaline solution, releasing the ammonia, which is then distilled into a sulfuric or boric acid solution. The nitrogen concentration is determined by alkalimetric or acidimetric titration. The fraction of nitrogen present in the original sample is computed from the concentration.

Desorption Data Requirements The following information is recorded at each point in time during the desorption measurements. • • • •

Raw desorbed gas volume Water bath temperature or internal canister temperature Atmospheric temperature Atmospheric pressure

Table 3-2 illustrates a typical data record. The data items with a white background are recorded data. Those with a shaded background are computed. The raw desorbed gas volume is equal to the volume of water displaced from the burette by the gas. This volume requires corrections that we will discuss shortly. We usually included one canister in each fivecanister water bath that was equipped with an internal

temperature probe to monitor the internal canister temperature. The internal canister temperature was assumed to be the same for each canister in the same bath. We found that the internal canister temperature was roughly equal to the water bath temperature when we used aluminum canisters. Therefore, when temperature probe data were unavailable, we recorded the water bath temperature. We measured the atmospheric pressure and temperature as these affect the measured desorption volume. We required supplementary information to properly evaluate the desorption data. The well information section identified the well location. The core run information summarizes the cored formation, the core run number, the depth of the sample, and the density of the coring fluid. The reservoir information summarizes the name of the reservoir as well as the reservoir pressure and temperature conditions. We recorded the pressure gradient rather than the pressure so that we could quickly calculate the reservoir pressure at the sample depth. The canister information identified the canister and its empty volume and weight. The filled canister was weighed after sealing and before placing it in a water bath. The apparent sample weight was the difference between the filled and empty canister weight. The apparent weight was always greater than the air-dry weight due to water evaporation and removal of extraneous material from the sample. The headspace volume was the void volume inside the canister. This volume was determined at the conclusion of the desorption measurements. We measured the headspace volume by expansion of an inert gas (such as argon) from a cylinder of known volume into the canister containing the sample. We computed the headspace volume with the ideal gas law based upon the initial and final pressures in the empty cylinder. You should assign a unique identification number to each sample. This number is different from the canister ID since the canisters are used on more than one well. The sample data are measured at the conclusion of the desorption measurements. The sample was removed from the canister and allowed to dry at atmo-

3.7

Chapter

3

Coal Sample Gas Content Evaluation

spheric pressure and temperature for 24 to 48 hours. Extraneous materials such as drilling mud, lost-circulation material, or free water were often brushed from the sample. The sample was then weighed to determine the air-dry mass. The sample volume was the difference between the empty canister volume and the headspace volume. The most difficult step in the evaluation was to obtain a representative sample split for the ash and moisture content analyses. ASTM presents a strict methodology for sampling6 . We typically split the core along the longitudinal axis. One half of the core was crushed and sampled. We sealed the samples in plastic bags and shipped them to a coal analysis laboratory. The laboratory performed the analysis and provided us with the ash and moisture content values. We asked the laboratory to follow ASTM standards as closely as possible. A proximate analysis includes ash, moisture, and volatile matter measurements. We did not need volatile matter data for each sample since they were not required to determine the in-situ gas content. However, we had volatile matter measured for sorption isotherm samples or when we required coal rank and organic composition data as a function of depth. The recovery time section was required to evaluate the data for lost gas content estimates. We will explain how to use this information shortly. We recorded the time when the bit penetrated the depth of the core sample, since this was when the sample was exposed to the coring fluid pressure and temperature. Gas desorption may have begun at this time if the hydrostatic head of the coring fluid was less than the reservoir pressure. Usually, the hydrostatic head of the coring fluid was greater than the reservoir pressure. We recorded the time at which the driller began pulling the drill string and core barrel out of the well. Gas desorption began when the sample reached a depth at which the hydrostatic head was equal to the critical desorption pressure at the sample temperature. The sample temperature was often lower than the reservoir temperature at this time. We recorded the time at which the core barrel reached surface. The pressure surrounding the sample after this time was equal to the atmospheric pressure.

3.8

We also recorded the time at which we sealed the sample in a canister. Gas was no longer lost from the sample once sealed.

Desorption Data Correction The raw gas desorption volume data require correction for two effects. The first effect is expansion or contraction of the gas within the canister void volume. This correction is important when the temperature or pressure of the canister is changed. The correction is greatest for the first point because of heating the canister from ambient to reservoir temperature conditions. The second correction adjusts the gas volume from ambient temperature and pressure conditions to standard conditions at which gas volumes are reported. The two corrections are calculated with Equation 3-1 for a measured point at time i, the time of interest. (3-1) v = C (v - v ) sci

sci

i

hi

Where: vsci standard condition desorption volume at time i, cm3 Csci standard condition correction factor at time i, dimensionless vi measured desorption volume at time i, cm3 vhi headspace correction at time i, cm3 The standard condition correction factor at time i is defined by Equation 3-2. (3-2) p (T + 459.69 ) C sci = ai sc p sc (Tai + 459.69 ) Where: Tsc pai Tai psc

temperature at standard conditions, oF. atmospheric pressure at time i, inches Hg ambient temperature at time i, oF. pressure at standard conditions, inches Hg

The headspace correction factor includes two components. The first component corrects the canister gas volume for changes from the preceding internal canister conditions (time i-1) to the current canister conditions (time i). The second component corrects the gas expansion volume to the measurement conditions.

Canister Data Well Identification GRI Observation Well #2 Well Name Canister No. 14-29 Operator Amoco Production Co. Empty Weight g 4,135 County La Plata County Filled Weight g 5,915 State Colorado Empty Volume cc 3,035 Section S. 17, T32N, R11W cc 1,143 Headspace Volume Field Sample Data Ignacio Blanco 36-7 Core Run Identification Sample ID No. Formation Fruitland Air-Dry Weight g 1,698 Coal Interval Basal Sample Volume cc 1,892 Core Run # 1 Ash Content fraction 0.2481 Sample Top Depth feet 3,163.0 Moisture Content fraction 0.1141 Sample Bottom Depth feet 3,164.0 Residual Gas Content scf/ton 0.00 Coring Fluid Density ppg 10.5 Misc. Information Pressure at standard conditions: 30.01 in Hg Reservoir Data Temperature Deg. F 120 Temperature at standard conditions: 60 Deg. F. Pressure Gradient psi/ft 0.479 Interpretation Parameters Reservoir Pressure psia 1,526.87 Recovery Times 01/17/91 04:10:00 Time when the top of the sample was cored Fluid Hydrostatic Pressure psia 1,738.83 01/17/91 07:10:00 Time when the core barrel started out of the well Temp. Recovery Time hours 2.583 01/17/91 09:25:00 Des. Time Correction Time when the core barrel reached surface hours 0.467 01/17/91 09:45:00 End of Temp. Recovery Time when the sample canister was sealed hours*0.5 2.103 01/17/91 07:26:34 Start of Regression Time at time zero hours*0.5 2.200 Time at measurement start End of Regression hours*0.5 2.400 01/17/91 10:13:00 Time Uncorrected Data Measurement Conditions Corrected Data Date & Time Desorption Square Root Incremental Desorbed Canister Ambient Ambient Cumulative Cumulative Time of Desorbed Volume Temperature Temperature Pressure Desorbed Desorbed Desorption Volume Volume Gas Content Time mm/dd/yy hh:mm:ss hours hours*0.5 cc cc Deg. F Deg. F Inches Hg cc @ STP scf/ton 01/17/91 09:45:00 1.841 1.357 0 0 40 40 23.59 0 0 01/17/91 10:13:00 2.307 1.519 760 760 120 75 23.59 452 8.52 01/17/91 10:24:00 2.491 1.578 395 1,155 120 75 23.59 753 14.22 01/17/91 10:29:00 2.574 1.604 220 1,375 120 75 23.59 922 17.39 01/17/91 10:37:00 2.707 1.645 310 1,685 120 75 23.59 1,158 21.86 01/17/91 10:45:00 2.841 1.685 310 1,995 120 75 23.59 1,395 26.32 01/17/91 10:58:00 3.057 1.748 520 2,515 120 75 23.59 1,793 33.82 01/17/91 11:32:00 3.624 1.904 1,545 4,060 120 75 23.55 2,970 56.03 01/17/91 11:52:00 3.957 1.989 825 4,885 122 75 23.53 3,595 67.83 01/17/91 12:37:00 4.707 2.170 1,825 6,710 122 75 23.53 4,986 94.07 01/17/91 12:55:00 5.007 2.238 730 7,440 122 75 23.51 5,541 104.54 01/17/91 13:18:00 5.391 2.322 925 8,365 122 75 23.51 6,245 117.83 01/17/91 13:56:00 6.024 2.454 1,120 9,485 122 75 23.51 7,098 133.92 01/17/91 14:25:00 6.507 2.551 780 10,265 122 75 23.48 7,690 145.09 01/17/91 14:55:00 7.007 2.647 715 10,980 122 75 23.48 8,234 155.35 04/09/91 07:37:00 04/10/91 07:37:00 04/11/91 07:44:00 04/12/91 07:43:00 04/15/91 07:34:00 04/16/91 07:36:00

1,967.707 1,991.707 2,015.824 2,039.807 2,111.657 2,135.691

44.359 44.629 44.898 45.164 45.953 46.214

60 25 0 0 20 158

22,882 22,907 22,907 22,907 22,927 23,085

122 128 125 124 120 121

75 75 75 75 75 75

25.26 24.85 24.81 24.93 24.84 24.82

17,477 17,474 17,477 17,483 17,502 17,627

329.74 329.70 329.75 329.86 330.21 332.57

Table 3-2. Example Core Desorption Data Sheet READ ME

3.9

3

Chapter

Coal Sample Gas Content Evaluation

This is required so that the measured and headspace correction volumes are at the same temperature and pressure. Equation 3-3 lists the relationship.

The cumulative measured desorption volume at time i is the sum of all the desorption volumes up to time i. Mathematically, the sum is as follows.

é p - (T + 459.69 ) ù é Tai + 459.69 ù (3-3) v hi = v v ê a (i 1) ci - 1ú ê ú ëê pai Tc (i -1) + 459.69 ûú ë Tci + 459.69 û

(

)

Vsci =

(3-4)

i

åv

scj

j =1

Where: vv pa(i-1) Tci Tc(i-1)

canister internal void (headspace) volume, cm3 atmospheric pressure at time i-1, inches Hg canister temperature at time i, oF. canister temperature at time i-1, oF.

Where: Vsci cumulative measured desorption volume at time i corrected to standard conditions, cm3 j summation index

Example 3-1. Correction of Desorption Data. Correct the first measured desorption volume for headspace expansion and non-standard measurement conditions. The data and the required parameters are listed in Table 3-2. Start with Equation 3-3 to determine the headspace correction. The point that we are interested in was measured 1/17/91 at 10:13 AM.

é pa (i -1 ) (Tci + 459.69 ) ù é Tai + 459.69 ù é 23.59 (120 + 459.69 ) ù é 75 + 459.69 ù v hi = v v ê = 1143ê - 1ú ê - 1ú ê ú ú û ë 120 + 459.69 û ë 23.59(40 + 459.69 ) ëê pai Tc (i -1 ) + 459.69 ûú ë Tci + 459.69 û

(

)

v hi = 1143(0.1601)(0.9224 ) = 169 cm 3 This volume is at ambient temperature and pressure conditions. Now subtract the headspace correction from the measured volume and convert to standard conditions. First, compute the standard condition correction factor with Equation 3-2.

C sci =

pai (Tsc + 459.69 ) é 23.59(60 + 459.69 ) ù = = 0.764 p sc (Tai + 459.69 ) êë 30.01(75 + 459.69 ) úû

Now use Equation 3-1 to determine the corrected volume.

v sci = C sci (vi - v hi ) = 0.764(760 - 169 ) = 452 cm 3 Since this is the first point, the cumulative volume, Vsci, is equal to the incremental volume. Table 3-2 lists the cumulative desorption volume for each time. Now compute the air-dry gas content for this point using Equation 3-5. V 452 DGcadi = 32.0368 sci = 32.0368 = 8.53 scf/ton mad 1698

3.10

The volumes are converted to the air-dry gas content by dividing by the air-dry mass.

DGcadi = 32.0368 Where:

Vsci mad

(3-5)

∆Gcadi measured gas content at time i, air-dry basis, mad

scf/ton air dry mass, g

The temperature at standard conditions is commonly 60 oF. Note that gas volume corrections require absolute temperature. In customary units, absolute temperature is in degrees Rankin. Convert degrees Fahrenheit to Rankin by adding 459.69. If you prefer SI units, add 273.15 to degrees Celsius to convert to Kelvin.7 Standard pressure conditions vary. In this book, we use 14.696 psia or 30.01 inches Hg. We usually followed the Bureau of Mines criterion8 that collection of desorption data was terminated when the desorbed gas volume is less than 10 cm3/day for five consecutive days. We often had to desorb San Juan Basin Fruitland Formation samples for 60 to 90 days, or even greater times to meet this criterion. We are ready to compute the lost gas content once the corrections have been applied and the measured desorption volume is computed.

is based upon constant temperature diffusion from a sphere originally at constant, uniform concentration. At time zero, the concentration at the boundary of the sphere is instantaneously changed and held constant. Changing the pressure is equivalent to changing the concentration. The diffusion coefficient of the sphere is also constant. The constant temperature and constant boundary concentration assumptions cause most of the errors in application of this theory. You might question the spherical geometry assumption. It isn’t very important. The geometry of the desorption sample has little effect upon predicted gas rates as long as you assume the geometry of the natural fracture system to be the same as the sample geometry. The theory predicts that the rate of gas desorption is proportional to the square root of desorption time when

Direct Method We found that the Direct Method resulted in the most accurate lost gas volume estimates. We will concentrate on this method. For completeness, we will discuss two other methods developed by Smith & Williams and Amoco later in this book. The Direct Method8,9,10,11 was developed to estimate the gas content of coals to be mined. The theory behind the method

Figure 3-4. Example direct Method Graph

3.11

Chapter

3

Coal Sample Gas Content Evaluation

the gas content is greater than half the original gas content. This relationship allows us to determine the lost gas content from a graph of the cumulative desorbed air-dry gas content vs. the square root of the desorption time. Figure 3-4 illustrates an example of such a graph. Interpretation Equations The relationship of the data on the straight-line portion of the graph is as follows. æ D DG cad = çç 203.1G cad 2 r è

(3-6) ö Dt ÷÷ - G cLad ø

Where:

∆Gcad cumulative desorbed gas content, air-dry Gcad GcLad ∆t D/r2 D r

basis, scf/ton total gas content, air-dry basis, scf/ton lost gas content, air-dry basis, scf/ton desorption time, hours diffusivity, sec-1 diffusion coefficient, cm2/sec average diffusion distance, cm

The total air-dry gas content is the sum of the lost, measured, and residual gas contents as in Equation 37. G cad = G cLad + DG cad + G crad (3-7) Where: Gcrad residual gas content, air dry basis, scf/ton A graph of DGcad vs. Dt has an intercept equal to GcLad and a slope related to the diffusivity. Our estimate of the lost gas content will be the absolute value of the intercept. We will estimate the diffusivity from the slope with Equation 3-8.

Where: m =

3.12

D æ m = çç 2 r è 203.1Gcad

ö ÷÷ ø

2

(3-8)

slope of the desorbed gas content vs. square root time graph, scf/ton-hour0.5

Diffusivity The diffusivity of the coal microporous region controls the rate of desorption of the gas into the natural fracture system. The absolute permeability of the natural fracture system controls the rate of gas production from wells. Gas production rates are greater for reservoirs of greater diffusivity and greater absolute permeability. The two properties are interrelated. The absolute permeability depends upon the number and aperture of natural fractures. As the number of fractures increases, the distance that gas must diffuse through the microporous region decreases. High permeability reservoirs will usually have high diffusivity. The diffusivity is the diffusion coefficient of the coal microporous region, D, divided by the square of an average diffusion distance, r. In practice, we do not know the diffusion distance so we do not attempt to separate the two terms. Reservoir simulation models require an estimate of the diffusivity to calculate the desorption rate from the coal microporous region. Most models request a value of the sorption time. Sorption time and diffusivity are interrelated. The sorption time depends upon the diffusivity and the shape of the coal microporous region between natural fractures. Shapes are commonly assumed spherical, cylindrical, or cubic. The assumed shape has little effect upon the desorption rate calculations as long as the same shape assumed for estimating the diffusivity is used in the simulation model. You can estimate the sorption time from the diffusivity with the following relationship.

t=

τ α

1

(3-9)

D 3600a 2 r

sorption time, hours shape factor, dimensionless

The shape factor depends upon the geometry assumed for the sample. Values for the shape factor are listed in Table 3-3.

Geometry Cube Cylinder Sphere

Shape Factor 60 8 15

Table 3-3. Sorption Time Shape Factors

One of the advantages of reservoir temperature desorption measurements is that the diffusivity is estimated at reservoir temperature. Diffusivity is very sensitive to temperature. The ratio of the diffusivity at one temperature to another is related to the cube of the absolute temperature ratio. If temperature is constant, sorption time is equal to the time required to desorb 63% of the lost and measured gas content. Since temperature is rarely constant, estimates of the diffusivity from the Direct Method applied to heated samples are superior. Saturated Reservoir Time Zero Before we can prepare a Direct Method graph, we must determine when desorption begins so that we can calculate the elapsed time as a precursor to the desorption time. Desorption will begin when the pressure surrounding the sample is equal to the critical desorption pressure at the temperature of the sample. The critical desorption pressure is the pressure at which the gas content and storage capacity are equal. The method used to estimate time zero differs for reservoirs that are saturated or undersaturated. It is more difficult to estimate time zero for undersaturated reservoirs since it is related to the total and lost gas content estimates. An iterative technique is required in this situation. We will discuss the method later in this chapter. For saturated reservoirs, the critical desorption pressure is equal to the reservoir pressure if the coring fluid temperature is equal to the reservoir temperature. These two temperatures usually differ. The storage capacity depends on temperature. As the cooler coring fluid decreases the sample temperature, the storage capacity increases. This cooling effect causes the critical desorption pressure to decrease, which delays the start of desorption. In practice, we

cannot account for this effect for the simple reason that we usually do not have the data required to do so. Consequently, we will ignore the effect of temperature upon the estimate of time zero. If we assume that the core barrel is extracted at a constant rate, we can calculate the time at which the wellbore pressure is equal to the initial reservoir pressure. This assumption causes some error when both drill collars and drill pipe are included in the drill string. Drill pipe located above drill collars is removed much more quickly than collars. The retrieval rate decreases dramatically once the collars reach surface. The Direct Method ignores the changes in the retrieval rate. You should request that the desorption company personnel record the time when the top of the drill collars reach surface. This data would improve your estimate of time zero. If the reservoir pressure is greater than the hydrostatic head of the coring fluid, time zero is equal to the time when the sample is cored. Calculate the pressure due to the hydrostatic head of the coring fluid with Equation 3-10. p m = p a + 0.052 r m d R

(3-10)

Where: pm pa

ρm dR

mud (coring fluid) hydrostatic pressure, psia ambient (atmospheric) pressure, psia mud (coring fluid) density, pounds per gallon sample subsurface (reservoir) depth, feet

All pressures in this book are absolute rather than gauge. Gauge pressure is less than absolute pressure by the atmospheric pressure. You must compute gas properties with absolute pressure. People often confuse these two pressures and ignore the difference. The reservoir pressure is a function of depth as is the coring fluid hydrostatic pressure. We specify the reservoir pressure gradient on the desorption data sheets so that it is easy to calculate the reservoir pressure using the following relationship. p R = p a + Ñp R d R

(3-11)

Where: pR ∇ pR

reservoir pressure, psia reservoir pressure gradient, psi/ft

3.13

Chapter

3

Coal Sample Gas Content Evaluation

You calculate these two pressures to determine if the coring fluid pressure is greater than the reservoir pressure. Equations 3-10 and 3-11 require ambient pressure in psia. This pressure is often reported in units of inches of mercury. Multiply inches of mercury by 0.4898 to convert to psia. Weather reports convert atmospheric pressure to sea level regardless of the elevation. Do not use weather information. You must measure the atmospheric pressure at the measurement elevation unless you are at sea level. We calculate the time when the sample leaves its original depth and begins to desorb by interpolation of pressure as a function of time. We know when the sample reached surface where the pressure was atmospheric. We know when the sample left its original depth where the pressure was the coring fluid hydrostatic pressure. We want to know when the hydrostatic pressure is equal to the reservoir pressure. Compute the elapsed time between when the sample leaves its original depth to time zero with Equation 312.

é p - pR ù Dt R0 = Dt Rs ê m ú ë pm - pa û

(3-12)

Where:

∆tR0 ∆tRs

elapsed time between time raised above the original depth and time zero, hours elapsed time between time raised above the original depth and time when at surface, hours

Elapsed times for desorption data analyses are computed from time zero, which is the time that the sample is raised above its original depth plus ∆tR0. Example 3-2 shows how to compute time zero. Undersaturated Reservoir Time Zero When reservoirs are undersaturated, it is more difficult to determine when the samples begin to desorb gas since the critical desorption pressure estimate depends upon the total (lost, measured, and residual) gas content estimate. The critical desorption pressure is at some unknown level below the reservoir pressure. The best way to determine the critical desorption pressure is by measuring the bottom-hole pressure during the early production life of the reservoir or during initial drill stem tests. When gas production

Example 3-2. Calculate Time Zero for Desorption Calculate time zero and the elapsed time between time zero and sealing the sample in a canister for the Table 3-2 data. Start by computing the mud hydrostatic and reservoir pressure with Equations 3-10 and 3-11. Then compute ∆tR0 with Equation 3-12. Note that the atmospheric pressure was 23.59 inches Hg or 11.55 psia when the sample was sealed in the canister. p m = 11.55 + 0.052(10.5 )(3163 ) = 1739 psia

p R = 11.55 + (0.479 )(3163 ) = 1527 psia

The reservoir pressure is less than the mud pressure. Desorption did not begin until the sample was lifted above the original depth. The elapsed time between lifting and when the sample reached surface was 2 hours 15 minutes or 2.25 hours.

é 1739 - 1527 ù = 0.276 hours Dt R0 = 2.25 ê ë 1739 - 11.55 úû The time between the sample leaving it original depth and being sealed was 2.583 hours. Therefore, time zero occurred 2.583 - 0.276 = 2.307 hours before sealing, or at 7:27 AM.

3.14

begins, the time and critical pressure is usually apparent in the pressure data and perhaps in the gas production rates. The critical desorption pressure is then used in Equation 3-12 rather than the reservoir pressure to determine the time at which desorption began. Be careful when you conclude that a reservoir is undersaturated. Errors in gas content and storage capacity data can cause the appearance of undersaturation. The iterative procedure begins with an estimate of a total gas content that is less than the storage capacity. Then follow these steps. 1. Estimate the critical desorption pressure using the isotherm relationship and Equation 62 of Chapter 6. 2. Use the critical desorption pressure in place of reservoir pressure and compute ∆tR0 with Equation 3-12. 3. Compute time zero and the desorption time. 4. Redo the regression of the same Direct Method data points used for the original estimate to compute the lost gas content. 5. Repeat steps 1 through 4 until the change in the estimated gas content is small, i.e., 1 to 5 scf/ ton. You may require three to four iterations to reach convergence. Iteration is best performed with a computer since either the Direct Method graph must be redrawn or a linear regression of the points recalculated during each iteration. Desorption Time Correction There is usually a delay between when a canister is sealed and the first desorption point is measured. The technician usually takes the canister from the catwalk to an on-site measurement location where the canister is weighed and placed in a water bath. During this time,

gas is not lost from the sample since the canister is sealed. We subtracted the time between sealing and the first measurement point from the elapsed time to correct for the delay. We referred to this time as “the desorption time correction” and symbolized as tdc. Compute the horizontal axis of the Direct Method graph with Equation 3-13. t DM =

(ti - t0 ) - t dc

(3-13)

Where: tDM Direct Method horizontal axis value (square root of desorption time), hours½ ti measured time i, hours to time zero, hours tdc desorption time correction Example 3-3 shows you how to make the correction and compute the horizontal axis for the Direct Method graph. Temperature Recovery Time Once the estimate of time zero is available, you prepare a graph of the cumulative desorbed gas content vs. the Direct Method axis value, tDM. Figure 3-4 illustrates a graph of the data in Table 3-2. When the desorption samples are reheated to reservoir temperature, the graph is “S shaped.” The lower end of the S is caused by the increase in the desorption rate as the temperature is increased. The upper end of the S results from a reduction of the desorption rate due to depletion of the sample gas content. The middle portion of the S is the data that we use to determine the lost gas content and diffusivity. We simulated the temperature changes that a sample went through at the COAL Site as illustrated in Figure 3-5. Coal drill cuttings were tightly packed into a can-

Example 3-3. Compute the Direct Method Horizontal Axis Compute the value of the Direct Method horizontal axis which is equal to the square root of the desorption time for the first measured data point in Table 3-2 at 1/17/91 10:13 AM. Time zero was at 7:27 AM based upon Example 3-2. The elapsed time between the first measured point and time zero is therefore 2.767 hours. The desorption time correction is the elapsed time between the time of sealing the canister (9:45 AM) and the first measurement point. The correction is 0.467 hours. Use Equation 3-13 to calculate tDM. 1 t DM = (ti - t0 ) - t dc = (10.217 - 7.450 ) - 0.467 = 1.517 hours 2

3.15

Chapter

3

Coal Sample Gas Content Evaluation

ter 3.2 hours. The time required for the temperature to return to the reservoir temperature was roughly equal to the time required to retrieve the sample and to place the canister into the water bath. We refer to this time as the temperature recovery time. We observed similar results for core samples from this and other wells and confirmed the observations with heat transfer theory. For the GRI Observation Well #2 data listed in Table 3-2, the temperature recovery time was 2 hours 35 minutes, equal to the time between raising the sample above its original depth and placing the canister in a water bath. Refer to Example 3-4 for the details of the temperature recovery calculation. Figure 3-5. The elapsed time corresponding to Sample Internal Temperature Changes the end of the temperature recovery time was 4.89 hours that corresponds to 2.1 ½ ister and a temperature probe was inserted into the cen- hours on the Direct Method horizontal axis. This ter of the cuttings. The instrumented canister, origi- value (2.1 hours½) is approximately the start of the nally at 120 oF, was placed in a water bath maintained straight-line portion of the data illustrated in Figure 3at 85 oF for 3.2 hours, removed, and placed in a tem- 4. The range of the data selected for the Direct Method perature bath maintained at the reservoir temperature lost gas estimates begins immediately after the end of of 120 oF. The temperatures were based upon the res- the temperature recovery time. The end of the selected ervoir and mud circulating temperatures of 120 oF and data range is based upon deviation from the straight 85 oF. The time in the 85 oF bath was based upon the line. As you can see in Figure 3-4, four points in the circle lie on the straight line. The later points begin to core retrieval time of 3.2 hours. The internal temperature of the cuttings dropped deviate below the line. The greatest slope (and greatest desorption rate) 27 oF to 93 oF which was 8 oF greater than the simuoccurs immediately after the temperature recovery lated mud circulating temperature. The temperature o returned to within 2 F of the original temperature af- time. The greatest slope results in the greatest estimates Example 3-4. Estimate the Temperature Recovery Time Estimate the start and end of the temperature recovery time for the data listed in Table 3-2. The canister was placed in a water bath immediately after sealing. The elapsed time between the time when the core barrel started out of the well and the time to sealing was 2 hours 35 minutes. Therefore, the temperature recovery time was 2.5833 hours. The end of the temperature recovery time is 2.5833 hours after the canister was sealed. Example 3-2 estimated that time zero was 2.307 hours before sealing. The end of the temperature recovery time is at 2.307+2.5833=4.8903 hours. The value of the Direct Method horizontal axis based upon Equation 3-13 is 1 4.8903 − 0.467 = 2.10 hours 2

3.16

Reservoir Temperature Desorption Data

80 Temp. Recovery Time

60 40

0 -20 -40 51.5 scf/ton

-60 -80 -100 -120 -140

hours, respectively. Theses values correspond to diffusivity estimates of 7.2(10-7) and 2.5(10-7) sec-1 for the reservoir and ambient data. The ambient temperature sorption time estimate is in error by 188%. The presence of a straight line section does not mean that the lost gas analysis is valid. There is no indication from ambient data alone that the apparent straight line results in such large errors.

Ambient Temperature Desorbtion Data

20

Sample Temperature, Deg. F.

Cumulative Desorbed Dry, Ash-Free, Gas Content, scf/ton Lost Dry, Ash-Free, Gas Content, scf/ton

100

123.5 scf/ton

0

130

Temp. Recovery Time

110 90 70 Wellbore & Surface Temp.

50

0

1

2

Reservoir Temp. Bath

30 1

2 3 Elapsed Time, hours

3

4

4

5

Direct Method Calculations Once the Direct Method graph has been properly prepared, you can Figure 3-6. select the proper data range to deterComparison of Ambient & Reservoir mine the slope and intercept of the Temperature Desorption Data correct straight line. You then compute the lost gas content, total gas of the lost gas content. Also in this time region, desorpcontent, diffusivity, and sorption time estimates. Extion is controlled by the same diffusivity as in the ample 3-5 shows you how to make the calculations for reservoir. Estimates of the diffusivity from this portion the data listed in Table 3-2 and illustrated in Figure 3of the data are equal to those that will control in-situ 4. diffusion. Square Root of Desorbtion Time, hours1/2

Smith & Williams Method

Ambient Temperature Direct Method The S shape is not present when desorption measurements are performed at ambient temperature. The line selected for the Direct Method usually starts after the first data point. The end of the line occurs when deviation below the line is noticeable. Figure 3-6 illustrates a Direct Method graph for two Fruitland Formation samples obtained from the Southern Ute 5-7 well for measurements performed at reservoir and ambient temperatures. The ambient temperature data appears to have a straight-line section immediately after the start of the measurements. Extrapolation of the line to time zero results in a lost gas estimate of 51.5 scf/ton. This estimate is 58% lower than the correct (reservoir temperature) lost gas content estimate. The diffusivity and sorption time estimates from the ambient temperature data are in even greater error. The sorption time estimates for the reservoir and ambient data were 25 and 72

Smith and Williams12 ,13 developed a lost gas analysis method that accounts for the pressure changes that samples undergo before sealing in desorption canisters. The theoretical basis is the same as for the Direct Method and includes the same assumptions with the exception of the pressure conditions. The lost gas estimate methodology is based upon a graph that relates a volume correction factor to a lost time ratio and a surface time ratio. The measured desorbed gas volume is multiplied by the correction factor to determine the total gas content. We found that the Smith & Williams method usually results in lower lost and total gas content estimates than the Direct Method. For GRI cooperative research wells, the Smith & Williams total gas content estimates averaged 27.3% less than the Direct Method results.14 The Direct Method results were more accurate based upon comparison to benchmark gas content data. Our results contradict assertions made by Smith &

3.17

Chapter

3

Coal Sample Gas Content Evaluation

Example 3-5. DirectMethod Gas Content, Diffusivity, and Sorption Time Estimate the lost gas content, total gas content, diffusivity, and sorption time for the data illustrated in Figure 3-4 and tabulated in Table 3-2. The residual gas content was zero for this sample. The intercept at time zero in Figure 3-4 is -250 scf/ton. The lost gas content is equal to the absolute value of the intercept. The last point in Table 3-2 is 333 scf/ton. This is the measured gas content. The total gas content is the sum of the lost, measured, and residual gas contents: 250+333+0=583 scf/ton. This is on an air-dry mass basis since the measured data are on an air-dry basis. Estimate the diffusivity using the slope and Equation 3-8. The slope is 147 scf/ton-hour½ in Figure 3-4. 2

2

ö æ ö D æ m 147 ÷÷ = çç ÷÷ = 1.54 10 -6 sec -1 = çç 2 ( ) 203 . 1 G 203 . 1 583 r è ø cad ø è If we assume that the diffusion geometry is spherical, the sorption time follows from Equation 3-9. t=

)

1 = 12 hours 3600 (15 )(1.54 ) 10 -6

Williams12 that the Direct Method should result in a 19% over-prediction of the gas content due to retardation of desorption by the slowly decreasing pressure history of the sample.

Amoco Method Amoco15 ,16 developed a lost gas volume estimate methodology based upon the same theory as the Direct Method. The Amoco Method fits a simplified form of the Direct Method equation to all of the measured desorption data by non-linear regression. The results of the non-linear regression are three parameters, the lost gas content, the total gas content, and the diffusivity. A computer program is required to apply the Amoco Method. Reference 14 provides details concerning Amoco Method mathematics. For GRI cooperative research wells, we found that the Amoco Method total gas content estimates averaged 21% greater than the Direct Method.14 The primary cause of error was that the Direct Method mathematical model only describes desorption behavior when the desorbed gas content is less than half the total gas content. However, Amoco chose to fit all of the data with the model. We may have found that the Amoco Method was more accurate had we limited the application to the first half of the data. Amoco may limit the data range in practice.

3.18

(

(

)

Amoco’s idea of fitting a mathematical model to all of the data is excellent. However, a more theoretically sound desorption model is required.

Summary In this section, we introduced you to the procedures for desorption measurements and the methods for interpreting the data. We covered the first two steps of the gas-in-place estimate procedure in detail. These steps were: 1. Perform gas desorption measurements at reservoir temperature on conventional core samples. 2. Estimate the total gas content of each sample using the Direct Method lost gas content procedure. You will perform this analysis on multiple samples and then interpret the data from multiple samples as we will discuss in Chapter 4.

Additional Reading There has been much published on performing desorption measurements and on interpreting the data. If you wish more details, refer to Reference 1. References 14 and 17 document the GRI research. Amoco personnel published an excellent paper on the subject in Reference 15.

Chapter 3 References 1. McLennan, J.D., Schafer, P.S., and Pratt, T.J.: A Guide to Determining Coalbed Gas Content, Gas Research Institute Report No. GRI-94/0396, Chicago, Illinois (1995) 182 p. 2. Mavor, M.J., Pratt, T.J., Crandlemire, A., and Ellerbrok, G.: “Assessment of Coalbed Methane Resources at the Donkin Mine Site, Cape Breton, Nova Scotia, Canada,” Paper 9368, Proceedings of the 1993 International Coalbed Methane Symposium, The University of Alabama / Tuscaloosa, Alabama (May 1993) pp. 471-481. 3. Mavor, M.J., Logan, T.L., and Robinson, J.R.: Cooperative Evaluation of San Juan Basin, Phillips Petroleum Company, Openhole Well Recompletion Efforts, Gas Research Institute Topical Report No. GRI-93/ 0466, Chicago, Illinois (July 1995) 105 p. 4. 1994 Annual Book of ASTM Standards, Section 5, Volume 05.05 Gaseous Fuels; Coal and Coke, D 172-89, American Society for Testing and Materials Philadelphia, Pennsylvania (1994) p. 292. 5. 1994 Annual Book of ASTM Standards, Section 5, Volume 05.05 Gaseous Fuels; Coal and Coke, D 176-89, American Society for Testing and Materials, Philadelphia, Pennsylvania (1994) pp. 302. 6. 1994 Annual Book of ASTM Standards, Section 5, Volume 05.05 Gaseous Fuels; Coal and Coke, D 197-87, American Society for Testing and Materials, Philadelphia, Pennsylvania (1994) p. 152. 7. The SI Metric System of Units and SPE METRIC STANDARD, Second Printing, Society of Petroleum Engineers, Richardson, Texas (1984) 39 p. 8. Kissell, F.N., McCulloch, C.M., and Elder, C.H.: The Direct Method of Determining Methane Content of Coalbeds for Ventilation Design, Report of Investigations 7767, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1973) 17 p. 9. Bertard, C., Bruyet, B., and Gunther, J.: “Determination of Desorbable Gas Concentration of Coal (Direct Method),” International Journal of Rock Mechanics and Mining Science, Vol. 7 (1970) pp. 43-65. 10. Diamond, W.P. and Levine, J.R.: Direct Method Determination of the Gas Content of Coal: Procedures and Results, Report of Investigations 8515, United States Department of the Interior, Bureau of Mines, Washington, D.C. (1981) 36 p. 11. Ulery, J.P., Hyman, D.M.: “The Modified Direct Method of Gas Content Determination: Applications and Results,” Paper 9163, Proceedings of the 1993 International Coalbed Methane Symposium, The University of Alabama / Tuscaloosa, Alabama (May 1993) pp. 489-500. 12. Smith, D.M. and Williams, F.L.: “A New Technique for Determining the Methane Content of Coal,” Proceedings of the 16th Intersociety Energy Conservation Engineering Conference, Atlanta, Georgia, (1981) pp. 1,167-1,272. 13. Smith, D.M., Methane Diffusion and Desorption in Coal, Dissertation Submitted in Partial Fulfillment of the Requirements for the Degree of Doctor of Philosophy in Chemical Engineering, The University of New Mexico, Albuquerque, New Mexico (May 1982) 172 p. 14. Mavor, M.J., Pratt, T.J., and Britton, R.N.: Improved Methodology for Determining Total Gas Content, Volume I. Canister Gas Desorption Data Summary, Gas Research Institute Report No. GRI-93/0410, Chicago, Illinois (May 1994) 230 p.

3.19

Chapter

3

Coal Sample Gas Content Evaluation

15. Yee, D., Seidle, J.P., and Hanson, W.B.: “Gas Sorption on Coal and Measurement of Gas Content,” in Law, B.E. and Rice, D.D. (editors): Hydrocarbons from Coal, AAPG Studies in Geology #38, American Association of Petroleum Geologists, Tulsa, Oklahoma (1993) pp. 203-218. 16. Metcalfe, R.S., Yee, D., Seidle, J., and Puri, R.: “Review of Research Efforts in Coalbed Methane Recovery,” Paper SPE 23025, SPE Asia-Pacific Conference, Perth, Western Australia (November 4-7, 1991). 17. Mavor, M.J., and Pratt, T.J.: Improved Methodology for Determining Total Gas Content, Volume II. Comparative Evaluation of the Accuracy of Gas-In-Place Estimates and Review of Lost Gas Models, Gas Research Institute Report No. GRI-94/0429, Chicago, Illinois (March

3.20

4

Multiple Sample Analysis

Chapter

I

n-situ gas content estimates are not accurate if you base them upon a single sample. You must desorb and interpret the data from multiple samples. Gas content estimates from different samples differ due to differing sample composition and errors. We have found that the most accurate way of minimizing errors is to relate the gas content from multiple samples to the sample composition. Errors will be minimized as long as the variation in the sample composition is greater than the standard deviation of the reservoir composition variation. In this chapter, we will cover Steps 3 through 5 of the gas-in-place estimate procedure. These steps are:

Figure 4-1. GRI #2 Air-Dry Gas Content vs. Inorganic Content Where:

3. Relate the total gas content of multiple samples to sample composition. 4. Relate the sample composition to density. 5. Determine the in-situ moisture content from equilibrium moisture content measurements.

Gcad Gco β wa ww

The interpretation of multiple desorption samples is illustrated by Figure 4-1 for data from GRI Well #2 at the COAL Site. The relationship between total gas content and inorganic content is determined by linear regression of Equation 4-1.

The vertical axis in Figure 4-1 is the air-dry gas content estimate obtained from each sample. The horizontal axis is the inorganic content (ash + moisture content) of each sample determined by proximate analysis. The intercept at an ash plus moisture content of zero is equal to the organic fraction gas content estimate for

G cad = G co + b (wa + ww )

(4-1)

air-dry gas content, scf/ton organic fraction gas content, scf/ton slope, scf/ton ash content, weight fraction moisture content, weight fraction

4.1

Chapter

4

Multiple Sample Analysis

the reservoir(s) of interest. We will use this value to compute the in-situ gas content once we determine the average in-situ inorganic content. The relationship for the seven samples from GRI Observation Well #2 resulted in an intercept of 908.8 ± 199.4 scf/ton. We estimated the range in the intercept from the confidence intervals. The 95% statistical confidence interval estimates (represented by the dashed lines in Figure 4-1) indicates the fit accuracy. The distance between the two 95% confidence interval is less when the variation in the sample inorganic content Figure 4-2. is greater and more samples are availGRI #1 Air-Dry Gas Content vs. Inorganic Content able. Had there been more samples with greater inorganic content variation from this well, the variation in the intercept would of the reservoir as shown by Example 4-1. The problem have been less. is that the average of a few samples is not an accurate In all GRI western basin research efforts, the cor- predictor of the average reservoir condition. The Exrelation of total gas content to the inorganic content has ample 4-1 estimate of the gas-in-place volume would resulted in an estimate of zero gas content at an ash plus have been low by 28.7% if based upon the average of moisture content less than one. Generally, the zero gas the samples. Based upon Example 2-1, the correct gascontent point was within statistical significance levels in-place volume was 60.28 Bscf per square mile. The of one. For example, the slope of the line illustrated in error is equivalent to 17.3 Bscf per square mile. A later section of this chapter will show you how to Figure 4-1 is equal to -1,037.5 ± 379.2 scf/ton and intersects the zero gas content abscissa at 0.876. The estimate the number of samples required to obtain range between the intersection of the confidence inter- statistically significant results. One important point to remember is that the range of the inorganic content of vals with the horizontal axis includes one. The extrapolation to a organic fraction gas content the samples must exceed the standard deviation of the may not be statistically valid in the event that few data inorganic content of the reservoir for accurate estipoints are available or if the samples have a narrow mates. range of ash and moisture contents. Such a situation is illustrated by Figure 4-2 for data collected from GRI Composition and Density Relationship Well #1 at the COAL Site. The intercept and slope for The composition of coal gas reservoirs can be these six points was 910.7 ± 902.0 scf/ton and -1,264.9 estimated from open-hole density log data and core ± 3,644.6 scf/ton, respectively. Surprisingly, the inter- data. We must relate the inorganic content to density to cept was very close to the result obtained from the GRI use the relationship between gas content and inorganic #2 samples but the confidence in the intercept and slope content. The sample or reservoir density is related to the was much lower. density of the ash, moisture, and organic fractions by Averaging the individual sample data does not Equation 4-2. result in an accurate estimate of the average gas content -1 é wa 1 - (wa + ww ) ww ù r =ê + + ro r w úû ë ra

4.2

Where:

ρ ρa ρo ρw

density, g/cm3 ash density, g/cm3 organic fraction density, g/cm3 sorbed water density, g/cm3

If we know the sample ash and equilibrium moisture contents, we can estimate the density. Therefore, we can convert the horizontal axis of Figure 4-1 or 42 to density. Example 4-2 shows you how to apply Equation 4-2. The density of the ash and organic portions of reservoirs can differ. Sample density can be measured and related to the ash, organic, and moisture contents. We found that accurate density measurements require helium pycnometry. A helium pycnometer measures

the volume of the sample by helium expansion. Helium is used since it enters coal micropores without adsorption and does not add moisture to the sample. The test is not destructive and accurate results are obtained on samples as small as three grams. Sample density is determined in this manner during sorption isotherm measurements. Instruct the laboratory staff to report the sample density when measuring storage capacity data. An interpretation method to determine ash and organic fraction density is based upon a rearranged version of Equation 4-2 listed in Equation 4-3.

æ wa ö -1 r -1 - ww r w-1 ÷÷ r a - r o-1 = r o-1 + çç 1 - ww 1 w w ø è

(

)

(4-3)

Example 4-1. Average Dry, Ash-Free Gas Content Estimates for Low Confidence Data Sets The relationship illustrated in Figure 4-2 between air-dry gas content and inorganic content is statistically insignificant. Insignificance can be caused by two few points, a narrow variation in the sample inorganic content, or by improper sample split selection for inorganic content measurements. One approach to estimating the organic fraction gas content is to average the dry, ash-free gas content estimates from each sample. These are summarized below for the six samples in Figure 4-2. Sample ID No.

Ash Content fraction

35-1 35-3 35-4 35-6 35-7 35-8 Average

0.418 0.349 0.404 0.426 0.350 0.388 0.389

Moisture Content fraction 0.026 0.045 0.044 0.033 0.049 0.041 0.040

Air-Dry Gas Content scf/ton 386.2 450.0 308.8 346.8 372.2 372.0 372.6

Dry, Ash-Free Gas Content scf/ton 694.1 741.7 559.2 641.2 620.0 650.7 651.2

The average dry, ash-free gas content estimate severely underestimates the organic fraction gas content estimate. The benchmark for these data is 913 scf/ton. Why is the average dry, ash-free gas content so much lower? There are two reasons. The first is that there are insufficient samples for errors to be normally distributed and cancel opposite errors. Secondly, there are insufficient samples to obtain a statistically significant estimate of the average dry, ash-free gas content of the reservoir. If you are reduced to analyzing gas content data in this manner, keep in mind that your estimates of the gas-in-place volume may be quite low. In this case, the gas-in-place estimate would have been low by 28.7%.

4.3

4

Chapter

Multiple Sample Analysis

Example 4-2. Relationship between Density & Inorganic Content Use estimates of the ash density (2.497 g/cm3) and the organic density (1.295 g/cm3) to estimate the density at an ash content of 0.30 and 0.55. Use an equilibrium moisture content of 0.0089 to approximate the in-situ moisture content. Use Equation 4-2 for the calculation. wa = 0.30;

éw 1 - (wa + ww ) ww ù r =ê a + + ro r w úû ë ra

-1

é 0.30 1 - (0.30 + 0.0089 ) 0.0089 ù =ê + + 1.295 1 úû ë 2.497

-1

é 0.55 1 - (0.55 + 0.0089 ) 0.0089 ù =ê + + 1.295 1 úû ë 2.497

-1

= 1.51 g/cm 3

wa = 0.55;

éw 1 - (wa + ww ) ww ù r =ê a + + ro r w úû ë ra

-1

Prepare a graph, such as in Figure 4-3, of the left-hand side of Equation 4-3, [the reciprocal of the dry density], versus wa/(1-ww) [the dry ash content] to interpret density – proximate data. We assume that the sorbed water density is one g/cm3. The graph results in a vertical axis intercept at zero equal to the reciprocal of the organic fraction density. The vertical axis intercept at one is equal to the reciprocal of the ash density. The analysis results in estimates of the coal density equal to 1.276 ± 0.023 g/cm3 and the ash density equal to 2.497 ± 0.310 g/cm3. The densities of the organic and ash fractions are functions of the compositions of each. The organic composition is quantified by the maceral composition.1 ,2 The three primary maceral groups are vitrinite, exinite (liptinite) and inertinite. Each of these groups includes sub-groups that have similar properties. Vitrinite is the most common maceral group in Upper Cretaceous Western Interior bituminous humic coal seams of the U.S. With maceral density data, you can compute the expected organic fraction density based upon the volumetric average density of each of three components; vitrinite, inertinite, and exinite. Equation 4-4 lists the relationship. The maceral density data is rarely measured. However, published data are available.

= 1.76 g/cm 3

r o = r vVv + r iVi + r eVe

(4-4)

Where:

ρo ρi Vv Ve

organic fraction density, g/cm3 vitrinite maceral density, g/cm3 inertinite maceral density, g/cm3 exinite maceral density, g/cm3 vitrinite content, volume fraction inertinite content, volume fraction exinite content, volume fraction

ρv ρe Vi

Figure 4-3. Relationship between Sample Density and Ash Content

READ ME

4.4

Primary Maceral Group Vitrinite Inertinite Exinite Vitrinite Inertinite Exinite Vitrinite Inertinite Exinite Vitrinite Inertinite Exinite Vitrinite Inertinite Exinite

Study

Dyrkacz & Horwitz1

Minimum Density g/cm3 1.21 1.25 1.08 1.22

Mode Density g/cm3 1.28 1.35 1.20 1.30

Maximum Density g/cm3 1.36 1.46 1.25

Crelling2 1.06 1.27

1.22 1.30 1.39 1.21

1.29

University of Utah3 1.14 Australian4

Average

1.18 1.28 1.34 1.12 1.29 1.35 1.18

Table 4-1 Summary of Published Maceral Density Ranges

Well

Sample

Valencia Canyon 32-1 Valencia Canyon 32-1 Valencia Canyon 32-1 Valencia Canyon 32-1 Valencia Canyon 32-1 Southern Ute 5-7 Southern Ute 5-7 Southern Ute 5-7 Southern Ute 5-7 Southern Ute 5-7 COAL Site Overall Average

Intermediate Fruitland Test 1 Intermediate Fruitland Composite Basal Fruitland Test 2 Basal Fruitland Composite Average Intermediate Fruitland Composite Intermediate Fruitland Test 1 Basal Fruitland Composite Basal Fruitland Test 3 Average GRI #1

Vitrinite Content

Inertinite Exinite Content Content

Volume Fraction 0.830 0.905 0.892 0.758 0.846 0.852 0.821 0.798 0.830 0.825 0.916 0.845

Volume Fraction 0.135 0.063 0.095 0.198 0.123 0.125 0.155 0.159 0.140 0.145 0.083 0.128

Volume Fraction 0.035 0.032 0.013 0.044 0.031 0.023 0.024 0.043 0.030 0.030 0.001 0.027

Organic Fraction Density g/cm3 1.294 1.290 1.294 1.297 1.294 1.295 1.297 1.295 1.295 1.295 1.295 1.295

Table 4-2 Fruitland Formation Organic Fraction Density Estimates

4.5

Chapter

4

Multiple Sample Analysis

Table 4-1 summarizes published density data for the three coal maceral types. Based upon Table 4-1, the average density values for vitrinite, inertinite, and exinite are 1.29, 1.35, and 1.18 g/cm3. These values were used to compute the possible range in Fruitland Formation coal density for nine samples obtained from the Valencia Canyon 32-1, Southern Ute 5-7, and COAL Site locations.1 The composition and density estimates for the samples are summarized in Table 4-2. Table 4-2 shows that the average value of 1.295 g/ 3 cm for the organic fraction density was remarkably similar to the value for all of the samples. There is an alternative method of estimating organic density from ultimate analysis data based upon a correlation. Ultimate analyses were discussed in Chapter 3. Coal composition data from a set of 66 coal samples ranging in rank from lignite to low-volatile bituminous were correlated as a function of ultimate analysis data.1 A correlation for the organic fraction density based upon an ultimate analysis is listed in Equation 4-5.

Sample

GRI #1 Test 1 GRI #2 S. Ute Tribal I PLA 9 #2 SSR #11-15 Test 2 SU 5-7 Intermediate Composite SU 5-7 Intermediate Tests 1 2 3 4 5 SU 5-7 Basal Composite SU 5-7 Basal Test 3 VC 32-1 Intermediate Test 1 VC 32-1 Intermediate Composite VC 32-1 Basal Test 2 VC 32-1 Basal Composite Average

rˆ o = 1.534 - 5.196 w H + 0.7375 wO - 2.472 w N + 0.3853 wS

(4-5) where: rˆ o estimated organic fraction density, g/cm3 wH hydrogen content, weight fraction wO oxygen content, weight fraction wN nitrogen content, weight fraction wS sulfur content, weight fraction Equation 4-5 results in estimates of the organic fraction density similar to those derived from laboratory measurements as summarized in Table 4-3. The average of 1.296 g/cm3 is very similar to the estimate obtained by density measurements. We recommend that you perform ultimate analyses and use Equation 45 when density data are unavailable. Fruitland coal was deposited in an environment that included a variety of rock types including sandstone, shale, and volcanic ash deposits. The ash contained within the coal contains a high proportion of kaolinite (density 2.42 g/cm3) with quartz (density:

Hydrogen Carbon Content, Content, Dry Ash- Dry AshFree Free weight weight fraction fraction 0.0470 0.8330 0.0492 0.8014 0.0519 0.8453 0.0549 0.8545 0.0583 0.7946 0.0546 0.8287 0.0571 0.8134 0.0538 0.8289 0.0557 0.8285 0.0597 0.8326 0.0593 0.8427 0.0600 0.8338 0.0551 0.8281

Nitrogen Content, Dry AshFree weight fraction 0.0143 0.0296 0.0140 0.0127 0.0007 0.0006 0.0006 0.0006 0.0107 0.0156 0.0144 0.0153 0.0108

Sulfur Content, Dry AshFree weight fraction 0.0174 0.0134 0.0086 0.0104 0.0095 0.0080 0.0183 0.0094 0.0063 0.0076 0.0078 0.0073 0.0103

Oxygen Content, Dry AshFree weight fraction 0.0883 0.1064 0.0802 0.0675 0.1369 0.1081 0.1106 0.1073 0.0988 0.0845 0.0758 0.0836 0.0957

Table 4-3 Summary of Equation 4-5 Organic Fraction Density Estimates

4.6

Equation 4-5 Organic Density g/cm3 1.326 1.289 1.292 1.271 1.334 1.332 1.324 1.336 1.293 1.250 1.249 1.249 1.296

2.65 g/cm3) and feldspar (density range: 2.55 to 2.76 g/cm3) components in lesser amounts.1 This composition suggests that the density of kaolinite would be a minimum estimate of the density of the ash. The estimated ash density of 2.497 g/cm3 shown in Figure 4-3 is in line with the kaolinite density. Example 42 shows you how to use these values to compute the relationship between density and inorganic composition. With estimates of the density of the ash and organic fractions, it is possible to compute the ash content from the density. We will do this in Chapter 5 to evaluate open-hole density log data for estimates of the in-situ ash content. Equation 4-6 lists the relationship for ash content from density data.

Figure 4-4 Valencia Canyon 32-1 Equilibrium Moisture Content vs. Temperature

(4-6)

æ 1 æ 1 1ö 1 ö ÷ çç - ÷÷ + wwe çç ro r ø r w r o ÷ø è è wa = 1 1 ro ra Where: wwe equilibrium moisture content, weight fraction The moisture content is determined independently by equilibrium moisture content measurements on coal samples.

Equilibrium Moisture Content You should base estimates of the in-situ gas content and density upon the in-situ moisture content. The moisture content obtained from the proximate analyses performed on air-dried samples is not equal to the insitu moisture content. The sample moisture content can be greater or less than the in-situ moisture content depending upon the sample type, coal rank, handling, and drying procedures. Presently, we recommend that

ASTM equilibrium moisture content data (measured with ASTM D14121 ) be used to approximate the insitu moisture content. The equilibrium moisture content measurement involves placing a weighed, pre-wetted coal sample contained in an uncovered bottle into a vacuum desiccator. The desiccator includes a dish containing a saturated solution of K2SO4 that maintains the relative humidity at 96% to 97%. The desiccator is evacuated to a pressure of 30-mm Hg and placed in an 86 oF convection oven. The sample remains in the oven for 48 hours or until a constant weight is achieved. The sample is removed and reweighed. The sample is then dried for 1.5 hours at 105 oC and the final dry weight measured. equilibrated coal weight. One of the limitations of this method is that the equilibrium moisture content is not measured at reservoir temperature. The results vary with temperature. Figure 4-4 illustrates the moisture dependence upon temperature for two Valencia Canyon 32-1 reservoirs. The reservoir temperature at this location is 100 oF Increasing the temperature from 86 to 100 oF decreases the equilibrium moisture content by 10% to 12% of the 86 oF value. This change is insignificant for gas-in-

4.7

Chapter

4

Multiple Sample Analysis

place estimates but can affect sorption isotherm measurements.1 We recommend that you select at least three samples per reservoir for the moisture measurements to determine consistency. The equilibrium moisture content is often available from samples selected for sorption isotherm measurements.

Number of Samples Required One of the questions that arises concerns the number of samples that are required to accurately determine the gas content. You can answer this question by statistical analysis based upon operating characteristic curves such as illustrated in Figure 4-5.12 The statistical problem involves selecting a subset of the reservoir such that the subset has the same average properties as the reservoir. You must specify two significance levels. The first level is the probability that the analysis concludes that the average property of the sample set is equal to the average property of the reservoir when they are equal. We chose 95% for this level. The second level is the risk that the analysis concludes that the average property of the sample set is equal to the average property of the reservoir when the sample set average is different by a significant amount. We use a risk of 10% to 20% for the second level. In Figure 4-5, the horizontal axis value is the difference between the sample set average property, µ, and the reservoir average property, µ0, divided by the standard deviation, σ, of the reservoir property. The horizontal axis value is zero when the sample set average and reservoir property average are the same. For a given error, the value of the horizontal axis increases as the standard deviation of the reservoir property decreases. The vertical axis is value of the first or second significance level and is a function of the number of samples, n. For the first level, the vertical axis is the value of the probability that the sample set property average is equal to the reservoir property average. Since we chose a level of 95%, the intercept at

4.8

Figure 4-5 Operating Charateristic Curves zero (when the averages are equal) is 0.95. The standard deviation must be estimated to determine the number of samples required, n. We are most interested in the density distribution in the samples and in the reservoir when we adjust open-hole log analyses to agree with core analyses. Therefore, we will use open-hole density logs in the statistical analysis. Before drilling, you can use open-hole density data from offset or analogous wells to determine the number of samples required. After logging, you should verify the statistical analysis with logs from the cored well. How do we use Figure 4-5? Suppose that the value of the horizontal axis is 2 as would be the case for a reservoir with a narrow density standard deviation. If only two samples are available, there is a 20% chance that the sample set average differs more than 10% from the in-situ average. Consider the case when the standard deviation of the in-situ density is twice as wide resulting in a horizontal axis value of one. Now eight samples are required to have no more than a 20% chance of the sample set average density differing from the in-situ average density by more than 10%. If only two samples are available for the wider standard deviation, the risk that the average is incorrect increases to over 0.7.

Example 4-3. Number of COAL Site Core Samples Required Determine the number of samples required to achieve 95% statistical certainty that the COAL Site sample density is within 10% of the correct value. Assume that there is no more than a 20% chance of concluding that the average density of the samples is the same as that of the reservoir when in fact it is not. Within the density range of 1.295 g/cm3 (100% organic) to 2.4 g/cm3 (96% inorganic), the average value and standard deviation of open-hole density log data is 1.659 and 0.286 g/cm3, respectively. The value for the horizontal axis of Figure 4-5 is calculated from the 10% density difference criterion and the standard deviation. We select the value of m to be 10% greater than the in-situ value to match our 10% error criterion. This value is 1.1 times 1.659.

m - m0 1.10 (1.659 ) - 1.659 = = 0.58 s 0.286 We then notice that a vertical line from this value intersects a horizontal line at 0.2 on the vertical axis at roughly 21 samples. The range in density of the samples must be lower than the average minus the standard deviation (1.659-0.286=1.373 g/cm3) and greater than the average plus the standard deviation (1.659+0.286=1.945). The density range corresponds to an ash content range of 0.12 to 0.70. However, for GRI #1, only six samples were available. As a result, there is a 64% chance that the sample set average differs more than 10% from the in-situ average.

In practical terms, if the in-situ density does not vary much, the standard deviation is small and we do not need many samples to determine the average in-situ density. As the in-situ density variation increases, more samples are required to accurately determine the average. Example 4-3 shows you how to apply the statistical analysis to determine the number of samples required for GRI Well #1 at the COAL Site. This example shows that at least 21 samples are required due to the wide variation in in-situ density in the San Juan Basin Fruitland Formation. We cut core samples into one-foot lengths for the desorption measurements. For 95% statistical certainty, 21 feet of the 90 feet (or 23%) of the reservoir must be sampled to obtain a sample average density that is within 10% of the average reservoir density. In addition, the standard deviation of the inorganic fraction of the samples must be equal to or greater than the standard deviation of the reservoir density values. For this reason, a wide range in the sample inorganic fractions must be selected for desorption experiments As an example of a properly sized sample set, Figure 4-6

illustrates the gas vs. inorganic content correlation for the Southern Ute 5-7 well. We desorbed 26 samples with a range in inorganic content from 0.185 to 0.749. There was a much “tighter” correlation (i.e., the difference between the 95% confidence intervals was reduced) when the data encompassed the entire density range. The intercept of the zero air-dry gas content point was also much closer to one. For these data, the intercept was at 0.961. To improve accuracy, do not attempt to high-grade samples by selecting only the lowest density samples for desorption. If you do, you will have difficulties correlating gas content to density. This was the case for the six GRI Observation Well #1 samples (see Figure 4-2) that had a narrow range in inorganic content (0.394 to 0.459) when the range should have including inorganic contents from 0.12 to 0.70. GRI Observation Well #2 (see Figure 4-1) had a much greater range of sample inorganic contents (0.328 to 0.689) and had a much better correlation between gas and inorganic content. We obtained the best correlation from the Southern Ute 5-7 data with an inorganic content range of 0.185 to 0.749.

4.9

Chapter

4

Multiple Sample Analysis

Drill Cutting Gas Content vs. Inorganic Content Correlations During GRI research, we found that gas content estimates from drill cutting samples were 25% lower than from core sample based estimates. The principal causes of the errors associated with drill cutting samples are due to a reduction in the average diffusion distance and mixing with rock extraneous to the reservoir. The drill bit crushes coal drill cuttings. The largest cutting sizes Figure 4-6 are commonly about 0.25 inch in Southern Ute 5-7 Air-Dry diameter while the smallest are powGas Content vs. Inorganic Content dered. Reduction of the cutting size below the characteristic reservoir diffusion distance collected in a strainer and washed with water to remove increases the diffusivity of the sample by the ratio of the drilling mud. The washing contributed to greater moisparticle size squared. Consequently, the samples tend ture content. We created a hypothetical example to investigate to lose gas much more rapidly than would be the case the effect of contamination upon gas content vs. inorif crushing had not occurred. The lost gas content tends ganic content correlations. Table 4-4 lists hypothetical to be underestimated. Usually, the correlation between gas content and data where coal samples from a coal seam with a range inorganic content is poor for drill cutting samples. In of ash contents were mixed with differing proportions our studies, contamination was the another cause of of extraneous rock. This example was computed aslack of statistical significance in drill cutting gas con- suming that the coal, ash, and extraneous rock density tent vs. inorganic content relationships. Mixing con- was 1.25, 2.2, and 2.6 g/cm3, respectively. The organic taminated the samples with rock and extraneous material from outside the reservoirs. Extraneous material Coal Ash Other Rock MixtureAsh Mixture includes drilling mud additives such as lost circulation Content by Volumetric Content Gas material and barite. Since the extraneous material was Weight Fraction Content fraction fraction fraction scf/ton generally of different density than the ash fraction, and 0 0.5 0.675 194.8 since the extraneous rock and material fractions were 0.2 0.2 0.458 391.1 unknown, it was not possible to improve the correla0.5 0.3 0.706 299.6 tions. The extraneous rock was often in the density 0.4 0.7 0.880 106.8 range of 2.6 to 2.8 g/cm3. The density of lost circulation 0.6 0.1 0.658 409.4 material is similar to that of the organic material while the density of barite is approximately 4 g/cm3. 0.8 0.5 0.915 175.0 Another source of extraneous material is water. Table 4-4 Drill cutting moisture content was generally greater Hypothetical Example of Drill Cutting Gas than that of core samples from the same reservoirs. Content vs. Ash Content During the GRI research efforts, drill cuttings were

4.10

fraction gas content was assumed to be 600 scf/ton. There was perfect correlation between the coal gas content and coal ash content for this example because the gas content was computed from the coal ash content. The addition of other rock degraded the correlation. Figure 4-7 illustrates these data. The appearance of this figure is similar to a typical drill cutting gas content vs. inorganic content relationship. Regression of these data resulted in an estimate of the organic fraction gas content equal to 688.5 ± 565.3 scf/ton which was in error by +14.8% ± 94.2%. The correlation coefficient was relatively low at 0.644. The scatter in the data and the relatively few data points decreased the predicted organic fraction gas content estimate accuracy.

Figure 4-7 Hypothetical Example of Drill Cutting Gas Content vs. Ash Content

Summary In this chapter, we covered steps 3 through 5 of the gas-in-place estimate procedure in detail. These steps are: 3. 4. 5.

Relate the total gas content of multiple samples to sample composition. Relate the sample composition to density. Determine the in-situ moisture content from equi librium moisture content measurements.

We covered the correlation of multiple sample gas content estimates to inorganic content. One important aspect that we pointed out is how an insufficient range in the sample composition increases the inaccuracy of the correlation. We demonstrated the method required to relate the sample composition to density and vice versa. In Chapter 5, we will show you how to convert the organic fraction gas content to an in-situ value with open-hole density log data.

Additional Reading The subject of coal composition is a complex one. References 1 and 2 are considered the classics on this subject. The ASTM Standards13 provide much information on methods used to estimate the organic and inorganic compositions.

4.11

Chapter

4

Multiple Sample Analysis

Chapter 4 References 1. Spackman, W.: “The Maceral Concept and the Study of Modern Environments as a Means of Understanding the Nature of Coal,” Transactions of the New York Academy of Sciences, Vol. 20, No. 5, (1958) pp. 411-423. 2. Stach, E., Mackowsky, M-Th., Teichmüller, M., Taylor, G.H., Chandra, D. and Teichmüller, R.: Stach’s Textbook of Coal Petrology, 3rd Edition, Gebruder Borntraeger, Berlin, Germany (1982) 535 p. 3. Mavor, M.J., Pratt, T.J., and Britton, R.N.: Improved Methodology for Determining Total Gas Content, Volume I. Canister Gas Desorption Data Summary, Gas Research Institute Report No. GRI-93/0410, Chicago, Illinois (May 1994) 230 p. 4. Dyrkacz, G.R. and Horwitz, E.P.: “Separation of Coal Macerals,” Fuel, Vol. 61 (1982) pp. 4-12. 5. Crelling, J.C.: “Separation, Identification, and Characterizations of Single Coal Maceral Types,” in Moulijn, J.A., et al. (editors) 1987 International Conference on Coal Science, Elsevier Science Publishers, B.V., Amsterdam (1987) pp. 119-122. 6. Karas, J., Pugmire, R.J., Woolfenden, W., Grant, D.M., and Blair, S.: “Comparison of Physical and Chemical Properties of Maceral Groups Separated by Density Gradient Centrifugation,” International Journal of Coal Geology, Volume 5 (1985) pp. 315-338. 7. Pandolfo, A.G., Johns, R.B., Dyrkacz, G.R., and Buchanan, A.S.: “Separation and Preliminary Characterization of High-Purity Maceral Group Fractions from an Australian Bituminous Coal,” Energy & Fuels, Vol. 2 (1988) p. 657. 8. Neavel, R.C., Smith, S.E., Hippo, E.J., and Miller, R.N.: “Interrelationships Between Coal Compositional Parameters,” Fuel, Vol. 65 (1986) pp. 312-320. 9. Bohor, B.F. and Triplehorn, D.M.: Tonsteins: Altered Volcanic-Ash Layers in Coal-Bearing Sequences, Special Paper 286, The Geological Society of America, Boulder, Colorado (1993). 10. 1994 Annual Book of ASTM Standards, Section 5, Volume 05.05 Gaseous Fuels; Coal and Coke, American Society for Testing and Materials Philadelphia, PA (1994) p. 192. 11. Mavor, M.J.: “Coalbed Methane Reservoir Properties,” in Saulsberry, J.L., Schafer, P.S., and Schraufnagel, R.A. (editors) A Guide to Coalbed Methane Reservoir Engineering, Gas Research Institute Report GRI-94/ 0397, Chicago, Illinois (March 1996) p 4.3. 12. Bowker, A.H. and Lieberman, G.L.: Engineering Statistics, Prentice Hall, Inc., Englewood Cliffs, New Jersey (1972) pp. 183-189. 13. 1994 Annual Book of ASTM Standards, Section 5, Volume 05.05 Gaseous Fuels; Coal and Coke, American Society for Testing and Materials Philadelphia, Pennsylvania (1994).

4.12

5

Thickness, Density, and Gas-In-Place Estimates

N

ow that we have evaluated the desorption and density data, we are ready to complete the analysis by estimating the reservoir thickness, average density and in-situ gas content. This chapter discusses the final three steps of the gas-in-place procedure. These steps are: 6. Estimate the gross thickness and average in-situ density from open-hole density log data. 7. Compute the in-situ gas content at the average reservoir density and moisture content. 8. Compute the gas-in-place volume with Equation 2-1. We will convert the organic fraction gas content estimated from the multiple sample analysis such as illustrated in Figure 4-1 to an in-situ value. We will also use the estimates of the organic and inorganic densities from Chapter 4 to evaluate open-hole density log data. We will use the average in-situ density obtained from the log data to compute the in-situ gas content based upon the organic fraction gas content. Finally, we will use Equation 2-1 to compute the gas-in-place volume within a specified drainage area.

Gross Thickness and Average Density Estimates Three estimates are required from open-hole density log data: the gross thickness of coal and carbonaceous shale that contains producible gas, the average in-situ density, and the average in-situ ash content. In the previous chapter, we showed that when sufficient samples are available for statistical analysis, that the

density range of Fruitland Formation rocks containing gas ranges from the organic density, 1.295 g/ cm3, to just under the inorganic density, 2.497 g/cm3. Remember that the estimated inorganic fraction of the samples is a simple average and not an indication of the heterogeneity of the samples. For instance, a sample that has an inorganic content of 0.749 (density 2.0 g/cm 3 ) is not a uniform piece of rock. There are high organic content intervals interbedded with inorganic rock. While the average

1

Volume Analysis 0 fraction

Porosity

Density¸ 1

g/cc¸

Gas Content 3.0

scf/ton

1000

Net Pay Interval

Shale Sand Coal Ash 3050

3100

3150

3200

3250

Figure 5-1. GRI #2 Coal Log

5.1

Chapter

Thickness, Density, and Gas-In-Place Estimates

Density

Depth feet

5

1.0

g/cm3

3.0

2,960 Total Fluid Production Fraction Fluid Rates

Upper Interval

Absolute Permeability

6%

Gas: 2 MSCF/D Water: 6 STB/D

0.9 md

32%

Gas: 21 MSCF/D Water: 18 STB/D

6.0 md

3,000

Middle Interval

13% 49%

Gas: Water: Gas: Water:

10 MSCF/D 4 STB/D 46 MSCF/D 3 STB/D

1.3 md 1.4 md

3,050

3,100 Lower Interval

0%

0 md

3,130

Figure 5-2. San Juan 30-5 Density and Production Log Data inorganic content is high, the inorganic content of the low-density beds is low. The in-situ density distribution is evaluated from open-hole density log data. Figure 5-1 illustrates a processed log including the density data from GRI Well #2 at the COAL Site. The log data are a running average of the rock properties above and below the measurement point. The vertical resolution of a highresolution density log is 0.5 feet. This means that the rock 0.25 feet above and 0.25 feet below the measurement point influenced the density estimate. The vertical resolution of a conventional density log is 2 feet, one foot above and one foot below the measurement

5.2

point. When the log records a high-density value such as 2.0 g/cm3, it is likely that low-density organic beds and high-density inorganic rocks are contained within the vertical resolution. One advantage of using 12-inch core desorption samples is that the vertical dimension of the core samples is similar to the vertical resolution of the density logs. It would be better to cut core samples into ½ foot lengths when using high-resolution density logs. However, gas desorption volumes are smaller and headspace effects greater for these smaller samples, increasing measurement difficulties. The gross thickness is determined by summing the thickness of intervals of density less than the density at an inorganic content (ash + moisture content) of one. In the past, many operators have used an upper density limit of 1.75 g/cm3 that is consistent with the geologic definition of coal (70% by volume and 50% by weight of organic material). This limit underestimated the gasin-place volume by eliminating higher density intervals that contained low-density organic beds containing gas that contribute to the productive reservoir thickness. One must be careful when applying an upper density limit equal to the maximum inorganic density. The estimated thickness can include intervals with thin organic beds that are not located within reservoir intervals. These isolated beds should be eliminated from the estimates of the net thickness unless there is reason to believe that the gas can be produced.

Individual Reservoir Identification Coal gas deposits often have multiple reservoirs located in close vertical proximity. We usually estimate gas-in-place volumes for individual reservoirs if possible. However, it is very difficult to determine which coal reservoirs are isolated from other coal reservoirs. For instance, you will find it easy to identify the two separate intervals in Figure 5-1 since there is 49 feet of shale between the two major coal intervals. However, multiple coal seams are contained within each major interval. Are these coal seams individual reservoirs?

Generally, we consider an individual reservoir to be isolated from other reservoirs. If a reservoir is isolated, production from the reservoir does not affect the behavior of other reservoirs except, perhaps, through wells. One way to identify if reservoirs are separate is through production logging. Because of the great density difference between gas and water, we expect gas to flow through the upper portions of a reservoir while water flows through the lower portions. An example of potentially isolated reservoirs within a single coal interval was observed in the San Juan 305 well.1 During GRI research, we conducted well tests and measured production logs in this well. From these data, it was possible to estimate the absolute permeability and the production rates from individual coal seams as illustrated in Figure 5-2. The greatest gas production rate and the highest gas-water rate ratio was from the deepest coal seam within the middle interval. The highest water rate was produced from the shallowest coal seam in the middle interval. These results indicate that there is no vertical connection between the three coal groups in the middle interval. If they were connected, the highest gas rates should be from the shallowest coal seams and the highest water rates should be from the deepest coal seams. For the purpose of gas-in-place estimates, we find it convenient to consider the middle interval as one interval that may contain multiple reservoirs. Keep in mind that the close vertical proximity does not mean that reservoirs are connected.

In-Situ Ash Content We estimate the in-situ ash content from open-hole density data with Equation 4-6. We will use the organic and ash density values that we determined in the previous chapter. These were 2.497 and 1.295 g/cm3, for the ash and organic fraction density, respectively. An estimate of the in-situ moisture content can be obtained from equilibrium moisture content data. We will use the equilibrium moisture content determined in the lab on GRI #1 samples that we selected for sorption isotherm estimates. This value is 0.0089. Example 5-1 shows you how to make the ash content estimates. During earlier research, we documented that ash content estimates obtained from open-hole density data agreed closely with the proximate analysis results from core samples. Figure 5-3 illustrates a comparison of the ash content estimates from both data sources for the Southern Ute 36-1 well in the San Juan Basin.1

In-Situ Gas Content We compute the in-situ gas content from the in-situ ash and moisture content based upon the relationship between the air-dry gas content and the inorganic content. Use Equation 5-1 for this estimate. G c = G co [1 - (wa + wwe )]

(5-1)

Where: Gc

Figure 5-3. Comparison of S. U. 36-1 Ash Content from Logs and Core Data

in-situ gas content, scf/ton Gco organic fraction gas content, scf/ton wa ash content, weight fraction wwe equilibrium moisture content, weight fraction This relationship assumes that the intercept of the relationship at gas content of zero intersects the horizontal axis at an inorganic content of 1.0. The GRI #2 data did not intersect at this point due to insufficient density distribution in the desorption samples. However, we know from data sets that are more complete

5.3

Chapter

5

Thickness, Density, and Gas-In-Place Estimates

that the intersection would have been at one if more data were available. Example 5-1 shows you how to make the calculation. During earlier research, we documented that in-situ gas content estimates computed in this manner can agree well with those obtained from canister desorption measurements. Figure 5-4 illustrates the comparison between gas content estimates obtained from log and core desorption data for the Southern Ute 36-1 well.

In-Situ Density and Gas Figure 5-4. Content Distributions Comparison of S. U. 36-1 Gas Content One of the difficulties in estimatfrom Logs and Core Data ing the gas-in-place volume is the method used to average density log data. Interpretation corded every 0.5 feet. At least two major reservoir intervals are present in of the digital density log data results in the most thorough evaluation. You can also visually average Figure 5-1, the GRI #2 open-hole log data. Potentially, density data by selecting limited vertical intervals from there are separate reservoirs within the major intervals. the recorded open-hole density log data. Example 5-2 Table 5-1 summarizes the density distribution of the at the end of this chapter shows you how to perform this shallower interval between depths of 3,067.9 and 3,098.8 feet. We computed estimates of the in-situ ash and gas analysis. Most logging companies can provide you with a content (See Example 5-1) for each depth at which digital file containing density vs. depth data. High- density data were available. We then constructed a resolution data are usually recorded every 0.1 or 0.25 histogram of the data by separating the interval into ten feet depending upon the logging company’s software. density sub-intervals. The reservoir density range is Conventional-resolution density data are usually re- between 1.295 g/cm3 (the organic fraction density) and Example 5-1. In-Situ Ash & Gas Content Calculations Calculate the in-situ ash and gas content at one depth in the GRI #2 well. At 3,209 feet, the recorded density value was 1.389 g/cm3. Compute the in-situ ash content with an ash density of 2.497 g/cm3 and an organic density of 1.295 g/cm3. Use an equilibrium moisture content value of 0.0089. The gas content of the organic fraction is 913 scf/ton. Use Equation 4-6 to calculate the in-situ ash content.

æ 1 æ 1 1ö 1 ö æ 1 1 ö 1 ö æ1 ÷÷ ç çç - ÷÷ + ww çç ÷ + 0.0089ç ÷ r r r r 1.295 1.389 ø o ø è 1 1.295 ø = 0.146 è w ø wa = è o =è 1 1 1 1 1.295 2.497 ro ra Compute the in-situ gas content with Equation 5-1 G c = G co [1 - (wa + wwe )] = 913[1 - (0.1460 + 0.0089 )] = 771.6 scf/ton

5.4

Minimum Maximum Density Density g/cm3

g/cm3

0.000 1.295 1.412 1.529 1.646 1.763 1.880 1.996 2.113 2.230 2.347 2.464 1.295

1.295 1.412 1.529 1.646 1.763 1.880 1.996 2.113 2.230 2.347 2.464 9.990 2.464

Proportion Average of Density Average Ash Data Density Content % g/cm3 %

0.00 11.29 11.94 11.61 13.23 7.74 4.84 3.87 5.16 6.77 14.84 8.71 100.00

Average Gas Thickness Cumulative Content Thickness scf/ton feet feet

1.346 1.464 1.575 1.705 1.815 1.935 2.049 2.188 2.297 2.401

8.44 24.56 37.47 50.47 60.03 69.28 76.99 85.35 91.16 96.25

827.8 680.6 562.8 444.0 356.8 272.4 201.9 125.7 72.6 26.1

1.833

61.52

343.2

0 3.5 3.7 3.6 4.1 2.4 1.5 1.2 1.6 2.1 4.6 2.7 28.3

0 3.5 7.2 10.8 14.9 17.3 18.8 20.0 21.6 23.7 28.3 28.3

Gas-in-Place per acre MMscf/acre

Proportion Cumulative of Gas in- Proportion of Place of Gas-in-Place % %

0.000 5.303 5.014 4.339 4.220 2.113 1.075 0.675 0.598 0.476 0.392 0.000 24.206

0.00 21.91 20.71 17.92 17.43 8.73 4.44 2.79 2.47 1.97 1.62 0.00 100.00

0.00 21.91 42.62 60.55 77.98 86.71 91.15 93.94 96.41 98.38 100.00 100.00 100.00

Table 5-1 GRI #2 Upper Reservoir Gas-In-Place Summary 6

Gas-in-Place Volume per Acre, MMscf/acre

5

4

3

2

1

0 1.295

1.412

1.529

1.646

1.763

1.880

1.996

2.113

2.230

2.347

2.464

Density Intervals. g/cm3

Figure 5-5 GRI #2 Upper Reservoir Gas-In-Place Distribution

5.5

Chapter

5

Thickness, Density, and Gas-In-Place Estimates

2.464 g/cm3 (the density at an ash plus moisture content of one). Table 5-1 summarizes the density and gas distribution estimates. Figure 5-5 illustrates the gas-inplace histogram vs. density. The majority of the gas-in-place volume (78%) is contained within the sub-intervals with densities below 1.763 g/cm3. The proportion of the gas-in-place contribution from the greater density sub-intervals becomes progressively less as the density increases. However, if the gas contained in the higher density sub-intervals is not included, the gas-in-place volume is underestimated by 22% for this interval. It is possible to determine the effect of differing upper density limits upon the thickness and gas-inplace estimates with Table 5-1. For instance, at an upper limit of 1.763 g/cm3, the thickness is 14.9 feet and the gas-in-place volume is 0.7798 x 24.206 or 18.88 MMscf per acre. Increasing the density limit to the maximum inorganic fraction density increases the thickness estimate by 89.9% to 28.3 feet. The gas-in-place estimate increases by 28.2% to 24.206 MMscf/acre from the lower density range value. Increasing the upper density limit increases the average density and decreases average gas content estimates. For instance, the average density of the density range less than or equal to 1.763 g/cm3 is 1.529 g/cm3. The average of the maximum density range is 19.9% greater. The average gas content of the density interval less than or equal to 1.763 g/cm3 is 622.4 scf/ ton. The maximum density limit average gas content is 44.9% less.

Gas-in-Place Estimates The values contained in Table 5-1 can be used to calculate the gas-in-place volume within a specified drainage area. You can either use Equation 2-1 or multiply the gas-in-place per acre by the area. For instance, from Table 5-1, the gas-in-place in the upper coal gas reservoir is 24.206 MMscf/acre. In a square mile area (640 acres), the upper reservoir gas-in-place is 24.206(640)=15,492 MMscf or 15.5 Bscf. In the basal reservoir, the volume of gas-in-place per square mile is 69.957(640) = 44,772 MMscf or 44.8 Bscf. The total in both reservoirs is 60.3 Bscf in a square mile area.

5.6

You may not have access to the digital density log data to perform numerical processing. In this situation, we typically average the density log data over two foot increments on the graphical log display. Example 5-2 shows you how to perform such an estimate. This example also shows you how to make the gas-in-place estimate with Equation 2-1. The estimate obtained from the “hand” calculations of 15.1 Bscf for a 640acre area of the upper interval is similar to the digital 15.5 Bscf result.

Summary This chapter summarized the final three steps of the gas-in-place procedure. These steps are: 6. 7. 8.

Estimate the gross thickness and average in-situ density from open-hole density log data. Compute the in-situ gas content at the average reservoir density and moisture content. Compute the gas-in-place volume with Equation 2-1.

The important points that you should remember besides these three steps are: • log-derived estimates of gas and inorganic content are running averages over a 0.5 to 2 foot vertical interval, • you cannot determine whether groups of coal seams are individual reservoirs by close vertical proximity or from density log data, and • most of the gas-in-place is stored in coal (density less than or equal to 1.75 g/cm3) but a significant volume (10 to 20%) is stored in carbonaceous shale.

Additional Reading Reference 2 summarizes the usefulness of log and core data for coal gas reservoirs and outlines a procedure to evaluate newly discovered reservoirs. Reference 3 provides additional information on log analysis in coal.

Example 5-2. GRI #2 Average Density, Thickness and Gas Content. READ ME

Determine the average density distribution in two-foot increments, and use these data to estimate the average in-situ density, thickness, and gas content. Then compute the gas-in-place volume in 640 acres. The following table summarizes the 2-foot density values. Top Depth

Bottom Depth

Thickness

Average Density

feet 3,068.0 3,070.0 3,072.0 3,074.0 3,076.0 3,078.0 3,080.0 3,082.0 3,084.0

feet 3,070.0 3,072.0 3,074.0 3,076.0 3,078.0 3,080.0 3,082.0 3,084.0 3,085.0

feet 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 1.0

g/cm3 2.30 1.68 1.59 1.51 1.73 1.49 1.92 2.39 2.41

3,087.8 3,090.0 3,092.0 3,094.0 3,096.0 3,098.0 Total

3,090.0 3,092.0 3,094.0 3,096.0 3,098.0 3,099.0

2.2 2.0 2.0 2.0 2.0 1.0 28.2

2.00 1.33 2.02 1.64 1.71 2.39

Thickness Density Product g-ft/cm3 4.60 3.36 3.18 3.02 3.46 2.98 3.84 4.78 2.41 4.40 2.66 4.04 3.28 3.42 2.39 51.82

Determine the average density with a thickness-weighted average by multiplying the average density in each depth range by the thickness. The average in-situ density is the sum of the thickness-density product values divided by the thickness. In this case, 51.82/28.2=1.84 g/cm3. Compute the average ash content from the average density value as per Example 5-1. A density of 1.84 g/cm3 corresponds to an ash content of 0.62. Since the organic fraction gas content is 903 scf/ton, the in-situ average gas content is 903[1-(0.62+0.0089)]=335 scf/ton. Compute the gas-in-place in a square mile area with Equation 2-1.

(

)

G = 1359.7 Ahr c G c = 1359.7 (640 )(28.2 )(1.84 )(335 ) = 1.51 10 10 scf or 15.1 Bscf

5.7

Chapter

5

Thickness, Density, and Gas-In-Place Estimates

Chapter 5 References 1. Mavor, M.J., Logan, T.L., and Robinson, J.R.: Cooperative Evaluation of San Juan Basin, Phillips Petroleum Company, Openhole Well Recompletion Efforts, Gas Research Institute Topical Report No. GRI-93/ 0466, Chicago, Illinois (July 1995) 105 p. 2. Mavor, M.J., Close, J.C., and McBane, R.A.: “Formation Evaluation of Exploration Coalbed Methane Wells,” Coalbed Methane, SPE Reprint Series No. 35, Society of Petroleum Engineers, Richardson, Texas (1992). pp. 27-45. also in SPE Formation Evaluation (December 1994) pp. 285-294. 3. Scholes, P.L. and Johnston, D.: “Coalbed Methane Applications of Wireline Logs,” in Law, B.E. and Rice, D.D. (editors): Hydrocarbons from Coal, AAPG Studies in Geology #38, American Association of Petroleum Geologists, Tulsa, Oklahoma (1993) pp. 287-302.

5.8

6 Chapter

G

Coal Gas Sorption & Storage Capacity

as-in-place in coal seams is stored by sorption as opposed to compression as in conventional gas reservoirs. You must understand the sorption phenomena to predict the gas recovery. Once you complete the gas content and gas-in-place estimates, you will find that sorption isotherm data, that relate storage capacity to pressure, can be very useful. This is especially true when the in-situ storage capacity is equal to the gas content, i.e., when the reservoirs are saturated. When saturated, you can use the storage capacity information to adjust gas content data for differences in depth and reservoir pressure. Undersaturation (i.e., initial gas content less than storage capacity) reduces the gas-in-place volume but even more dramatically reduces gas production rates and recovery. Because of the dependence of productivity and recovery upon the degree of saturation, it is very important that accurate gas content and storage capacity estimates be available to forecast future gas production rates. An alternative method of estimating gas content is to assume that the gas content of the reservoirs is equal to the maximum value possible, i.e., the gas storage capacity This assumption is very dangerous. Gas-inplace estimates should be based upon measured core desorption data as discussed in the previous chapters. Gas content can be significantly less than the gas storage capacity. However, sorption data are still important. They serve as check on the gas content data (i.e., gas content estimates should be less than or equal to storage capacity). More importantly, they are required to predict the recovery of the gas-in-place when production reduces the average reservoir pressure.

Sorption at the Molecular Level Solid surfaces attract gas molecules in close proximity to the solid surfaces. This is the phenomenon known as sorption. The attraction causes the molecules to pack closer together than if the surface is not present. Since the molecules are closer together, the gas density is greater near the surface that it is away from the surface. In a microporous material such as coal, the molecules in the pores become closely packed. The packing causes the effective density of the sorbed gas to approach the density of the molecules when in a liquid state at atmospheric pressure. The high effective sorbed gas density explains why much greater volumes of gas can be stored in coal seams than in conventional gas reservoirs at shallow depths (i.e., at depths less than 7,000 feet or so). For instance, the sorbed density for methane,1 is 0.421 g/ cm3. In contrast, the density of methane in the vapor state at 1,600 psia and 125o F. is 0.0747 g/cm3 or 5.6 times less than the sorbed methane density. This pressure and temperature condition was common in the San Juan Basin Fruitland Formation commercial coal reservoirs in 1980. Coal matrix pore spaces are separated into two size ranges, micropores with a characteristic width of less than 2 nm, (A nanometer, nm, equals 10-9 meters.) and mesopores having widths between 2 and 50 nm. The equivalent molecular diameter of methane is roughly 0.4 nm. The smallest pores are only 5 times larger than methane molecules. The small pore sizes cause a very large surface area to volume ratio. The larger this ratio, the greater the surface area causing attraction between gas molecules

6.1

Chapter

6

Coal Gas Sorption & Storage Capacity

and rock. For instance, the internal matrix porosity of high volatile A bituminous coal is between four and eight percent of the bulk volume. Five- percent porosity corresponds to a pore volume of roughly 0.01 ft3 per pound of coal. The internal surface area of a pound of coal is in the range of 1,000,000 square feet. The ratio of the surface area to the pore volume is about 108 ft2/ ft3. The volume of gas stored in coal can be very large. As an example, a San Juan Basin Fruitland Formation coal sample from the GRI COAL Site research location can sorb 913 scf of gas per cubic foot of organic material. The commercial coal gas reservoirs at this location contain 43% inorganic material also. At in-situ conditions, with the dilution due to inorganic material, the sorbed gas content is 512 scf/ton. Part of the reason for the high gas-in-place volume at this location is that the sorbed gas also contains carbon dioxide. In this coal, the storage capacity of carbon dioxide is 2.8 times greater than that of methane. The term coalbed methane is misleading. Coal seam gas often contains substantial quantities of gases besides methane. You must often account for the composition of the coal gas to estimate the economic value of the gas-in-place. Gas storage capacity is a function of coal properties and reservoir conditions. The coal properties include maceral composition, rank, matrix porosity, organic content, and moisture content. Storage capacity varies with pressure and temperature. As pressure increases, the gas storage capacity increases. As temperature increases, the gas storage capacity decreases.

ture (hence the name) that usually is equal to the reservoir temperature. The Langmuir isotherm relationship follows.

G s = G sL [1 - (wa + wwe )]

p p + pL

Where: Gs GsL wa wwe p pL

gas storage capacity, scf/ton dry, ash-free Langmuir storage capacity, scf/ton ash content, weight fraction equilibrium moisture content, weight fraction pressure, psia Langmuir pressure, psia

The ash plus moisture content is the inorganic content of the coal sample. The inorganic content of sorption samples is determined by a proximate analysis. The Langmuir model assumes that molecules compete for storage sites in a layer that is one molecule thick on the solid organic surface area. Competitive molecules include hydrocarbon and non-hydrocarbons such as water, carbon dioxide, and nitrogen. Eventually, at high pressures, all of the storage sites become occupied if sufficient molecules are available. At this point, the storage capacity will reach a constant value

The Langmuir Isotherm The most common model used to relate storage capacity to organic content, moisture content, and pressure is the Langmuir isotherm.2 This model relates the equilibrium sorbed gas capacity to the pressure of the gas outside of the coal matrix. Laboratories measure the isotherm data at a constant temperaFigure 6-1 Example Langmuir Isotherm Relationship

6.2

(6-1)

equal to the Langmuir storage capacity. The Langmuir pressure is equal to the pressure at which the storage capacity is equal to half the Langmuir storage capacity. The isotherm relationship is very important in coal gas reservoir engineering as it is used to estimate three essential items illustrated in Figure 6-1. These are:

can compute the gas recovery factor as a function of the average pressure using Equation 6-3. Example 6-1 shows you how to apply Equations 6-2 and 6-3.

1. the pressure at which gas release (desorption) begins, 2. the amount of gas released as pressure is reduced, and 3. the gas remaining in the reservoir at abandonment.

Where: fg = fractional gas recovery, demensionless p = average reservoir pressure, psia

The gas storage capacity at the initial reservoir pressure is the maximum amount of gas that may be sorbed in a reservoir. The gas content is the actual gas sorbed within the rock. This distinction is important, since gas content can be substantially less than gas storage capacity. You must determine the correct insitu gas content by desorption measurements. The critical desorption pressure is the pressure in the coal natural fracture system at which gas desorption from the rock matrix begins. This pressure is equal to the pressure at which the gas content and storage capacity are equal. The critical desorption pressure can be substantially less than the initial reservoir pressure since the isotherm relationship is relatively “flat” in the higher pressure range. You can compute the critical desorption pressure with Equation 6-2.

p L Gci pc = GsL [1 - (wa + wwe )] - Gci

(6-2)

Where: pc critical desorption pressure, psia Gci initial gas content, (in-situ basis) scf/ton Once the pressure drops below the critical desorption pressure, the isotherm relates the gas storage capacity (which is now equal to the gas content) to pressure. You can compute the remaining gas content as a function of pressure with the Langmuir relationship, Equation 6-1. The gas recovery factor is one minus the ratio of the remaining gas content to the initial gas content. You

fg = 1 -

G sL [1 - (wa + wwe )] p (6-1) Gci ( p + p L )

The abandonment reservoir pressure can be difficult to determine as it is affected by a combination of reservoir properties and economics. The abandonment pressure is the average pressure of each reservoir when the operator shuts in wells due to gas rates less than minimum economic rates. The average pressure is equal to the pressure at which the reservoir would eventually stabilize and is greater than the pressure in the wells when production ceases. The stabilization pressure is a function of location, permeability, and depth. You can estimate the abandonment pressure using a reservoir simulation model that incorporates structural geometry and the variation in permeability throughout the reservoirs. As for all core analysis data, sorption isotherm data are subject to errors. Reference 3 discusses an evaluation of these errors.

Isotherms for Multiple Gas Components The gas recovered from coal seams often contains significant amounts of molecules other than methane including carbon dioxide, nitrogen, water, and heavier molecular weight hydrocarbons. You must use sorption isotherm relationships for a gas mixture if the reservoir that you are evaluating has multiple components. You can compute multicomponent isotherm relationships from single component data by extended Langmuir isotherm theory. The extended Langmuir isotherm relationship is listed in Equation 6-4.1 G si = G sLi [1 - (wa + wwe )]

py i p Li 1+ p

nc

(6-4)

yj

åp j =1

Lj

6.3

Chapter

6

Coal Gas Sorption & Storage Capacity

Where: = multicomponent storage capacity of component i, in-situ basis, scf/ton GsLi = single component Langmuir storage capacity of component i, dry, ash-free basis, scf/ton pLi or pLj = single component Langmuir pressure of component i or j, psia yi or yj = mole fraction of component i or j in the free gas (vapor) phase, dimensionless nc = number of components p = pressure of the free gas phase, psia

Gsi

Carbon dioxide has a significant influence upon the storage capacity estimated for some San Juan Basin Fruitland Formation coals as illustrated by Figure 6-2. The COAL Site that has been the subject of the examples in this book has an in-situ storage capacity of 513 scf/ton. Twenty-one percent of the storage capacity is due to the presence of carbon dioxide in the sorbed gas although the produced gas composition contained only 13% carbon dioxide. Example 6-2 shows you how to apply Equation 64. Figure 6-2 illustrates three COAL Site isotherms for methane, carbon dioxide, and a binary isotherm. The binary isotherm was com-

puted with extended Langmuir theory as a function of pressure in the same manner as Example 6-2 with pressure ranging from zero to 2,000 psia. We know that the coal gas reservoirs at the COAL Site were saturated since gas was produced during drill stem tests conducted while drilling. Only a few wells had been on production for a few months in the nearby area. If the reservoirs had been undersaturated, gas would not have been produced during the drill stem tests. Gas content estimates were also in agreement with the storage capacity estimates. Two wells at the COAL Site were cored and samples were placed in desorption canisters. The gas storage capacity on a dry,

Figure 6-2 COAL Site Multicomponent Isotherm Relationships

Example 6-1. Estimate Important Reservoir Conditions READ ME

The basis of the isotherm relationship in Figure 6-1 was a Langmuir volume of 786.8 scf/ton and a Langmuir pressure of 334.3 psia. Calculate the critical desorption pressure if the gas content is 355 scf/ton. The ash content is 0.30 (30%) and the moisture content is 0.01 (1%). Use Equation 6-2.

pc =

(334.3)355 = 632 psia 786.8[1 - (0.30 + 0.01)] - 355

Calculate the gas recovery factor at an abandonment pressure of 100 psia using Equation 6-3. fg = 1 -

6.4

786.8 [1 - (0.30 + 0.01)]100 = 0.648 355(100 + 334.3 )

Example 6-2. COAL Site Multicomponent Storage Capacity READ ME

The GRI COAL Site research location has a vapor phase gas composition that is 87% methane and 13% carbon dioxide. Compute the binary storage capacity based upon the isotherm data listed below for the basal coal interval. Also, estimate the fraction of carbon dioxide in the sorbed state. The average in-situ ash content and moisture content are 43% and 0.89%, respectively. The reservoir pressure is 1,550 psia. Component Number 1 2

Component

Dry, Ash Free Langmuir Volume

Methane Carbon Dioxide

Langmuir Pressure

scf/ton 1,116 3,124

psia 606 964

Based upon Equation 6-4, the methane storage capacity at reservoir conditions is:

1,550(0.87 ) 606 G S 1 = 1,116 [1 - (0.43 + 0.0089 )] = 406 scf/ton é 0.87 0.13 ù 1 + 1,550 ê + ë 606 964 úû Also based upon Equation 6-4, the carbon dioxide storage capacity at reservoir conditions is: 1,550(0.13) 964 = 107 scf/ton G S 2 = 3,124[1 - (0.430 + 0.0089 )] é 0.87 0.13 ù 1 + 1,550 ê + ë 606 964 úû The total storage capacity is the sum of the storage capacity of each component or 513 scf/ton. The fraction of carbon dioxide in the sorbed state is 107/513=0.209. ash-free basis was 913 scf/ton. The gas content estimates obtained from samples from two wells were 909 and 911 scf/ton. Produced gas composition will change over time in reservoirs with multiple sorbed gas components. At the COAL Site, the carbon dioxide content of the produced gas is expected to increase as the reservoir is depleted. Prediction of changes in produced gas composition has been discussed by a number of authors. Refer to Reference 1 for more information.

equation for the gas-in-place within the coal natural fracture system is as follows.

Free Gas-in-Place Volume Coal gas reservoirs also contain gas stored by compression in the natural fracture system. This volume is usually small in comparison to the volume stored by sorption in the coal matrix porosity. The

Sg

Where: Gf A h ff

Bg

Gf =

43560 Ahf f S g

(6-5)

Bg

= gas volume in the coal natural fracture sys tem, scf = drainage area, acres = reservoir thickness, feet = natural fracture porosity, fraction of bulk volume = gas saturation in the natural fracture poros ity, fraction of natural fracture porosity = gas formation volume factor, reservoir volume / surface volume

6.5

Chapter

6

Coal Gas Sorption & Storage Capacity

Estimates of the gas saturation are possible from production data if relative permeability data are available using methods developed for well test analysis.4 The gas formation volume factor is defined as follows. Bg =

p sc z (T + 459.69 ) z sc (Tsc + 459.69 ) p

(6-6)

Where: psc zsc Tsc z T p

= pressure at standard conditions, psia = real gas deviation factor at standard conditions, dimensionless = temperature at standard conditions, oF = real gas deviation factor at reservoir conditions, dimensionless = temperature at reservoir conditions. oF = pressure at reservoir conditions, psia

The real gas deviation factor estimates are obtained from correlations as a function of gas composition, temperature, and pressure.5 The volume of gas contained within the coal natural fracture system at the time of first production is small for two reasons. First, the coal natural fracture system is typically less than 2% of the reservoir bulk volume. Second, in many reservoirs, (but not in all), the natural fractures are initially full of water. Example 63 illustrates the application of Equations 6-5 and 6-6 to prediction of the gas volume contained within the coal natural fracture system at the COAL Site.

Solution Gas-in-Place Volume Gas is also dissolved in the water contained within the natural fracture system. This volume is small relative to the volume of gas stored by sorption within the reservoir. Equation 6-7 presents a relationship for this volume.

Example 6-3. Maximum Gas-In-Place in the COAL Site Natural Fracture System At the GRI COAL Site, we wished a rough estimate of the maximum gas volume that was in the coal natural fracture system at the time of initial production. We did not have accurate estimates of the natural fracture porosity but knew that it must be less than 2% of the bulk volume. We estimated the gas saturation in the natural fracture system from production data and relative permeability data. We computed the formation volume factor with Equation 6-6 for a gas composed of 87% methane and 13% carbon dioxide at reservoir conditions of 120 oF and 1,550 psia. Standard conditions were 60o F. and 14.696 psia. We computed the maximum gasin-place volume using Equation 6-5 and the information summarized in the following table.

Property Drainage area Thickness Maximum natural fracture porosity Average gas saturation Gas formation volume factor Initial gas-in-place per square mile

Units acres feet fraction fraction reservoir volume / surface volume Bscf

Upper Coal Interval Value 640 28.3 0.02 0.192 9.15(10-3) 0.33

Basal Coal Interval Value 640 61.7 0.02 0.192 9.15(10-3) 0.72

The initial gas-in-place volume in the natural fracture system for both intervals was 1.05(109) scf or 1.05 Bscf (billion standard cubic feet). This volume is 1.7% of the sorbed gas-in-place volume of 60.28 Bscf (See Example 2-1). Because of the high porosity estimate, we expect this natural fracture initial gas-in-place estimate to be a maximum limit.

6.6

Bw

(6-7)

Where: GD Sw Rsw Bw

= = = =

dissolved gas volume, scf water saturation, volume fraction solution gas-water ratio, scf/STB water formation volume factor, reservoir volume / surface volume

The dissolved water volume is typically small since the natural fracture porosity is low and the solution gas-water ratio is relatively low. The solution gas water ratio ranges between 4 and 12 scf/STB for the pressure and temperature conditions generally found in commercial coal seam gas reservoirs.6 At the COAL Site, the solution gas-water ratio was roughly 11 scf/ STB. The maximum volume of gas dissolved in the water was 0.14 and 0.30 Bscf for the upper and basal intervals, respectively. The dissolved gas volume was less than half the maximum volume of gas stored by compression in the natural fractures and roughly 0.7% of the volume stored by sorption within the coal matrix.

Use of Isotherm Data for Saturated Reservoirs Once you know that gas content and storage capacity are equal, sorption isotherm data become very useful. You can use the isotherm relationship to esti-

mate reserves and to adjust gas content data for differences in reservoir pressure. When you perform these estimates for wells without gas content data you must be careful that the coal rank and organic composition do not vary from those penetrated by the cored wells. You can adjust the organic fraction gas content estimate for pressure and inorganic content as a function of depth by combining the isotherm relationship with the in-situ gas content relationship. estimated (saturated) in-situ gas content, scf/ton

) Gc = G sL [1 - (wa + wwe )]

( pa + Ñp R d R ) ( pa + Ñp R d R ) + p L

(6-8)

Where: ) G c = estimated (saturated) in-situ gas content, scf/ ton GsL = organic fraction Langmuir storage capacity, scf/ton wa = ash content, weight fraction wwe = equilibrium moisture content, weight fraction pa = atmospheric pressure psia pR = reservoir pressure gradient, psi/ft dR = reservoir depth, feet pL = Langmuir pressure, psia

∆

GD =

43560 Ahf f S w Rsw

You can apply Equation 6-8 to each measured point of open-hole density log data to compute the gas content as a function of pressure and inorganic content.

Example 6-4. COAL Site Isotherm-Based Gas Content Estimate. Use Equation 6-8 to estimate the gas content at a depth of 3,209 feet in the GRI #2 well. The density at this depth is 1.389 g/cm3. Example 5-1 showed you how to estimate an ash content of 0.146 corresponding to this density value. The equilibrium moisture content is 0.0089. The reservoir pressure gradient is 0.481 psi/ ft. The two component Langmuir parameters based upon the single component isotherm parameters summarized in Example 6-2 are GsL = 1,288.4 scf/ton and pL = 636.7 psia. The in-situ storage capacity and thus an estimate of the in-situ gas content is computed as follows. ) G c = 1288.4 [1 - (0.146 + 0.0089 )]

(12.5 + (0.481)3209 ) = 773 scf/ton (12.5 + (0.481)3209 ) + 636.7

This is similar to the estimate of 771.6 scf/ton obtained in Example 5-1.

6.7

Chapter

6

Coal Gas Sorption & Storage Capacity

Compute the in-situ ash content prior to the gas content with Equation 4-6. Then compute the gas content with Equation 6-8. You can complete the log analysis by determining the gas-in-place in the manner illustrated by Example 5-1 with digital log data and computer software or Example 5-2 for calculator-based methods. See Example 6-4 for an example of application of Equation 6-8.

Summary The sorption phenomenon dominates gas storage in coal seams. Sorption is caused by micro- and mesoporosity that have a very large surface area to volume ratio, resulting in attractive forces between the gas molecules and the solid surface. The attraction causes the sorbed gas density to approach liquid density. Sorption isotherm data are required to predict the volume of gas released from the coal as the pressure in the coal natural fracture system is reduced. These data allow you to predict the fraction of the gas that can be extracted from the resource. These data also provide an upper bound for the maximum gas content that can be stored in the coal seams. You should not assume that the gas content is equal to the storage capacity. You should estimate the gas content by desorption of multiple coal samples reheated to reservoir temperature. Coal seam gas often contains significant quantities of components other than methane. When this is the case, multicomponent isotherms should be computed from single component data to estimate the in-situ storage capacity. When reservoirs are saturated, you can combine sorption isotherm relationships with log data and reservoir pressure data to estimate gas content and thus gasin-place for each measured log data point. Additional Reading There has been a great mass of literature published on the sorption phenomena. An excellent review of this information for coal gas reservoirs is included in Reference 7 . Additional applications of sorption theory are discussed in Reference 8.

6.8

Chapter 6 References 1. Arri, L.E., Yee, D., Morgan, W.D., and Jeansonne, M.W.: “Modeling Coalbed Methane Production with Binary Gas Sorption,” Paper SPE 24363, SPE Rocky Mountain Regional Meeting held in Casper, Wyoming, May 18-21, 1992. 2. Langmuir, I.: “The Adsorption of Gases on Plane Surfaces of Glass, Mica, and Platinum,” Journal of the American Chemical Society, Vol 40 (1918) pp. 1,361-1,403. 3. Mavor, M.J., Pratt, T.J., and Britton, R.N.: Improved Methodology for Determining Total Gas Content, Volume I. Desorption Data Summary, Gas Research Institute Report No. GRI-93/0410, Chicago, Illinois (May 1994) pp. 16-19. 4. Mavor, M.J. and Robinson, J.R.: “Analysis of Coal Gas Reservoir Interference and Cavity Well Tests,” Paper SPE 25860 presented at the 1993 Joint Rocky Mountain Regional and Low Permeability Reservoirs Symposium held in Denver, Colorado, April 26-28, 1993. 5. Standing, M.B.: Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems, Reinhold Publishing Corp., New York (1952) 122 p. 6. Dodson, C.R. and Standing, M.B.: “Pressure-Volume-Temperature and Solubility Relations for Natural Gas-Water Mixtures,” Drilling and Production Practice, American Petroleum Institute (1944) pp. 173-179. 7. Yee, D., Seidle, J.P., and Hanson, W.B.: “Gas Sorption on Coal and Measurement of Gas Content,” in Law, B.E. and Rice, D.D. (editors): Hydrocarbons from Coal, AAPG Studies in Geology #38, American Association of Petroleum Geologists, Tulsa, Oklahoma (1993) pp. 203-218. 8. Mavor, M.J.: “Coalbed Methane Reservoir Properties” in Saulsberry, J.L., Schafer, P.S., and Schraufnagel, R.A. (Editors): A Guide to Coalbed Methane Reservoir Engineering, Gas Research Institute Report GRI-94/ 0397, Chicago, Illinois (March 1996) pp. 4.2-4.9.

6.9

Chapter

6.10

6

Coal Gas Sorption & Storage Capacity

7

Additional Problems

Chapter

The additional problems included in this chapter are examples of the material presented earlier in this book.

Problem 7-1. Valencia Canyon 32-1 Gas-in-Place Compute the gas-in place in a 320-acre area for each interval based upon the following parameters. Parameter

Units

Drainage area Thickness Average in-situ density Average gas content Gas-in-place Bscf

acres feet g/cm3 scf/ton

Upper Coal Interval Value 320 20 1.71 323

Intermediate Coal Interval Value 320 43 1.56 425

Basal Coal Interval Value 320 31 1.52 460

Table 7-1.Problem 7-1 Parameters. Use Equation 2-1.

G = 1359.7 Ahr Gc

(2-1)

Where: G A h r Gc

= = = = =

gas-in-place volume, scf reservoir area, acres reservoir thickness, feet average in-situ rock density at the average in-situ rock composition, g/cm3 average gas content at the average in-situ rock composition, scf/ton

7.1

Chapter

7

Additional Problems

Problem 7-1. Solution The solution to this problem is listed in the following table. Parameter

Drainage area Thickness Average in-situ density Average gas content Gas-in-place

Units

acres feet g/cm3 scf/ton Bscf

Upper Coal Interval Value 320 20 1.71 323 4.81

Intermediate Coal Interval Value 320 43 1.56 425 12.40

Basal Coal Interval Value 320 31 1.52 460 9.43

Table 7-2. Problem 7-1 Solution. The total gas-in-place in the 320-acre area is 26.64 Bscf. The calculations for each interval are as follows. Upper Interval

( )

G = 1359.7 Ahr Gc = 1359.7 (320)(20 )(1.71)(323) = 4.806 10 9 scf or 4.81 Bscf Intermediate Interval

( )

G = 1359.7 Ahr Gc = 1359.7 (320)(43)(1.56 )(425) = 1.240 1010 scf or 12.40 Bscf

Basal Interval

( )

G = 1359.7 Ahr Gc = 1359.7 (320)(31)(1.52)(460) = 9.431 10 9 scf or 9.43 Bscf

7.2

Problem 7-2. Desorption Volume Correction and Gas Content Correct the incremental desorption volume for the first measured point from sample 34-1 from the Valencia Canyon 32-1 well for headspace expansion and measurement conditions. Table 7-3 lists all required data. The procedure for this problem is as follows. 1.

Compute the standard condition correction factor with Equation 3-2.

C sci =

p ai (Tsc + 459.69 ) p sc (Tai + 459.69 )

(3-2)

Where: Csci Tsc pai Tai psc

= = = = =

standard condition correction factor at time i, dimensionless temperature at standard conditions, oF. atmospheric pressure at time i, inches Hg ambient temperature at time i, oF. pressure at standard conditions, inches Hg

2.

Compute the headspace-corrected volume with Equation 3-3.

é pa (i -1 ) (Tci + 459.69 ) ù é Tai + 459.69 ù v hi = v v ê - 1ú ê ú êë pai (Tc (i -1) + 459.69 ) úû ë Tci + 459.69 û

Where:

(3-3)

headspace correction at time i, cm3 canister internal void (headspace) volume, cm3 atmospheric pressure at time i-1, inches Hg canister temperature at time i, oF. canister temperature at time i-1, oF.

vhi vv pa(i-1) Tci Tc(i-1)

= = = = =

3.

Compute the corrected incremental desorption volume with Equation 3-1. v sci = C sci (vi - v hi )

(3-1)

Where: vsci vi

= standard condition desorption volume at time i, cm 3 = measured desorption volume at time i, cm3

4.

Compute the cumulative corrected desorption volume with Equation 3-4.

Vsci = Where: Vsci j

i

åv

scj

(3-4)

j =1

= cumulative measured desorption volume at time i corrected to standard conditions, cm3 = summation index

7.3

Chapter 5.

7

Additional Problems

Compute the cumulative desorbed gas content with Equation 3-5.

DGcadi = 32.0368

Vsci mad

Where: DGcadi = = mad

measured gas content at time i, air-dry basis, scf/ton air-dry mass, g

Example 3-1 of this book shows you how to perform these calculations.

7.4

Well Identification Canister Data Canister No. 12-44 Valencia Canyon 32-1 g 4,140 Bowen & Edwards Empty Weight g 6,349 La Plata County Filled Weight cc 2,403 Empty Volume Colorado Sec. 32 T33N R11W cc 889 Headspace Volume Sample Data Valencia Canyon 34-1 Core Run Identification Sample ID No. Formation Fruitland Air-Dry Weight g 2,127 Coal Interval Intermediate Sample Volume cc 1,514 Core Run # 2 Ash Content fraction 0.4845 Sample Top Depth feet 1,774.0 Moisture Content fraction 0.0696 Sample Bottom Depth feet 1,774.8 Residual Gas Content scf/ton 0.00 Coring Fluid Density ppg 10.2 Misc. Information Pressure at standard conditions: 30.01 in Hg Reservoir Data Temperature Deg. F 100 Temperature at standard conditions: 60 Deg. F. Pressure Gradient psi/ft 0.526 Interpretation Parameters Reservoir Pressure psia Recovery Times 11/23/90 13:47:00 Time when the top of the sample was cored Fluid Hydrostatic Pressure psia 11/23/90 14:44:00 Time when the core barrel started out of the well Temp. Recovery Time hours Des. Time Correction 11/23/90 16:45:00 Time when the core barrel reached surface hours End of Temp. Recovery 11/23/90 17:01:08 Time when the sample canister was sealed hours*0.5 Time at time zero Start of Regression hours*0.5 Time at measurement start End of Regression hours*0.5 Corrected Data Time Uncorrected Data Measurement Conditions Canister Ambient Ambient Cumulative Cumulative Date & Time Desorption Square Root Incremental Desorbed Volume Temperature Temperature Pressure Desorbed Desorbed Desorbed Time of Volume Gas Content Volume Desorption Time mm/dd/yy hh:mm:ss hours hours*0.5 cc cc Deg. F Deg. F Inches Hg cc @ STP scf/ton 11/23/90 17:01:08 0 0 25 25 23.93 11/23/90 17:11:00 340 340 91 75 23.93 11/23/90 17:16:00 130 470 91 75 23.93 11/23/90 17:24:00 185 655 91 75 23.93 11/23/90 17:30:00 115 770 91 75 23.93 11/23/90 17:36:00 115 885 91 75 23.93 11/23/90 17:42:00 120 1,005 91 75 23.93 11/23/90 17:48:00 110 1,115 91 75 23.93 11/23/90 17:58:00 160 1,275 88 75 23.93 11/23/90 18:08:00 180 1,455 88 75 23.93 11/23/90 18:18:00 165 1,620 88 75 23.93 11/23/90 18:32:00 200 1,820 88 75 23.93 11/23/90 18:47:00 220 2,040 88 75 23.93 11/23/90 19:04:00 230 2,270 88 75 23.93 11/23/90 19:22:00 255 2,525 90 75 23.93 11/23/90 19:46:00 295 2,820 90 75 23.93 11/23/90 20:17:00 370 3,190 90 75 23.93 11/23/90 20:42:00 290 3,480 90 75 23.93 11/23/90 21:02:00 220 3,700 89 75 23.93 11/23/90 21:50:00 430 4,130 89 75 23.93 11/23/90 22:15:00 240 4,370 88 75 23.93 Well Name Operator County State Section Field

Table 7-3. Problem 7-2 Core Desorbtion Data Sheet

7.5

7

Chapter

Additional Problems

Problem 7-2. Solution The solution to this problem for the first measured point at 11/23/90 17:11 is as follows. Standard Condition Correction Factor

C sci =

p ai (Tsc + 459.69 ) 23.93(60 + 459.69 ) = = 0.775 p sc (Tai + 459.69 ) 30.01(75 + 459.69 )

Headspace Correction

é pa (i -1 ) (Tci + 459.69) ù é Tai + 459.69 ù é 23.93(91 + 459.69) ù é 75 + 459.69 ù = 889ê - 1ú ê v hi = v v ê - 1ú ê ú ú ë 23.93(25 + 459.69 ) û ë 91 + 459.69 û êë pai (Tc (i -1) + 459.69 ) úû ë Tci + 459.69 û v hi = 889(0.1362)(0.971) = 117.63 cm 3 Corrected Incremental Desorption Volume

v sci = C sci (vi - v hi ) = 0.7750(340 - 117.6 ) = 172.4 cm 3 Cumulative Corrected Desorption Volume Since this is the first point, i =1 i

Vsci =

åv

scj

= v sc1 = 172.4 cm 3

j =1

Cumulative Desorbed Gas Content

DGcadi = 32.0368

7.6

Vsci 172.4 = 32.0368 = 2.6 scf/ton mad 2127

Problem 7-3. Time Zero and Direct Method Horizontal Axis Value Estimate time zero for the Direct Method graph for sample 34-1 collected from the Valencia Canyon 32-1 well. Also, compute the Direct Method horizontal axis value for the first measured point. All necessary information is contained in Table 7-3. Assume that the reservoir is saturated. The time zero estimate procedure is as follows. Examples 3-2 and 3-3 of this book show you how to perform the calculations. 1. 2.

Calculate the sample depth by averaging the top and bottom sample depths. Compute the reservoir pressure with Equation 3-11. p R = p a + Ñp R d R

(3-11)

Where: = = =

pR ∇pR dR

reservoir pressure, psia reservoir pressure gradient, psi/ft sample subsurface (reservoir) depth, feet

Convert pa in inches of mercury to psia by multiplying by 0.4898. 3.

Where:

Compute the coring fluid hydrostatic pressure with Equation 3-10. p m = p a + 0.052 r m d R

(3-10)

pm pa rm

= mud (coring fluid) hydrostatic pressure, psia = ambient (atmospheric) pressure, psia = mud (coring fluid) density, pounds per gallon

4.

If the hydrostatic pressure is less than or equal to the reservoir pressure, time zero occurs when the sample is cored. If the hydrostatic pressure is greater than the reservoir pressure, estimate time zero by interpolation between the time that the sample leaves bottom and reaches surface with Equation 3-12.

Where: ∆tR0 ∆tRs

é p - pR ù Dt R0 = Dt Rs ê m ú ë pm - pa û

(3-12)

= elapsed time between time raised above the original depth and time zero, hours = elapsed time between time raised above the original depth and time when at surface, hours

You will have to convert military time in hh:mm:ss format to decimal hours. Do the conversion with the following relationship.

æ min utes ö æ sec onds ö t = hours + ç ÷+ç ÷ è 60 ø è 3600 ø 5.

Add ∆tR0 to the time that the core barrel started out of the well to estimate time zero.

7.7

Chapter

7

Additional Problems

The Direct Method horizontal axis calculation procedure is as follows. Example 3-3 of this book shows you how to perform the calculations. The definition of the Direct Method horizontal axis was given by Equation 3-13. t DM =

(ti - t0 ) - t dc

(3-13)

Where: Direct Method horizontal axis value (square root of desorption time), hours½ measured desorption time i, hours time zero, hours desorption time correction

tDM ti to tdc

= = = =

1.

Compute the elapsed time from time zero for the first measured point.

2.

Subtract the desorption time correction from the elapsed time. The desorption time correction is the elapsed time (decimal hours) between the first measured point and the time when the canister was sealed. The first measured point is the second point in Table 7-3.

3.

Take the square root of the difference.

7.8

Problem 7-3. Solution The solution to this problem is as follows. Sample Average Depth This is the arithmetic average of the sample top and bottom depths. d R = 0.5 (1774.0 + 1774.8 ) = 1774.4 ft

Reservoir Pressure p R = p a + Ñp R d R = [0.4898 (23.93 )] + 0.526 (1774.4 ) = 945.1 psia

Coring Fluid Hydrostatic Pressure p m = p a + 0.052 r m d R = [0.4898 (23.93 )] + [0.052(10.2 )(1774.4 )] = 952.9 psia

The hydrostatic is slightly greater than the reservoir pressure. Therefore, desorption did not begin until after coring ended and the core barrel was lifted off bottom. Compute time zero by interpolating between the times that the core barrel started out of the well and reached surface with Equation 3-12. Time Zero The time that the core barrel started out of the well was 11/23/90 14:44 hours or 14.7333 hours. The pressure at this time was equal to the coring fluid hydrostatic pressure of 952.9 psia. The time that the core barrel reached surface was 11/23/90 16:45 hours or 16.75 hours. The pressure at this time was equal to the atmospheric pressure of 0.4898(23.93)=11.7 psia.

é p - pR ù é 952.9 - 945.1 ù = 0.0167 hours = 1 minute = (16.75 - 14.73)ê Dt R 0 = Dt Rs ê m ú ë 952.9 - 11.7 úû ë pm - pa û Time zero occurred 1 minute after the core barrel was lifted of bottom. Time zero occurred at 14:45. Elapsed Time from Time Zero The first measured point occurred at 11/23/90 17:11 hours or 17.183 hours. Time zero was at 14.750 hours. Therefore, the elapsed time for the first measured point was 17.183-14.750=2.433 hours Desorption Time Correction The canister was sealed at 17:01:08 or 17.0189 hours. The first measurement point was at 17.183 hours. Therefore, the desorption time correction was 17.183-17.019=0.164 hours. This time is the same for all measurement points. Horizontal Axis Value By repeating this procedure for each measured point, you will end up with Table 7-4. t DM =

(ti - t0 ) - tdc

= 2.433 - 0.164 = 1.507 hours 0.5

7.9

Chapter

7

Well Name Operator County State Section Field

Additional Problems

Well Identification Valencia Canyon 32-1 Bowen & Edwards La Plata County Colorado Sec. 32 T33N R11W

Canister Data Canister No. Empty Weight Filled Weight Empty Volume Headspace Volume

g g cc cc

12-44 4,140 6,349 2,403 889

Valencia Canyon Sample Data 34-1 Sample ID No. Core Run Identification Formation Fruitland Air-Dry Weight g 2,127 Coal Interval Intermediate Sample Volume cc 1,514 Core Run # 2 Ash Content fraction 0.4845 Sample Top Depth feet 1,774.0 Moisture Content fraction 0.0696 feet 1,774.8 Residual Gas Content scf/ton 0.00 Sample Bottom Depth Coring Fluid Density ppg 10.2 Misc. Information Pressure at standard conditions: 30.01 in Hg Reservoir Data Temperature Deg. F 100 Temperature at standard conditions: 60 Deg. F. Pressure Gradient psi/ft 0.526 Interpretation Parameters Reservoir Pressure psia 945.59 Recovery Times psia 952.86 Time when the top of the sample was cored Fluid Hydrostatic Pressure 11/23/90 13:47:00 Time when the core barrel started out of the well 11/23/90 14:44:00 Temp. Recovery Time hours 2.286 Des. Time Correction Time when the core barrel reached surface 11/23/90 16:45:00 hours 0.164 Time when the sample canister was sealed 2.095 11/23/90 17:01:08 End of Temp. Recovery hours*0.5 11/23/90 14:44:56 Time at time zero Start of Regression hours*0.5 Time at measurement start End of Regression hours*0.5 11/23/90 17:11:00 Measurement Conditions Corrected Data Time Uncorrected Data Canister Ambient Ambient Cumulative Cumulative Date & Time Desorption Square Incremental Desorbed Desorbed Volume Temperature Temperature Pressure Desorbed Desorbed Time Root of Volume Gas Desorption Volume Content Time mm/dd/yy hh:mm:ss hours hours*0.5 cc cc Deg. F Deg. F Inches Hg cc @ STP scf/ton 11/23/90 17:01:08 2.106 1.451 0 0 25 25 23.93 0 0 11/23/90 17:11:00 2.270 1.507 340 340 91 75 23.93 172 2.60 11/23/90 17:16:00 2.353 1.534 130 470 91 75 23.93 273 4.11 11/23/90 17:24:00 2.487 1.577 185 655 91 75 23.93 417 6.27 11/23/90 17:30:00 2.587 1.608 115 770 91 75 23.93 506 7.62 11/23/90 17:36:00 2.687 1.639 115 885 91 75 23.93 595 8.96 11/23/90 17:42:00 2.787 1.669 120 1,005 91 75 23.93 688 10.36 11/23/90 17:48:00 2.887 1.699 110 1,115 91 75 23.93 773 11.64 11/23/90 17:58:00 3.053 1.747 160 1,275 88 75 23.93 901 13.57 11/23/90 18:08:00 3.220 1.794 180 1,455 88 75 23.93 1,040 15.67 11/23/90 18:18:00 3.387 1.840 165 1,620 88 75 23.93 1,168 17.59 11/23/90 18:32:00 3.620 1.903 200 1,820 88 75 23.93 1,323 19.93 11/23/90 18:47:00 3.870 1.967 220 2,040 88 75 23.93 1,494 22.50 11/23/90 19:04:00 4.153 2.038 230 2,270 88 75 23.93 1,672 25.18 11/23/90 19:22:00 4.453 2.110 255 2,525 90 75 23.93 1,867 28.12 11/23/90 19:46:00 4.853 2.203 295 2,820 90 75 23.93 2,096 31.57 11/23/90 20:17:00 5.370 2.317 370 3,190 90 75 23.93 2,382 35.88 11/23/90 20:42:00 5.787 2.406 290 3,480 90 75 23.93 2,607 39.27 11/23/90 21:02:00 6.120 2.474 220 3,700 89 75 23.93 2,779 41.86 11/23/90 21:50:00 6.920 2.631 430 4,130 89 75 23.93 3,112 46.88 11/23/90 22:15:00 7.337 2.709 240 4,370 88 75 23.93 3,299 49.70 01/09/91 08:18:00

1,121.387

33.487

8

13,297

99

75

25.03

Table 7-4. Completed Problem 7-3 Desorption Data Sheet

7.10

10,147

152.83

Problem 7-4.Recognition of Desorption Measurement Conditions. Was the measurement temperature at ambient or at reservoir conditions for the following six Direct Method graphs?

Figure 7-1. Example Direct Method Graphs.

7.11

Chapter

7

Additional Problems

Problem 7-4 Solution.

Figure 7-2. Problem 7-4 Solution.

7.12

Problem 7-5. Direct Method Analysis Evaluate the desorption data contained in Table 7-4 with the Direct Method. The procedure for this problem is as follows. Example 3-5 shows you how to perform the calculations. 1.

Prepare a graph of the cumulative desorbed gas content in the right-most column vs. the square root of the desorption time. This graph has been prepared for you in Figure 7-3.

2.

Fit a straight line to the proper portion of the data required for the lost gas estimate. This line should start near the end of the temperature recovery time for reservoir temperature measurements. The line will start on the first or second point for ambient temperature measurements.

3.

Compute the lost gas content from the absolute value of the y-axis intercept.

4.

Compute the total gas content by summing the lost gas content, the last measured point in Table 7-4, and the residual gas content.

5.

Compute the diffusivity from the slope using Equation 3-8.

D æ m = çç 2 r è 203.1Gcad

ö ÷÷ ø

2

(3-8)

Where: D/r2 m Gcad 6.

= = =

diffusivity, sec-1 slope of the desorbed gas content vs. square root time graph, scf/ton-hour0.5 total gas content, scf/ton

Compute the sorption time from the diffusivity for a spherical fracture geometry with Equation 3-9. The value of the shape factor is 15 for a sphere.

t= Where:

τ

α

= =

1 D 3600a 2 r

(3-9)

sorption time, hours shape factor, dimensionless

7.13

7

Chapter

Additional Problems

Cumulative Desorbed Air-Dry Gas Content, scf/ton

100

50

0

-50

-100 0.0

0.5

1.0

1.5

2.0

2.5

Square Root of Desorption Time, hours*0.5

Figure 7-3.Problem 7-5 Direct Method Graph.

7.14

3.0

3.5

4.0

Problem 7-5. Solution Sample 34-1

100

Regression Line Measured Data

Measured Air-Dry Gas Content, scf/ton

50

0

-50

-100 0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Square Root of Desorption Time, hours*0.5

Figure 7-4. Problem 7-5 Direct Method Graph Solution. Fit a Straight Line to the Proper Data Interval The Direct Method graph for sample 34-1 has the appearance of ambient temperature desorption data since the S-shape characteristic of heated canisters is not present. However, the temperature data in the desorption data sheet indicate that the sample has been reheated to 91o F. Reservoir temperature was reported to be 100o F. In spite of this, the data flattens almost immediately, before the end of the temperature recovery time is reached. We must treat the sample as unheated and fit a straight line to the first few data points. The reason that the data were not S-shaped was that the canister was not placed into a water bath. Instead, reheating was performed by raising the air temperature inside an on-site desorption lab to 91o. Reheating samples in this manner is not as effective as water baths. It is likely that the internal sample temperature was much less than 91o. The estimated lost and total gas contents for this sample are probably lower than the true values. The proper range for the Direct Method line for ambient temperature data begins immediately after the first point. The end of the range is when the data begins to deviate below the straight line. For these data, a straight line was fit to the range 1.5 to 1.6 on the horizontal axis. The intercept and slope are –76.0 scf/ton and 52.2 scf/tonhour½, respectively.

7.15

Chapter

7

Additional Problems

Lost and Total Gas Content Estimates The lost gas content is the absolute value of the intercept, 76.0 scf/ton. The measured gas content is the last data point in the right hand column of Table 7-4, 152.8 scf/ton. Residual gas content was reported to be zero. The total gas content is the sum of the lost, measured, and residual gas contents, i.e., 76.0+152.8+0.0=228.8 scf/ton. Diffusivity Estimate The diffusivity is computed from the slope with Equation 3-8.

D æ m = çç 2 r è 203.1Gcad

2

2

(

)

ö æ ö 52.2 ÷÷ = çç ÷÷ = 0.001123 2 = 1.26 10 -6 sec -1 ( ) 203 . 1 228 . 8 è ø ø

Sorption Time Estimate The sorption time is computed from the diffusivity.

t=

1 D 3600a 2 r

=

1 = 14.7 hours 3600(15 )(1.26 ) 10 -6

(

)

Problem 7-6. Reservoir Temperature Direct Method Analysis Evaluate the data in the Direct Methodgraph illustrated in Figure 7-5. These data were measured on a GRI #2 sample 35-1 that was heated to reservoir temperature. The measured and residual gas contents for this sample were 180.4 and 0 scf/ton, respectively. The time that the core barrel started out of the well was 12/2/90 19:30:00. The sample was placed into a heated water bath at 12/2/90 22:17:00 at the same time that the canister was sealed. The first measured point was at 22:37. The procedure for this problem is as follows. Example 3-5 shows you how to perform the calculations. 1.

Prepare a graph of the cumulative desorbed gas content in the right-most column vs. the square root of the desorption time. This graph has been prepared for you in Figure 7-5.

2.

Estimate the temperature recovery time. This is the elapsed time between the time that the core barrel is lifted off bottom until the canister is placed in a water bath. (22:17)

3.

Estimate the end of the temperature recovery time by adding the temperature recovery time to the time that the canister is sealed. The canister was sealed at 12/2/90 22:17:00.

4.

Calculate the Direct Method horizontal axis value at the end of the temperature recovery time. The first measured point was at 22:37.

7.16

t DM =

(ti - t0 ) - t dc

Where: Direct Method horizontal axis value (square root of desorption time), hours ½ measured desorption time i, hours time zero, hours desorption time correction

tDM ti to tdc 5.

Fit a straight line to the proper portion of the data required for the lost gas estimate.

This line should start near the end of the temperature recovery time for reservoir temperature measurements. 6.

Compute the lost gas content from the absolute value of the y-axis intercept.

7.

Compute the total gas content by summing the lost gas content, the measured gas content (180.4 scf/ton).

8.

Compute the diffusivity from the slope using Equation 3-8.

D æ m = çç 2 r è 203.1Gcad

Where: D/r2 m Gcad 9.

= = =

2

(3-8)

diffusivity, sec-1 slope of the desorbed gas content vs. square root time graph, scf/ton-hour0.5 total gas content, scf/ton

Compute the sorption time from the diffusivity for a spherical fracture geometry with Equation 3-9. The value of the shape factor is 15 for a sphere.

t= Where: τ α

ö ÷÷ ø

= =

1 3600a

D r2

(3-9)

sorption time, hours shape factor, dimensionless

7.17

Chapter

7

Additional Problems

Figure 7-5. Problem 7-6 Direct Method Graph.

7.18

Figure 7-6. Problem 7-6 Direct Method Graph Solution.

Temperature Recovery Time The temperature recovery time is the elapsed time from the time that the sample leaves bottom until the canister is placed in a water bath. The sample started out of the well at 12/2/90 19:30 (19.500 hours). The canister was sealed at 22:17 (22.283 hours). The temperature recovery time is the time difference of 2.783 hours. The end of the temperature recovery time occurred 2.783 hours after sealing or at 22.283+2.783=25.066 hours. This is on the following day (12/30/90) at 1:03:58 A.M. Time zero was at 19:39:08 (19.652 hours). The elapsed time at the end of the temperature recovery time from time zero was 25.066-19.652=5.414 hours. The first measured point was 20 minutes (0.333 hours) after the time of sealing; therefore the desorption time correction is 0.333. The Direct Method horizontal axis value at the end of the temperature recovery time is as follows.

Fit a Straight Line to the Proper Data Interval The Direct Method graph for sample 35-1 has the appearance of reservoir temperature desorption data since the S-shape characteristic of heated canisters is present. We expect the start of the correct straight line to be near 2.25 hours 1/2 on this graph. Therefore, select the points between 2.25 and 2.5 that appear on a straight line. The intercept and slope for this line are -208 scf/ton and 115 scf/ton-hour 1/2, respectively.

7.19

Chapter

7

Additional Problems

Lost and Total Gas Contents Estimates The lost gas content is the absolute value of the intercept, 208.0 scf/ton. The measured gas content is 180.4 scf/ton. Residual gas content was reported to be zero. The total gas content is the sum of the lost, measured, and residual gas contents, i.e., 208.0+180.4+0.0=388.4 scf/ton. Diffusivity Estimate The diffusivity is computed from the slope with Equation 3-8.

Sorption Time Estimate

7.20

Problem 7-7. Multiple Sample Analysis Evaluate the data in Table 7-5 to determine the organic fraction gas content estimate for the Valencia Canyon 32-1 well.

Sample Number

Ash Content

Moisture Content

Inorganic Content

34-1 34-2 34-3 34-4 34-5 Average

fraction 0.4845 0.3948 0.1098 0.2846 0.2047 0.2957

fraction 0.0696 0.1308 0.0958 0.1190 0.0823 0.0995

fraction 0.5541 0.5256 0.2056 0.4036 0.2870 0.3952

Total Air- Total Dry, Dry Gas Ash-Free Content Gas Content scf/ton scf/ton 228.8 513.1 267.3 563.4 529.3 666.2 339.4 569.2 443.2 621.6 361.6 586.7

Lost Gas Content

scf/ton 76.0 45.5 92.9 75.9 72.5 72.5

Measured Gas Content scf/ton 152.8 221.7 436.4 263.6 370.7 289.1

Residual Gas Content

Diffusivity

scf/ton 0.0 0.0 0.0 0.0 0.0 0.0

1/sec 1.26E-06 2.81E-07 2.70E-07 5.79E-07 3.13E-07 5.41E-07

Sorption Time

hours 14.7 65.8 68.5 32.0 59.1 48.0

Table 7-5. Valencia Canyon 32-1 Gas Desorption Summary. The procedure for this problem is as follows. Figure 4-1 of this book illustrates a typical analysis graph. 1.

Construct a graph of the total air-dry gas content vs. the inorganic content for each sample. This graph has been prepared for you in Figure 7-7.

2.

Fit a line to the data and extrapolate the line to a zero inorganic content value. The value of the intercept is the organic fraction gas content.

7.21

Chapter

7

Additional Problems

1,000

900

800

700

600

500

400

300

200

100

0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Ash + Moisture Content, fraction

Figure 7-7. Problem 7-7 Gas vs. Inorganic Content Graph.

7.22

0.8

0.9

1.0

Problem 7-7. Solution Figure 7-8 illustrates the analysis graph for the five Valencia Canyon 32-1 desorption samples. 1,000 Regression Line

900

Upper 95% Confidence Interval Lower 95% Confidence Interval

800

Individual Sample Data

700

600

500

400

300

200

100

0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Ash + Moisture Content, fraction

Figure 7-8. Problem 7-8 Gas vs. Inorganic Content Solution Graph. The intercept and slope of the solid line are 687.5 scf/ton and -824/9 scf/ton, respectively. The organic fraction gas content is equal to the intercept value.

7.23

Chapter

7

Additional Problems

Problem 7-8. Density-Ash Content Relationship Compute the density corresponding to the inorganic contents listed in the following table. Assume that the equilibrium moisture content is equal to 1.74%. Use ash and organic fraction densities of 2.497 and 1.295 g/cm3, respectively. Ash Content Density fraction g/cm3 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Table 7-6. Problem 7-7 Ash Content Values. Solve this problem by computing the density with Equation 4-2.

éw 1 - (wa + ww ) ww ù r=ê a + + ro r w úû ë ra Where:

ρ ρa ρo ρw wa

= = = = =

density, g/cm3 ash density, g/cm3 organic fraction density, g/cm3 sorbed water density, g/cm3 ash content, weight fraction

ww

=

moisture content, weight fraction

7.24

-1

(4-2)

Problem 7-8. Solution At an ash content of 0.5, the solution is as follows.

éw 1 - (wa + ww ) ww ù r=ê a + + ú ro rw û ë ra

-1

1 - (0.5 + 0.0174 ) 0.0174 ù é 0.5 =ê + + 1.295 1 úû ë 2.497

-1

r = [0.2002 + 0.3727 + 0.0174 ] 1 = 1.694 g/cm 3 -

The results for all of the data are listed in Table 7-7. Ash Content fraction 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Density g/cm3 1.288 1.353 1.425 1.505 1.594 1.694 1.808 1.938 2.089 2.264 2.473

Table 7-7. Problem 7-7 Solution. Note that the relationship between density and ash content is a hyperbola as illustrated by Figure 7-9.

7.25

Chapter

7

Additional Problems

2.5

Density, g/cc

2.0

1.5

1.0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Inorganic Content, fraction

Figure 7-9. Problem 7-7 Density vs. Inorganic Content.

7.26

0.8

0.9

1.0

Problem 7-9. Core Density Evaluation Evaluate the Valencia Canyon 32-1 water displacement core density data to estimate the organic and ash fraction densities. The data are summarized in the following table. Moisture Content

Ash Content

wa 1 - ww

fraction 0.0120 0.0184 0.0140 0.0229 0.0073 0.0075 0.0069 0.0134 0.0262

fraction 0.0780 0.0818 0.1054 0.1151 0.1771 0.2437 0.4876 0.6485 0.7493

fraction 0.0789 0.0833 0.1069 0.1178 0.1784 0.2455 0.4910 0.6573 0.7695

Core

r -1 - ww r w-1 Density 1 - ww

cm3/g 0.7108 0.7898 0.7972 0.8019 0.9084 0.7796 0.5785 0.5495 0.5373

g/cm3 1.40 1.26 1.25 1.24 1.10 1.28 1.72 1.80 1.82

Table 7-8. Valencia Canyon 32-1 Core Density vs. Ash and Inorganic Content. The analysis is based upon Equation 4-3 of this book.

(

Where:

ρ ρa ρo ρw

= = = = wa = ww =

æ wa ö -1 r -1 - ww r w-1 ÷÷ r a - r o-1 = r o-1 + çç 1 - ww è 1 - ww ø

)

(4-3)

density, g/cm3 ash density, g/cm3 organic fraction density, g/cm3 sorbed water density, g/cm3 ash content, weight fraction moisture content, weight fraction

The procedure is as follows. 1. Calculate the dry ash content.

wa 1 - ww

2. Compute the reciprocal dry density.

r -1 - ww r w-1 1 - ww

3. Prepare a graph of the reciprocal dry density vs. the dry ash content. The first three steps have been performed for you. See Figure 7-10 4. Fit a straight line to the data. 5. Estimate the organic fraction density from the intercept at a dry density of zero. 6. Estimate the ash fraction density from the intercept at a dry density of one.

7.27

Chapter

7

Additional Problems

1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

0.0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Dry Ash Content, fraction

Figure 7-10. Problem 7-8 Core Density Analysis Graph.

7.28

0.8

0.9

1.0

Problem 7-9. Solution The results of Steps 1 and 2 were listed in the data sheet. Figure 7-11 illustrates the analysis graph. 1.0 Measured Data 0.9

Regression Line Upper 95% Confidence Interval Lower 95% Confidence Interval

0.8

0.7

0.6

Apparent Organic Density

0.5

1.181 g/cc 0.4

0.3

Apparent Ash Density 0.2

2.384 g/cc

0.1

0.0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Dry Ash Content, fraction

Figure 7-11. Problem 7-8 Core Density Analysis Graph Solution. The intercept of the solid line at zero is equal to 0.8464 cm3/g. The apparent organic density is equal to the reciprocal value or 1.181 g/cm3. The intercept at one is equal to 0.4195 cm3/g. The apparent ash density is equal to the reciprocal value or 2.384 g/cm3. The apparent ash and organic density values are less than the values of 2.497 g/cm3 for the ash density and 1.295 g/cm3 for the organic density that were estimated in Chapter 4 of this book. We believe that the cause of the low values was due to the water displacement procedure used to obtain the density estimates. The volume of the sample was measured by the volume of water displaced by the sample. The sample was weighed after immersion. The apparent density was equal to the mass divided by the volume. We have found that this procedure usually results in low density estimates. As a result, both the organic and ash densities are underestimated from these data. Helium pycnometry determines the sample volume by expansion of helium. These data when analyzed in the same manner as this problem, result in more accurate organic and ash density estimates.

7.29

Chapter

7

Additional Problems

Problem 7-10. Number of Valencia Canyon Core Samples. Determine the number of samples required to achieve 95% statistical certainty that the Valencia Canyon 321 intermediate interval sample density is within 10% of the correct value. Assume that there is no more than a 20% chance of concluding that the average density of the samples is the same as that of the reservoir when if fact it is not. Within the density range of 1.295 g/cm3 (organic) to 2.4 g/cm3 (96% inorganic), the average value and standard deviation of open-hole density log data is 1.585 and 0.214 g/cm3, respectively, in the intermediate interval. Use the operating characteristic curves illustrated in Figure 7-12.

Figure 7-12. Operating Characteristic Curves for Problem 7-9. Where:

µ = sample average density value, g/cm3 µ0 = average in-situ density value, g/cm3 σ = in-situ density standard deviation, g/cm3 The procedure for this problem is as follows. Example 4-3 of this book shows you how to perform the steps. 1. 2. 3.

Compute the value of the x axis for the desired accuracy (10% for this problem). Determine the number of samples by the n line closest to the x axis value that intersects the y axis at the desired probability (20% for this problem). Determine the range in sample density and ash content that is required.

Use an equilibrium moisture content of 0.0174 and ash and organic densities of 2.497 and 1.295 g/cm3, respectively to compute the ash content range. Use equation 4-6 to convert density to ash content.

7.30

Where: wa

ρ ρa ρo ρw

wwe

= = = = = =

æ 1 æ 1 1ö 1 ö ÷ çç - ÷÷ + wwe çç ro r ø r w r o ÷ø è è wa = 1 1 ro r a ash content, weight fraction density, g/cm3 ash density, g/cm3 organic fraction density, g/cm3 sorbed water density, g/cm3 equilibrium moisture content, weight fraction

(4-6)

7.31

Chapter

7

Additional Problems

Problem 7-10. Solution For this problem, we specified an accuracy of 10%. Therefore the sample average value, µ, must be within 10% of the average in-situ value, µ0. The average in-situ value is 1.585 g/cm3. Therefore, the sample average value must be 1.1(1.585)=1.788 g/cm3. The x axis value becomes as follows.

m - m0 1.10 (1.585 ) - 1.585 = = 0.74 s 0.214

1 .0

n=

0 .6

1

2 3

0 .4 4

P ro b a b ility

0 .8

5 6 7 8 10 15 20 30 40 50 75 100

0 .2 0 .0 0

1 0.74

2

3

4

5

m-m 0 s Figure 7-13. Problem 7-9 Solution.

In Figure 7-13, the intersection of a vertical line of horizontal value 0.74 with the horizontal line intersecting the vertical axis at 0.2 is at about n=15. Fifteen samples are required for this well to obtain a sample density value that is within 10% of the in-situ density. The range in density required is from below 1.585 - 0.214 = 1.371 g/cm3 to above 1.585 + 0.214 = 1.799 g/ 3 cm . The density range corresponds to an ash content range as follows. Minimum:

Maximum:

7.32

1 ö 1 ö æ 1 æ1 ç ÷ + 0.0174ç ÷ 1.295 1.371 ø 1 1.295 ø è è = 0.126 wa = 1 1 1.295 2.497 1 ö 1 ö æ 1 æ1 ÷ ç ÷ + 0.0174ç 1.295 1.799 ø 1 1.295 ø è è wa = = 0.593 1 1 1.295 2.497

Problem 7-11. Interval Thickness and Density Determine the gross thickness and average density of the Valencia Canyon 32-1 intermediate interval illustrated in Figure 7-14. Use a maximum density limit of 2.46 to assist in identifying the organic bearing intervals. Use the gamma ray log in conjunction with the density data to assist you. The average density should be computed as a thickness weighted average as in Example 5-2.

Figure 7-14. Valencia Canyon Intermediate Coal Interval Log.

7.33

Chapter

7

Additional Problems

Problem 7-11. Solution The following table summarizes the thickness and average density estimates for each one- or two-foot interval. The average density of the gross thickness interval is the sum of the thickness-density product values divided by the gross thickness. Top Depth

Bottom Average Depth Density

feet feet g/cm3 1,776 1,778 1.45 1,778 1,780 1.39 1,780 1,782 1.47 1,782 1,784 1.42 1,784 1,786 1.47 1,786 1,788 1.46 1,788 1,790 1.66 1,790 1,792 1.62 1,794 1,796 1.88 1,796 1,798 1.66 1,798 1,800 1.44 1,800 1,802 1.50 1,804 1,806 1.49 1,806 1,808 1.52 1,808 1,810 1.62 1,810 1,812 1.44 1,812 1,814 1.31 1,814 1,816 1.60 1,816 1,817 1.88 1,822 1,824 1.85 1,824 1,826 1.35 1,826 1,828 2.01 Gross Thickness-Density Product Total Thickness Gross Thickness Average Density

Cumulative Thickness feet 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 37 39 41 43 ft-g/cm3 feet feet g/cm3

ThicknessDensity Product feet-g/cm3 2.896 2.773 2.939 2.845 2.947 2.925 3.318 3.243 3.760 3.328 2.875 2.997 2.982 3.049 3.241 2.886 2.613 3.191 1.877 3.693 2.698 4.014 67.090 52.0 43.0 1.560

Table 7-9. Problem 7-12 Solution. r=

7.34

43.0 = 1.560 g/cm 3 67.09

Problem 7-12. Valencia Canyon 32-1 Ash and Gas Content Continue Problem 7-11 and compute the average ash content, gas content, and gas-in-place within a 320 acre drainage area. The procedure for this problem is as follows. 1. Compute the ash content at the average density with Equation 4-6. Use ash and organic densities of 2.497 and 1.295 g/cm3, respectively. The equilibrium moisture content is 0.0174 based upon measurements performed on Valencia Canyon 32-1 isotherm samples.

æ 1 æ 1 1ö 1 ö ÷ çç - ÷÷ + wwe çç ro r ø r w r o ÷ø è è wa = 1 1 ro r a

(4-6)

Where: wa = ρ = ρa = ρo = wwe = ρw =

ash content, weight fraction density, g/cm3 ash density, g/cm3 organic fraction density, g/cm3 equilibrium moisture content, weight fraction sorbed water density, g/cm3

2. Compute the gas content at the average ash content with Equation 5-1. Use the value of the organic fraction gas content determined in Problem 7-7 (687.5 scf/ton). G

c

= G

co

[1

- ( w a + w we

)]

(5-1)

Where: Gc = in-situ gas content, scf/ton Gco = organic fraction gas content, scf/ton 3. Compute the gas-in-place with Equation 2-1.

G = 1359.7 Ahr Gc

(2-1)

Where: G A h r Gc

= = = = =

gas-in-place volume, scf reservoir area, acres reservoir thickness, feet average in-situ rock density at the average in-situ rock composition, g/cm3 average gas content at the average in-situ rock composition, scf/ton.

7.35

Chapter

7

Additional Problems

Problem 7-12. Solution The average density was determined to be 1.560 g/cm3 in Problem 7-11. The average ash content is computed as follows.

æ 1 æ 1 1ö 1 ö æ 1 1 ö 1 ö æ1 ÷÷ ç çç - ÷÷ + wwe çç ÷ + 0.0174ç ÷ r r r r 1.295 1.560 ø o ø è 1 1.295 ø = 0.1312 + 0.0174(0.2278 ) = 0.3685 è w ø =è wa = è o 1 1 1 1 0.7722 - 0.4055 1.295 2.497 ro r a The in-situ gas content is computed as follows. G c = G co [1 - (wa + w we )] = 687.5[1 - (0.3685 + 0.0174 )] = 422.2 scf/ton

The gas-in-place in 320 acres is computed as follows.

( )

G = 1359.7 Ahr Gc = 1359.7 (320 )(43)(1.560 )(422.2 ) = 1.232 10 10 scf = 12.32 Bscf

7.36

Problem 7-13. Maximum Possible Gas Recovery Estimate the maximum possible gas recovery from the three reservoir intervals in the Valencia Canyon 321 well. Assume that the average reservoir pressure can be reduced to 50 psia. This assumption requires that producing bottom-hole pressures be maintained below this pressure late in the life of the well. Use the recovery factor relationship listed in Equation 6-3.

fg = 1 Where: fg GsL wa wwe p pL

= = = = = =

GsL [1 - (wa + wwe )]p Gci ( p + p L )

(6-3)

fractional gas recovery, dimensionless dry, ash-free Langmuir storage capacity, scf/ton ash content, weight fraction equilibrium moisture content, weight fractions average reservoir pressure, psia Langmuir pressure, psia.

The Langmuir parameters measured on Valencia Canyon 32-1 samples are as GsL, 946.9 scf/ton, and pL, 368.5 psia. The individual reservoir parameters are summarized in the following table. Parameter

Units

Initial gas-in-place Average ash content Equilibrium moisture content Initial gas content

Bscf fraction fraction scf/ton

Upper Interval 4.81 0.496 0.0174 323

Intermediate Interval

Basal Interval

12.40 0.343 0.0174 425

9.43 0.288 0.0174 460

Table 7-10. Problem 7-12 Input Data.

7.37

Chapter

7

Additional Problems

Problem 7-13. Solution The solution to this problem for the intermediate interval is as follows.

fg = 1 -

[

]

GsL 1 - (wa + weq ) p Gci ( p + p L )

=1-

946.9[1 - (0.343 + 0.0174 )]50 = 1 - 0.170 = 0.830 425(50 + 368.5 )

The maximum gas recovery is therefore 12.40(0.83)=10.29 Bscf from this reservoir. The individual reservoir parameters and results for each interval are summarized in the following table.

Parameter

Units

Initial gas-in-place Average ash content Equilibrium moisture content Initial gas content Fractional gas recovery Gas recovery

Bscf fraction fraction scf/ton fraction Bscf

Upper Interval 4.81 0.496 0.0174 323 0.830 4.01

Intermediate Basal Interval Interval 12.40 9.43 0.343 0.288 0.0174 0.0174 425 460 0.830 0.830 10.29 7.83

Table 7-11. Problem 7-12 Solution. Therefore, the potential gas recovery from this well, if draining a 320-acre drainage area, is 22.13 Bscf.

7.38

Problem 7-13. Extension of Valencia Canyon 32-1 Gas Content Data The Valencia Canyon 32-3 well is to be drilled after the VC 32-1. The operator wishes to know what the gasin-place may be surrounding the VC 32-3 location. The VC 32-3 is located in the same section as the VC 32-1 well but at a shallower depth. Figure 7-15 illustrates the structure map of the Basal coal interval across the section.

Section 32 T 33 N R 11 W Structure Map Height Above Sea Level, feet

Figure 7-15. Valencia Canyon Section 32 Basal Coal Interval Structure Map. Make an estimate of the of the gas content and gas-in-place at the VC 32-3 location. Assume that the thickness of each coal interval is the same at both wells. Adjust the pressure between wells by the depth difference assuming that a normal hydrostatic pressure gradient exists between the two wells. A key assumption is that the coal gas reservoirs are saturated at both locations and that the coal rank and organic composition do not vary. This assumption allows us to use the VC 32-1 isotherm data to adjust gas content estimates. The procedure for this problem is as follows. 1.

Where: pR

∇pR pa

Estimate the pressures at the midpoint of each coal interval in the VC 32-1 well based upon the pressure gradients determined from drill stem tests. Use Equation 3-11 for this estimate. (3-11) p R = p a + ∇p R d R = = =

reservoir pressure, psia reservoir pressure gradient, psi/ft atmospheric pressure, psia

7.39

Chapter

7

Additional Problems

The atmospheric pressure at this location is 23.98 in Hg (11.8 psia) based upon the desorption data. 1. Estimate the coal depths at the VC 32-3 well location based upon the differences in elevation on the structure map. 2. Compute the pressure in each coal interval at the location of the VC 32-3 well. The pressure gradient through the reservoir will be due to the hydrostatic head of water, 0.43 psi/ft. 3. Compute the gas content at the midpoint of each VC 32-3 coal interval based upon the ash, moisture, and isotherm parameters for the VC 32-1 well. The Langmuir parameters measured on Valencia Canyon 32-1 samples are GsL, 946.9 scf/ton, and pL, 368.5 psia. The Langmuir isotherm relationship is as follows.

G s = GsL [1 - (wa + wwe )]

Where: Gs GsL wa wwe p

= = = = =

p + p pL

(6-1)

gas storage capacity, scf/ton dry, ash-free Langmuir storage capacity, scf/ton ash content, weight fraction equilibrium moisture content, weight fraction pressure, psia

4. Compute the gas-in-place in a 160-acre area surrounding the VC 32-3 using Equation 2-1.

G = 1359.7 Ahr Gc

(2-1)

Where: G A h r

Gc

= = = = =

gas-in-place volume, scf reservoir area, acres reservoir thickness, feet average in-situ rock density at the average in-situ rock composition, g/cm3 average gas content at the average in-situ rock composition, scf/ton

The Valencia Canyon 32-1 reservoir properties are summarized in Table 7-12. Parameter

Units

Midpoint Depth Initial Pressure Gradient Thickness Average density Average ash content Equilibrium moisture content Initial gas content

feet psi/ft feet g/cm3 fraction fraction scf/ton

Upper Interval 1,715 0.526 20 1.71 0.496 0.0174 323

Intermediate Interval 1,802 0.526 43 1.56 0.343 0.0174 425

Basal Interval 1,928 0.471 31 1.52 0.288 0.0174 460

Table 7-12. Valencia Canyon 32-1 Reservoir Properties.

7.40

Problem 7-14. Solution The solution to this problem is as follows. VC 32-1 Reservoir Pressures Upper Interval Pressure p R = p a + Ñp R d R = 11.8 + 0.526 (1715 ) = 914 psia

Intermediate Interval Pressure p R = p a + Ñp R d R = 11.8 + 0.526 (1802 ) = 960 psia

Basal Interval Pressure p R = p a + Ñp R d R = 11.8 + 0.471(1928 ) = 920 psia

VC 32-3 Coal Depths and Pressures Based upon the structure map, the base of the Basal interval in the VC 32-1 well is at 4,380 feet above sea level. The base of the Basal interval at the VC 32-3 well location is 4,840 feet above sea level or 460 feet shallower than at the VC 32-1 location. The hydrostatic head of water between the two locations is equal to 0.433 psi/ft times 460 feet which is equal to 199 psi. Therefore, the pressure in each reservoir interval at the VC 32-3 location is 199 psi less than at the VC 32-1 location. VC 32-3 Gas Contents Now that pressure estimates are available, we can calculate the gas content at the VC 32-3 location if we assume that it is equal to the storage capacity. For example, for the Intermediate interval, the calculation is as follows.

G s = G sL [1 - (wa + wwe )]

p 761 = 946.9[1 - (0.343 + 0.0174 )] = 408 scf/ton p + pL 761 + 368.5

VC 32-3 Gas-in-Place Once the gas content estimates are available, we can compute the gas-in-place volume. The calculation is as follows for the Intermediate interval.

( )

G = 1359.7 Ahr Gc = 1359.7 (160 )(43 )(1.56 )(408 ) = 5.95 10 9 scf or 5.95 Bscf The following table summarizes the estimates for each of the three intervals.

7.41

Chapter

7

Additional Problems

Parameter

Units

Midpoint Depth Pressure Thickness Average density Average ash content Equilibrium moisture content Gas content Gas-in-place

feet psia feet g/cm3 fraction fraction scf/ton Bscf

Upper Intermediate Interval Interval 1,255 1,342 715 761 20 43 1.71 1.56 0.496 0.343 0.0174 0.0174 304 408 2.26 5.95

Basal Interval 1,468 721 31 1.52 0.288 0.0174 435 4.46

Table 7-13. Valencia Canyon 32-3 Coal Gas Reservoir Property Estimates. The total gas-in-place in a 160-acre area surrounding the Valencia Canyon 32-3 well is roughly 12.67 Bscf. Note that this estimate assumed that the reservoirs are horizontal. In reality, to perform the computation correctly, you should include the dip in the calculations. Reservoir simulators take the dip into account by breaking the area into small parallelepipeds and assigning constant properties such as structural elevation and pressure in each. You can do the same by hand if necessary.

7.42

Problem. 7-15. Gas-in-Place for the Southern Ute 5-7 READ ME

The Southern Ute 5-7 well intersected two coal gas reservoir intervals through which core was taken. A total of 26 samples were desorbed for gas content estimates. The data from these measurements is summarized in the following table. Combine this information with the logs included in this section to determine the gas-in-place in a 320-acre area surrounding the SU 5-7. Sample Number 49-24 49-1 49-10 49-11 49-15 49-16 49-17A 49-18 49-19 49-2 49-22A 49-23 49-26 49-27 49-28 49-29 49-3 49-30 49-31 49-32 49-33 49-34 49-5 49-8 49-9 49-25 Average

Ash Content fraction 0.4727 0.5443 0.3068 0.5991 0.3188 0.4331 0.5728 0.4042 0.7405 0.5421 0.2705 0.1573 0.1998 0.1912 0.2209 0.1765 0.2465 0.1707 0.1653 0.2681 0.1455 0.4778 0.2673 0.2858 0.2465 0.2834 0.3349

Moisture Content fraction 0.0150 0.0160 0.0093 0.0108 0.0108 0.0180 0.0252 0.0103 0.0080 0.0181 0.0123 0.0158 0.0105 0.0110 0.0139 0.0126 0.0105 0.0143 0.0113 0.0125 0.0105 0.0133 0.0140 0.0149 0.0099 0.0115 0.0131

Inorganic Content fraction 0.4877 0.5603 0.3161 0.6099 0.3296 0.4511 0.5980 0.4145 0.7485 0.5602 0.2828 0.1731 0.2103 0.2022 0.2348 0.1891 0.2570 0.1850 0.1766 0.2806 0.1560 0.4911 0.2813 0.3007 0.2564 0.2949 0.3480

Total AirDry Gas Content scf/ton 239.5 214.9 412.9 184.2 313.3 252.5 209.1 271.6 123.1 233.4 314.8 409.7 459.2 418.3 409.3 437.7 409.6 432.3 407.6 381.6 425.7 242.3 429.8 368.7 402.0 345.4 336.5

Total Dry Ash-Free Content scf/ton 467.4 488.7 603.7 472.3 467.4 460.1 520.1 463.9 489.5 530.7 439.0 495.5 581.5 524.3 534.8 539.7 551.2 530.5 495.1 530.4 504.4 476.1 598.1 527.2 540.6 489.9 512.4

Lost Gas Lost Gas Fraction Content scf/ton 19.9% 47.7 26.4% 56.7 23.4% 96.6 22.6% 41.6 13.6% 42.6 13.8% 34.9 33.3% 69.5 16.7% 45.3 14.0% 17.2 30.4% 70.9 33.9% 106.8 14.9% 60.9 15.2% 69.8 18.3% 76.6 17.9% 73.3 17.1% 74.7 24.7% 101.0 16.4% 70.7 16.5% 67.2 19.6% 74.8 17.1% 72.9 20.2% 48.9 26.8% 115.0 27.5% 101.6 26.6% 106.9 13.7% 47.5 20.8% 68.9

Measured Gas Content scf/ton 191.8 158.2 316.3 142.6 270.8 217.6 139.6 226.3 105.9 162.5 208.0 348.9 389.4 341.7 336.0 363.0 308.5 361.6 340.4 306.8 72.9 193.4 314.8 267.1 295.1 298.0 256.8

Residual Gas Content scf/ton 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Diffusivity 1/sec 6.88E-07 8.84E-07 5.53E-07 6.23E-07 3.91E-07 4.42E-07 1.90E-06 4.55E-07 3.88E-07 9.86E-07 1.80E-06 4.85E-07 5.09E-07 5.83E-07 5.92E-07 5.86E-07 6.83E-07 5.47E-07 5.79E-07 6.15E-07 6.61E-07 1.01E-06 8.33E-07 7.01E-07 6.46E-07 4.36E-07 7.14E-07

Sorption Time hours 26.9 21.0 33.5 29.7 47.3 41.9 9.7 40.7 47.7 18.8 10.3 38.2 36.4 31.7 31.3 31.6 27.1 33.8 32.0 30.1 28.0 18.3 22.2 26.4 28.7 42.5 30.2

Table 7-14. Southern Ute 5-7 Reservoir Temperature Core Desorption Data. The equilibrium moisture content determined on sorption isotherm samples is 1.93%. A graph of the Table 7-14 data is included in Figure 7-16. Figures 7-17 and 7-18 illustrate the open-hole log data.

7.43

Chapter

7

Additional Problems

600

500

400

300

200

100

0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Ash + Moisture Content, fraction

Figure 7-16. Final Problem Gas Content vs. Inorganic Content Graph.

7.44

0.9

1.0

Southern Ute 5-7 Upper Coal Interval

READ ME

Figure 7-17. Southern Ute 5-7 Upper Coal Interval Log.

7.45

Chapter

7

Additional Problems

Southern Ute 5-7 Lower Coal Interval

Figure 7-18. Southern Ute 5-7 Lower Coal Interval Log.

7.46

The steps in this problem are as follows. 1. Evaluate the gas content vs. inorganic content data to determine estimates of the organic fraction gas content. 2. Evaluate the open-hole density log data to determine the coal thickness and average density in two-foot intervals. 3. Calculate the average ash and gas content in each coal interval. 4. Calculate the gas-in-place in each coal interval

7.47

7

Chapter

Additional Problems

Problem 7-15 Solution The solution to this problem is as follows. Gas Content – Inorganic Content Relationship The relationship between the air-dry gas content and the inorganic content is illustrated in Figure 7-19. 600 Regression Line Upper 95% Confidence Interval 500

Lower 95% Confidence Interval Individual Sample Data

400

300

200

100

0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Ash + Moisture Content, fraction

Figure 7-19. Southern Ute 5-7 Gas Content – Inorganic Content Relationship. Linear regression of these data results in the following estimates. Property Organic Fraction Gas Content Slope X-Axis Intercept Regression Coefficient Significance Level Number of Points Intercept Variation Slope Variation

Units scf/ton scf/ton scf/ton scf/ton scf/ton

Value 532.64 -563.68 0.945 0.9590 0.95 26 28.51 75.04

Table 7-15. Southern Ute 5-7 Gas Content – Inorganic Content Relationship

7.48

Open-Hole Log Evaluation A summary of the open-hole log analysis for each of the two intervals is listed in Tables 7-16 and 7-17.

Top Depth

Bottom Depth

Average Density

feet feet g/cm3 1,321 1,322 1.54 1,322 1,324 1.34 1,324 1,326 1.41 1,326 1,328 1.35 1,328 1,330 1.34 1,330 1,332 1.46 1,332 1,334 1.47 1,334 1,336 1.57 1,336 1,338 1.63 1,338 1,339 1.97 1,341 1,342 1.74 1,342 1,344 1.63 1,344 1,346 1.48 1,346 1,347 1.58 1,349 1,350 1.55 1,350 1,352 1.44 1,352 1,354 1.55 1,354 1,356 1.45 1,356 1,358 1.30 1,358 1,360 1.34 1,360 1,362 1.67 Gross Thickness-Density Product Gross Thickness-Ash Content Product Total Thickness Gross Thickness Average Density Average Ash Content Average Gas Content Gas-in-Place per acre

Cumulative ThicknessThickness Density Product feet 1 3 5 7 9 11 13 15 17 18 19 21 23 24 25 27 29 31 33 35 37

feet-g/cm3 1.541 2.683 2.828 2.695 2.685 2.917 2.948 3.139 3.256 1.974 1.740 3.268 2.957 1.576 1.549 2.887 3.093 2.901 2.600 2.686 3.341 ft-g/cm3 feet feet feet g/cm3 fraction scf/ton MMscf/acre

Ash Content

fraction 0.342 0.082 0.186 0.092 0.084 0.244 0.263 0.374 0.436 0.725 0.542 0.442 0.269 0.381 0.352 0.225 0.348 0.233 0.019 0.085 0.477 55.265 10.058 41.0 37.0 1.494 0.272 369.5 27.77

ThicknessAsh Content Product feet 0.342 0.165 0.371 0.184 0.168 0.487 0.526 0.748 0.872 0.725 0.542 0.884 0.537 0.381 0.352 0.449 0.697 0.466 0.037 0.169 0.955

Gas Content

Gas-In-Place per Acre

scf/ton 340.1 478.5 423.5 473.4 477.6 392.7 382.2 323.2 290.2 136.1 233.7 287.0 379.3 319.3 335.1 402.7 336.8 398.2 512.4 477.3 268.0

MMscf/acre 0.713 1.745 1.629 1.735 1.743 1.557 1.532 1.379 1.285 0.365 0.553 1.275 1.525 0.684 0.706 1.581 1.416 1.570 1.812 1.743 1.217

Table 7-16. Southern Ute 5-7 Upper Coal Interval Log Analysis Summary.

7.49

Chapter

7

Top Depth

Additional Problems

Bottom Depth

Average Density

feet feet g/cm3 1,451 1,452 1.63 1,452 1,454 1.44 1,454 1,456 1.57 1,456 1,458 1.73 1,458 1,460 1.31 1,460 1,462 1.47 1,462 1,464 1.38 1,464 1,466 1.30 1,466 1,468 1.29 1,468 1,470 1.35 1,470 1,472 1.30 1,472 1,473 1.85 Gross Thickness-Density Product Gross Thickness-Ash Content Product Total Thickness Gross Thickness Average Density Average Ash Content Average Gas Content Gas-in-Place per acre

Cumulative Thickness

feet 1 3 5 7 9 11 13 15 17 19 21 22

ThicknessDensity Product

Ash Content

feet-g/cm3 1.633 2.885 3.131 3.465 2.625 2.933 2.767 2.600 2.590 2.702 2.600 1.847 ft-g/cm3 feet feet feet g/cm3 fraction scf/ton MMscf/acre

fraction 0.440 0.223 0.369 0.535 0.038 0.253 0.144 0.019 0.011 0.097 0.019 0.632 31.777 4.488 22.0 22.0 1.444 0.204 402.2 17.38

ThicknessAsh Content Product feet 0.440 0.447 0.739 1.070 0.077 0.507 0.287 0.037 0.021 0.194 0.037 0.632

Gas Content

Gas-In-Place per Acre

scf/ton 287.9 403.4 325.6 237.4 502.0 387.4 445.9 512.4 516.7 470.7 512.4 186.0

MMscf/acre 0.639 1.583 1.386 1.118 1.792 1.545 1.678 1.812 1.820 1.729 1.812 0.467

Table 7-17. Southern Ute 5-7 Lower Coal Interval Log Analysis Summary. Gas-in-Place The final estimates of the gas-in-place for the Southern Ute 5-7 well are summarized in Table 7-18. Parameter

Units

Drainage area Thickness Average in-situ density Average gas content Gas-in-place

acres feet g/cm3 scf/ton Bscf

UpperCoal Interval Value 320 37 1.494 369.5 8.89

Lower Coal Interval Value 320 22 1.444 402.2 5.56

Table 7-18. Southern Ute 5-7 Gas-in-Place Summary. The total gas-in-place in a 320 acre drainage area is 14.45 Bscf.

7.50

8

Nomeclature Summary

Chapter

Symbol A Bg Bw Csci D dR fg G Gc

) Gc Gcad Gco GD Gf GcLad Gsi Gci Gcrad Gs GsL GsLi h m mad mmmf n nc p p

Definition reservoir drainage area gas formation volume factor water formation volume factor standard condition correction factor at time i diffusion coefficient sample subsurface (reservoir) depth fractional gas recovery gas-in-place volume average gas content at the average in-situ composition estimated (saturated) in-situ gas content total gas content, air-dry basis organic fraction gas content dissolved gas volume gas volume in the coal natural fracture system lost gas content, air-dry basis multicomponent storage capacity of component i, in-situ basis initial gas content, (in-situ basis) residual gas content, air-dry basis gas storage capacity dry, ash-free Langmuir storage capacity Langmuir storage capacity of component i, dry, ash-free basis reservoir thickness slope of the Direct Method straight line air-dry mass mineral-matter-free mass number of samples number of components total pressure of the free gas phase pressure

Units acres dimensionless dimensionless dimensionless cm2/sec feet dimensionless scf scf/ton scf/ton scf/ton scf/ton scf scf scf/ton scf/ton scf/ton scf/ton scf/ton scf/ton scf/ton feet scf/ton-hour½ g g psia psia

8.1

Chapter

p pa pai pa(i-1) pc pL pLi or pLj pm pR psc r Rsw Sg Sw Tai Tci Tc(i-1) tdc tDM ti Tsc t0 Ve Vi vi vhi vsci Vsci Vv vv wa wad was wH wN wO wS ws ww wwe

8.2

8

Nomenclature Summary

average reservoir pressure ambient (atmospheric) pressure atmospheric pressure at time i atmospheric pressure at time i-1 critical desorption pressure Langmuir pressure Langmuir pressure of component i or j mud (coring fluid) hydrostatic pressure reservoir pressure pressure at standard conditions average diffusion distance solution gas-water ratio gas saturation water saturation ambient temperature at time i canister temperature at time i canister temperature at time i-1 desorption time correction Direct Method horizontal axis value time at time i temperature at standard conditions time zero

exinite maceral volume fraction inertinite maceral volume fraction measured desorption volume at time i head space correction at time i standard condition desorption volume at time i cumulative standard condition desorption volume at time i vitrinite maceral volume fraction canister internal void (head space) volume ash content dry ash content moist-basis ash content adjusted for sulfur content hydrogen content nitrogen content oxygen content sulfur content sulfur trioxide content moisture content equilibrium moisture content

psia psia inches Hg inches Hg psia psia psia psia psia psia cm scf/STB volume fraction volume fraction Degrees Fahrenheit Degrees Fahrenheit Degrees Fahrenheit hours hours½ hours Degrees Fahrenheit hours dimensionless dimensionless cm3 cm3 cm3 cm3 dimensionless cm3 weight fraction weight fraction weight fraction weight fraction weight fraction weight fraction weight fraction weight fraction weight fraction weight fraction

yi or yj z zsc

α β ∆Gcadi ∆Gcad ∆t ∆tRs ∆tR0 φf µ µ0 ρ ρa

r

ρe ρi ρm ρo ρv ρw σ τ ∇pR

mole fraction of component i or j in the free gas (vapor) phase real gas deviation factor real gas deviation factor at standard conditions shape factor slope of the gas content vs. inorganic content straight line measured gas content at time i, air-dry basis cumulative desorbed gas content, air-dry basis desorption time elapsed time between time raised off bottom and time at surface elapsed time between time raised of bottom and time zero natural fracture porosity sample set average property reservoir average property density ash density average in-situ rock density at the in-situ composition exinite maceral density inertinite maceral density mud (coring fluid) density organic fraction density vitrinite maceral density water density standard deviation of the reservoir property sorption time reservoir pressure gradient

dimensionless dimensionless dimensionless dimensionless scf/ton scf/ton scf/ton hours hours hours volume fraction various various g/cm3 g/cm3 g/cm3 g/cm3 g/cm3 pounds per gallon g/cm3 g/cm3 g/cm3 various hours psi/ft

8.3

9

Glossary

Chapter

Abandonment Pressure

The average pressure of a reservoir when abandoned due to lack of com mercial gas productivity.

Absorbed Gas

Gas which is molecularly dissolved within a liquid phase or which has penetrated into the lattice structure of a solid.

Absorption

The process of molecular assimilation or incorporation within a liquid phase or into the lattice structure of a solid.

Adsorbed Gas

Gas which is sequestered, through physical or chemical bonding, at an interfacial surface in a metastable equilibrium state, the stability of which is strongly affected by changes in temperature or pressure.

Adsorbent

A microporous material having the capacity to attract and retain on its surface through physical or chemical-bonding a layer of molecules of another substance, usually a gas or liquid, with which it is in contact.

Adsorption

The attachment, through physical or chemical bonding, of fluid phase molecules to an interfacial surface. The adsorbed phase molecules are sequestered at the interfacial surface in a metastable equilibrium state, the stability of which is strongly affected by changes in temperature or pres sure.

Adsorption Isotherm

The quantitative relationship, at constant temperature, describing how the concentration of adsorbed phase molecules at an interfacial surface varies as a function of increasing system pressure.

Air-Dry Basis

Measured data normalized with respect to a base where the moisture content of the sample is in equilibrium with the atmospheric conditions to which it is exposed.

Air-Dry Gas Content

Gas content based upon a desorption sample mass after drying for 24 to 48 hours at laboratory conditions. Extraneous water and material might be removed from the original sample before mass measurement.

Ambient Pressure

The static pressure due to the surrounding atmosphere (e.g., atmospheric pressure).

Ambient Temperature

The static temperature due to the surrounding atmosphere (e.g., atmospheric temperature).

9.1

Chapter

9

Glossary

Amoco Method

Lost and total gas content estimate procedure developed by Amoco Produc tion Company

Ash Content

Fraction by weight of the inorganic residue remaining after ignition of combustible substances, determined by definite prescribed methods. (For coal, see methods prescribed in ASTM D 3174-89.) Ash may not be identical in composition or quantity with the inorganic substances present in the material before ignition.

ASTM

American Society for Testing and Materials: A scientific and technical organization formed for “the development of standards on characteristics and performance of materials, products, systems, and services; and the promotion of related knowledge.”

Basis

A standard for normalizing test data.

Bitumen

Naturally occurring, inflammable substances composed primarily of hydrocarbons.

Brine

Saline fluid containing dissolved Cl, Na, Ca, and K ions found within the pores of sedimentary rocks.

Brine Gas

Natural gas dissolved in aquifers under normal hydrostatic pressure (see Absorption).

Bscf

Billion standard cubic feet

Bulk Density

The mass of a unit volume of material including any void space.

Calorific Value

The heat of combustion of a unit quantity of a substance.

Canister

see Desorption Canister

Cleat

A naturally occurring fracture within a coal seam.

Coal Natural Gas

Gas produced naturally by coalification and found within coal natural gas reservoirs consisting predominately of methane with smaller amounts of hydrocarbons, water vapor, nitrogen, and carbon dioxide, or other non-hydrocarbons. The majority of the gas is usually physically sorbed within the microporosity and mesoporosity within the organic matrix.

Coal Natural Gas Reservoir

Natural gas reservoir that contains natural gas in the free and sorbed states in coal and interbedded coaly shale, carbonaceous shale, and inorganic rocks

Coal Seam

A stratum or bed of coal

Coalbed

A coal seam

Coalbed Gas

see Coal Natural Gas

Coalification

The overall processes of diagenesis and metamorphism by which organic materials derived from plant components are converted into coal.

Conventional Core

A ‘large’ diameter core (8.9 cm or larger), where the core barrel is recovered to the surface by pulling the drill string out of a well.

9.2

Core Barrel

Two nested tubes above the bit of a core drill, the outer tube rotating with the bit, the inner receiving and preserving a continuous section of core

Core Sample

A cylindrical sample of rock, usually 5 to 10 cm in diameter and up to several meters in length, cut with a hollow, cylindrical bit

Critical Desorption Pressure The pressure at which a sample begins to release adsorbed phase gas molecules. Crude Oil

Petroleum in its natural state after recovery from a reservoir but prior to refining or distillation.

Density Log

Wireline log that measures rock density as a function of depth surrounding a wellbore

Desorption

The detachment of adsorbed molecules from an interfacial surface (see Adsorption) causing the molecules to move from the sorbed to the free gas state.

Desorption Canister

An airtight container used to hold samples and trap gas during desorption measurements (described in Chapter 3).

Desorption Isotherm

The relationship, at constant temperature, which describes the sorbed gas storage capacity as a function of decreasing system pressure.

Desorption Rate

The volumetric rate at which gas desorbs from a sample.

Diffusion

The process of mass transfer whereby molecules in either the gaseous or liquid state move from a region of higher to lower concentration.

Diffusivity

The ratio of the diffusion coefficient to the square of an average diffusion distance.

Direct Method

A procedure used for estimating the volume of gas lost by desorption during recovery of freshly cut reservoir coal core or cuttings samples based upon the volume of gas desorbed vs. the square root of desorption time.

Dissolved Gas

Natural gas dissolved in crude oil (see Absorption).

Drainage Area

The reservoir area which supplies fluid to a wellbore.

Drill Collars

Heavy, thick-walled drill pipe used above a drill bit or core barrel in a rotary drill string to increase the weight on the bit and stabilize the drill string

Drill Cuttings

Rock chips cut by a bit in the process of well drilling and removed from the hole by drilling mud while rotary drilling or a bailer while cable tool drilling

Drill Pipe

Heavy pipe used to turn the bit in rotary drilled wells

Drill String

The assemblage of drill pipe, drill collars, core barrel, and drill bit used during rotary drilling

Dry, Ash-Free Basis (daf)

Test data normalized with respect to a theoretical base of no moisture or ash associated with the sample. For coal, this theoretical base is the volatile matter and fixed carbon portions of the sample determined by a proximate analysis.

9.3

Chapter

9

Glossary

Dry, Mineral-Matter-Free Basis (dmmf)

Test data normalized with respect to a theoretical base of no moisture, ash and other select components (e.g., sulfur) associated with the sample. For coal, refer to ASTM D 1757-86 and ASTM D 3177-89.

Effective Porosity

The interconnected pore space available to hold fluids from which fluids can be produced.

Effective Thickness

The portion of the gross thickness of a reservoir that contains producible gas.

Equilibrium Moisture Content

The amount of moisture physically retained by a sample at equilibrium with its surrounding environment. For coal, this value is determined at 96 percent to 97 percent relative humidity and 30 °C (see ASTM D 1412-85) and is sometimes referred to as inherent or bed moisture.

Exinite

A group of microscopically distinguishable coal macerals derived from plant spores, cuticular matter, resins, and waxes (see ASTM D 2796). Exinite exhibits a yellow appearance in thin section, transmitted light microscopy and a dark gray appearance in reflected light microscopy.

Extended Langmuir Isotherm

A Langmuir isotherm extended to account for gases consisting of multiple components

Extraneous (Free) Moisture

The moisture that is not physically or chemically bound to the sample and which can be removed by draining or straining. For coal, this value is determined as the difference between the total moisture measured by ASTM D 3302 and the equilibrium moisture measured by ASTM D 1412-85 and is sometimes referred to as surface or adherent moisture.

Fixed Carbon

The solid residue other than ash obtained by destructive distillation (see ASTM D 3172-89). It is the resultant of the summation of the percentage moisture, ash and volatile matter (all on the same basis) subtracted from 100 percent.

Fracture Porosity

The porosity attributed to fracture void volume.

Free Gas Phase

Gas in the free (vapor) state within the pores and natural fractures.

Free Moisture Content

That portion of the total moisture in coal that is in excess of the inherent moisture.

Fusinite

A microscopically distinguishable coal maceral belonging to the inertinite maceral group (see ASTM D 2796). Fusinite exhibits an opaque appearance in thin section, transmitted light microscopy and a white, yellowish or light gray appearance in reflected light microscopy.

Gas Content

The total volume of gas (corrected to standard conditions) divided by the weight of the rock in which it is stored.

Gas Desorption

see Desorption.

Gas Formation Volume Factor

The ratio of the gas volume in the free state at reservoir pressure and temperature conditions to the gas volume at standard temperature and pressure conditions.

9.4

Gas Hydrates

Crystalline molecular compounds (clathrates) composed of solid three-dimensional hydrogen-bonded lattices of water molecules (host species) having in terstitial cavities occupied by low molecular weight hydrocarbon and other types of gases (guest species).

Gas Kick

A situation in which gas flows uncontrolled into a wellbore. A major gas kick can cause a blowout.

Gas Recovery Factor

The fraction of the gas-in-place that can be economically recovered using presently available technology.

Gas Reserves

The gas-in-place volume that can be economically recovered using presently available technology.

Gas Resource

The total gas-in-place volume whether or not it can be economically recovered using presently available technology.

Gas Saturated

A situation where the total volume of gas stored by a sample is equal to the sample’s gas storage capacity.

Gas Storage Capacity

The maximum volume of gas that can be stored by adsorption at a given set of temperature and pressure conditions by a specific mass or volume of adsorbent material. Gas storage capacity is affected by the type and composition of gas being adsorbed and the physical properties of the adsorbent. The gas storage capacity of coal is affected by its rank, organic content, maceral composi tion, and moisture content.

Gas-Bearing Shale

A kerogen-bearing, finely-laminated sedimentary rock that contains natural gas in the free (vapor) state within the matrix and fracture porosity, absorbed within bitumen, and adsorbed on organic carbon and clay minerals.

Gas-In-Place (GIP)

The volume of gas stored within a specified volume of reservoir rock. For coal seam reservoirs, the reservoir rock includes both coal and interbedded carbonaceous shale. The GIP volume is the product of four reservoir parameters: drainage area, thickness, average in-situ bulk density, and average insitu gas content.

Geopressured Gas

Natural gas dissolved in brine at abnormally high pressures, i.e., pressures exceeding the normal hydrostatic pressure gradient of 0.43 pounds per square inch per foot of depth.

Gross Thickness

The total thickness of a coal gas reservoir containing coal and interbedded organic bearing, and inorganic rocks.

Headspace Volume

The void volume within a sealed container (e.g., a desorption canister).

Hydrostatic Pressure

The pressure exerted by the weight of water at higher levels in the zone of saturation.

Inertinite

A group of microscopically distinguishable coal macerals derived from oxidized woody tissue precursors (see ASTM D 2796). Inertinite exhibits an opaque appearance in thin section, transmitted light microscopy and a white, yellowish or light gray appearance in reflected light microscopy.

9.5

Chapter

9

Glossary

Inherent Moisture

Moisture that exists as an integral part of the coal seam in its natural state including water in pores but not that present in macroscopically visible frac tures (see ASTM D 121-85).

In-Situ Basis

Test data normalized with respect to a base defined by the sample’s natural state or original location. For coal, the natural state or original location refers to the subsurface seam or reservoir location.

In-Situ Gas Content

Gas content data normalized with respect a base defined by the reservoir coal’s average ash content and equilibrium moisture content conditions.

Isotherm (Sorption Isotherm) The relationship, at constant temperature, which describes sorbed gas storage capacity as a function of system pressure. Kerogen

Fossilized insoluble organic material found in sedimentary rocks which can be converted by distillation to hydrocarbon liquids and gases.

Kick

A situation in which formation fluids flow uncontrolled into a wellbore (see Gas Kick).

Langmuir Isotherm

The quantitative relationship, at constant temperature, which describes how a monolayer concentration (i.e., sorbed storage capacity) of adsorbed phase molecules at a homogeneous interfacial surface varies as a function of increasing system pressure.

Langmuir Pressure

The pressure at which the storage capacity of a sample is equal to half the Langmuir storage capacity.

Langmuir Storage Capacity

The maximum volume per sample weight of adsorbed phase gas corresponding to monolayer surface coverage.

Liptinite (Exinite)

A group of microscopically distinguishable coal macerals derived from hydrogen-rich precursors such as spores, cuticular matter, resins, and waxes (see ASTM D 2796). Liptinite exhibits a yellow appearance in thin section, transmitted light microscopy and a dark gray appearance in reflected light micros copy.

Lost Gas Content

The gas volume (normalized to standard conditions) lost by desorption from a coal sample prior to the time that it is sealed in a desorption canister divided by the sample mass.

Lost Gas Time

The elapsed time from the start of desorption to the time that a canister is sealed during which gas is lost from a sample.

Maceral

An organic component of coal, distinguishable with an optical microscope, including mineral matter not discernible with optical microscopy.

Matrix

The solid portion of a rock.

Matrix Porosity

The void space of the matrix material (see Porosity).

9.6

Maturity

The degree to which the original organic material has been altered by physical and chemical changes during coalification. The changes most commonly taken as indicators of the maturity of the organic material include calorific value, moisture content, percent of volatile matter, vitrinite reflectance, and fixed carbon content.

Measured Gas Content

The gas volume (normalized to standard conditions) released from a coal sample during desorption measurements divided by the coal mass.

Mesopore

Pores with a width of between two and fifty nanometers.

Micropore

Pores with a width of less than two nanometers.

MMscf

Million standard cubic feet.

Moist, Mineral-MatterFree Basis

Test data normalized with respect to a theoretical weight base containing moisture but having no ash or other select components (e.g., sulfur) associated with the sample. For coal, refer to ASTM D 1757-86 and ASTM D 317789.

Moisture Content

The amount of moisture in a sample determined under prescribed testing conditions and expressed as a percentage of the original sample mass, i.e., the dry substance mass plus the moisture mass.

Mscf

Thousand standard cubic feet.

Mud Logs

A continuous analysis for entrained oil or gas in the drilling mud and well cuttings while rotary drilling. Drilling conditions and sample lithology may also be reported.

Multicomponent Storage Capacity

Gas storage capacity in a rock for a gas containing more than one component.

Nanometer

10-9 meters.

Natural Fractures

A general term for natural breaks in a rock resulting from mechanical failure caused by stress including cleats, cracks, joints, and faults.

Oil Shale

A kerogen-bearing, fine-grained sedimentary rock that upon distillation yields liquid or gaseous hydrocarbon products.

Organic Fraction Gas Content

The total volume of gas stored by a sample, normalized with respect to a 100% organic fraction base.

Petroleum Reservoir

A subsurface layer of porous, hydrocarbon containing rocks that covers a large areal extent from which crude oil or natural gas can be economically extracted.

Porosity

The fraction of the bulk volume of a material occupied by voids (i.e., the ratio of void space to total bulk volume).

Potash

Potassium carbonate, K2CO3.

Pressure Coring

A coring procedure that involves trapping a cored rock sample downhole within a sealed preventing loss of fluids while retrieving the sample to surface.

9.7

Chapter

9

Glossary

Proximate Analysis

The fraction of the individual compounds contained in a mixture or sample. For coal, this analysis (refer to the methods and procedures given in ASTM D 3172-73) involves the determination of moisture, volatile matter, ash, and fixed carbon (by difference).

Rank

A term used for classifying coals into a natural series based upon their degree of metamorphism or thermal maturity. This classification scheme is based upon the coal’s fixed carbon content, gross calorific value, and agglomerating characteristics (refer to ASTM D 388).

Raw Basis

The actual sample weight including moisture and any other components not normally associated with the sample.

Residual Gas Content

The volume of gas remaining in a sample at the conclusion of canister desorption measurements divided by the sample mass.

Residual Moisture

The weight fraction of moisture remaining in a sample after air drying.

Saturated Reservoir

A reservoir with an in-situ gas content equal to the in-situ storage capacity.

Saturation

The ratio of the fluid volume contained within rock divided by the internal void volume of the rock.

Scf

A volume of gas in cubic feet reported at standard temperature and pressure.

Shale

A fine-grained sedimentary rock, formed by the consolidation of clay, silt, or mud.

Sidewall Core

Rotary drilled (or explosively shot) small diameter (typically 1.9 cm diameter) cores drilled perpendicular to a wellbore axis and recovered to the surface by wireline.

Smith & Williams Method

Lost and total gas content estimate procedure developed by Smith & Williams

Solution Gas

see Dissolved Gas.

Sorbed Gas Phase

see Adsorbed Gas.

Sorption

see Adsorption.

Sorption Isotherm

The relationship, at constant temperature, which describes sorbed gas storage capacity as a function of system pressure.

Sorption Time

A characteristic diffusion time related to the inverse of a rock sample’s diffusivity often defined as the time required to desorb 63% of the original gas content.

Storage Capacity

The total volume of gas that can be contained within a unit volume of reservoir rock by sorption.

Surface (Free) Moisture Content

The amount of moisture that adheres to the surface of a sample and which is removed by air-drying. For coal, this is sometimes referred to as extraneous or adherent moisture.

9.8

Temperature Recovery Time The time required to return a rock sample to its original reservoir temperature during desorption measurements. Thermal Maturity

The degree to which the original organic material has been altered by physical and chemical changes during coalification. The changes most commonly used as indicators of organic matter thermal maturity include calorific value, moisture content, volatile matter content, fixed carbon content, and vitrinite reflectance.

Time Zero

The time at which a rock sample begins to desorb gas.

Total Gas Content

The sum of the lost, measured, and residual gas content originally contained within a rock sample.

Total Moisture Content

The amount of moisture determined as the loss in sample weight by heating in an air atmosphere under rigidly controlled conditions of temperature, time, and air flow. For coals, this value is determined using the procedure given in ASTM D 3302-89a. A white or yellow-white monoclinic mineral: Na3(CO3)(HCO3)•2H2O.

Trona Ultimate Analysis

The fraction of the elements comprising a compound. For coal, this analysis normally includes the determination of carbon, hydrogen, nitrogen, sulfur, ash, and oxygen (by difference).

Undersaturated Reservoir

A reservoir with an in-situ gas content less than the in-situ storage capacity.

Vitrinite

A microscopically distinguishable coal maceral derived from the cell wall components of woody plants (see ASTM D 2796). Typically the most abundant maceral in humic coals. Vitrinite exhibits an orange to red appearance in thin section, transmitted light microscopy and a light to medium gray appearance in reflected light microscopy.

Vitrinite Reflectance

The percentage of light reflectance, measured microscopically in immersion oil, from the polished surface of a vitrinite maceral when illuminated with plane-polarized (white) light (refer to the methods and procedures given in ASTM D 2798). In coal, vitrinite reflectance values vary systematically with fixed carbon content and are widely used as a thermal maturity indicator.

Volatile Matter

The term applied to the total amount of gaseous or vapor materials, other than moisture, that is liberated from a sample upon its being heated under rigidly controlled conditions. Since this is a destructive analysis procedure, the liber ated volatile matter is not an inherent sample component. For coal, volatile matter is defined as the material, other than moisture, liberated under the stan dardized test conditions given in ASTM D 3175-89a.

Volumetric Displacement Apparatus

A device, maintained at ambient conditions, for measuring the amount of gas desorbed from a sample into a desorption canister (described in Chapter 3).

Water Saturation

The fraction of the pore space that is filled with formation water or brine.

9.9

Chapter

9

Glossary

Weathering

Progressive, naturally occurring degradation processes involving chemical or microbial reactions, in some instances accompanied by physical changes, between a material and elements of its local environment such as the oxygen in air, moisture, and ultraviolet light.

Well Logs

A graphical record of the measured or computed physical properties of the rock section encountered in a well, plotted as a continuous function of depth.

Wireline Core

A core sample retrieved to the surface by means of a steel line or cable while the drill bit and drill string remain in place within the wellbore.

9.10