A Guide to Coal Bed Methane Operations

®

A Guide To

Coalbed Methane Operations

A Guide to Coalbed Methane Operations v

v

v

Copyright © 1992 by Gas Research Institute All Rights Reserved

By

Vicki A. Hollub Taurus Exploration, Inc. (Birmingham, Alabama)

Paul S. Schafer Schafer Associates (Oxford, Ohio)

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About the Authors Vicki A. Hollub, P.E. works with Taurus Exploration, Inc. as a reservoir engineer at the GRI Rock Creek research project in Alabama. She previously worked ten years with OXY USA as a drilling engineer and as a senior production engineer. Vicki holds a B.S. in Mineral Engineering from The University of Alabama and is a registered professional engineer. She is a member of the Society of Petroleum Engineers (SPE) and currently serves as chairperson of the SPE Professional Engineering Registration Committee.

Paul S. Schafer owns and operates Schafer Associates, a consultancy that provides technical communication services to the petroleum and petrochemical industries. He previously worked ten years with Marathon Oil Company as a production and operations engineer and as an advanced reservoir engineer. Paul holds a Master of Technical and Scientific Communication from Miami University at Oxford, Ohio and a B. S. in Petroleum Engineering from Marietta College. He is a member of the Society of Petroleum Engineers and the Society for Technical Communication. ❖

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Disclaimer 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 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, nor 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 for damages resulting from the use of, any information, apparatus, method, or process disclosed in this publication. Reference to trade names or specific commercial products, commodities, or services in this publication does not represent or constitute an endorsement, recommendation, or favoring by GRI of the specific commercial product, commodity, or service.

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About This Guide

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Guide to Coalbed Methane Operations provides practical information on siting, drilling, completing, and producing coalbed methane wells. Whether you’re an experienced coalbed methane producer or you’re exploring coalbed methane operations for the first time, this guide will give you the information you need to make informed decisions about producing this resource. This guide is a “working reference.” It will help you in planning and performing field activities. Each chapter provides an overview of key field operations as well as specific guidelines for performing them. The chapters also describe the equipment and materials required for each operation. Though the guide focuses on developing multiple coal seams in the Black Warrior Basin, you can apply many of the concepts to other coal basins as well. You will notice an emphasis on practical applications rather than lengthy technical explanations and engineering data. However, if you want to investigate any of the topics in greater depth, the Additional Resources section at the end of each chapter will guide you to selected references. The information in this guide represents the shared knowledge and expertise of many specialists in the coalbed methane field. Much of this information resulted from GRI’s Rock Creek Methane from Multiple Coal Seams Completion Project and from several operators and service company representatives in the Black Warrior Basin of Alabama. We hope this guide contributes to greater understanding of coalbed methane production and more economical development of this gas resource. ❖

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Table of Contents About this Guide i List of Figures and Tables iv Conventions Used in This Guide vii Acknowledgments viii About Producing Coalbed Methane x Chapter I

Selecting and Preparing a Field Site

1-1

Protecting Wetland Areas 1-2 Disposing Produced Water 1-3 Controlling Non-Point Source (NPS) Pollution 1-4 Preventing Spills 1-13 Safety and Operating Guidelines 1-14

ii

Chapter 2

Drilling and Casing the Wellbore Planning the Drilling Program 2-2 Drilling the Wellbore 2-32 Coring the Wellbore 2-36 Casing and Cementing the Wellbore 2-4

2-1

Chapter 3

Wireline Logging Sources for Estimating Reservoir Properties 3-2 Open Hole Logging Tools 3-4 Selecting an Open Hole Logging Suite 3-35 Guidelines for Open Hole Logging 3-36 Cased Hole Logging Tools 3-37 Selecting a Cased Hole Logging Suite 3-41 Guidelines for Cased Hole Logging 3-42 Production Logging Tools 3-44

3-1

Chapter 4

Completing the Well Reservoir Considerations in Completing Coalbed Methane Wells 4-2 Objectives of Completing the Well 4-2 Completing in Open Hole 4-4 Completing in Cased Hole 4-8 Accessing the Formation 4-10 Selecting Production Tubing 4-27 Working Over Wells 4-27

4-1

Chapter 5

Fracturing Coal Seams Performing a Minifracture Test 5-2 Planning a Fracture Treatment Design 5-4 Preparing for a Fracture Treatment 5-30 Performing a Fracture Treatment 5-35 Evaluating a Fracture Treatment 5-48

5-1

Chapter 6

Selecting Production Equipment and Facilities Estimating the Volume of Water to be Produced 6-2 Pumping Equipment 6-3 Power Supply for Pumping Equipment 6-19 Surface Production Facilities 6-23 Gas Compressors 6-35 Gas Dehydration Equipment 6-40

6-1

Chapter 7

Operating Wells and Production Equipment Preparing Surface Facilities for Production 7-2 Unloading the Well 7-3 Bringing the Well on Line 7-8 Troubleshooting Well and Equipment Problems 7-8

7-1

Chapter 8

Treating and Disposing Produced Water Characteristics of Coalbed Methane Produced Water 8-2 Regulations and Permitting for Water Disposal 8-6 Considerations for Designing a Water Disposal System 8-8 Methods for Treating and Disposing Produced Water 8-10

8-1

Chapter 9

Testing the Well Performing Pressure Transient Tests 9-2 Evaluating Production from Multiple-Seam Wells 9-21

9-1

Appendix A

Summary of Permitting Requirements for Drilling a Coalbed Methane Well in Alabama Quality Control and Job Supervision Guidelines for Stimulation Treatments Procedures and Surface Equipment for Implementing the Forced Closure Fracturing Technique

Appendix B Appendix C

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T

Chapter 2

Figures and Tables Drilling and Casing the Wellbore Figure 2-1 Figure 2-2 Figure 2-3 Figure 2-4 Figure 2-5 Figure 2-6 Figure 2-7

Chapter 3

Wireline Logging Figure 3-1 Figure 3-2 Figure 3-3 Figure 3-4 Figure 3-5 Figure 3-6 Figure 3-7 Figure 3-8 Figure 3-9 Figure 3-10 Figure 3-11 Figure 3-12 Figure 3-13 Figure 3-14 Figure 3-15 Figure 3-16 Figure 3-17 Table 3-1 Table 3-2 Table 3-3 Table 3-4 Table 3-5 Table 3-6 Table 3-7 Table 3-8 Table 3-9

Chapter 4

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3-1

Bulk Density Log 3-6 Comparison of Conventional and Mineral Logging Density Logs 3-9 Dual Induction/Shallow Log 3-13 Phasor Induction Log 3-14 SP Log 3-20 Compensated Neutron Log 3-21 Comparison of Cleat Orientation from Microscanner® Log & Cores 3-23 Sonic Log 3-25 Full Waveform Sonic Log 3-27 Geochemical and Carbon/Oxygen Log 3-29 VOLAN® Log 3-30 Spectral Gamma Ray Log 3-32 Computer-Processed Coal Quality Log 3-34 Cement Bond/Variable Density Log 3-40 Wellhead Configuration for Annular Logging 3-44 Flowmeter Developed for Coalbed Methane Wells 3-46 Flowmeter Log 3-47 Primary Non-Log Sources for Estimating Reservoir Properties 3-2 Logging Sources for Estimating Reservoir Properties 3-3 Matrix Densities for Common Formations 3-7 Photoelectric Absorption Index for Common Formations 3-10 Total Natural Radioactivity of Common Formations 3-11 Responses for Logs Commonly Used to Evaluate Coals 3-16 Logging Tools for Open Hole Exploration Wells 3-35 Logging Tools for Open Hole Development Wells 3-36 Logging Tools for Cased Hole Wells 3-42

Completing the Well Figure 4-1 Figure 4-2 Figure 4-3

2-1

The Planning Process for Drilling a Coalbed Methane Well 2-2 Setting Casing Through Zones with Lower Fracture Gradients 2-5 Selecting Hole Size 2-7 Casing Selection Chart 2-11 Conventional Rotary and Rotary-Percussion Drilling Techniques 2-16 Typical Cementing Manifold 2-50 Two Stage Cementing 2-52

Single-Zone Open Hole Completion 4-5 Multiple-Zone Open Hole Completion 4-8 Multiple-Zone Cased Hole Completion 4-9

4-1

Figure 4-4 Figure 4-5 Figure 4-6 Figure 4-7 Figure 4-8

Chapter 5

Fracturing Coal Seams Figure 5-1 Figure 5-2 Figure 5-3 Figure 5-4 Figure 5-5 Figure 5-6 Figure 5-7 Table 5-1 Table 5-2 Table 5-3 Table 5-4

Chapter 6

Chapter 8

6-1

Beam Pumping System 6-5 Top-Seating Pump Hold-Down 6-8 Bottom-Seating Pump Hold-Down 6-9 Gas Anchor 6-10 Progressing Cavity Pump 6-13 Gas Lift Installation 6-16 Electric Submersible Pump 6-18 Water Flow Path for Fields In Black Warrior Basin 6-24 Gas Flow Path for Fields In Black Warrior Basin 6-30 Artificial Lift Methods for Coalbed Methane 6-4 Comparison of Gas Flow Meters 6-32 Typical Sales Gas Specifications 6-33

Operating Wells and Production Equipment Figure 7-1 Figure 7-2 Figure 7-3 Figure 7-4

5-1

Instantaneous Shut in Pressure (ISIP) 5-8 Wellbore Configurations for Fracturing 5-13 "Dead String" for Measuring Bottomhole Pressure 5-16 Nolte Plot for Evaluating Fracture Pressures 5-38 Tiltmeter Sensor 5-53 Tiltmeter Installation 5-54 Tiltmeter Displays for Fractures 5-55 Minifracture Tests 5-2 Information for Designing a Fracture Treatment 5-5 Pumping Schedule for a Gel Fracture Treatment 5-28 Pumping Schedule for a Foam Fracture Treatment 5-29

Selecting Production Equipment and Facilities Figure 6-1 Figure 6-2 Figure 6-3 Figure 6-4 Figure 6-5 Figure 6-6 Figure 6-7 Figure 6-8 Figure 6-9 Table 6-1 Table 6-2 Table 6-3

Chapter 7

Perforated Cased Hole Completion 4-12 Slotted Cased Hole Completion 4-13 Fracture Communication from Restricted Access 4-21 Limited Entry Multiple-Zone Completion 4-22 Lithology of the Well P5 Interseam Completion 4-25

7-1

Beam Pumping System 7-10 Troubleshooting Beam Pumps (I) 7-11 Troubleshooting Beam Pumps (II) 7-12 Troubleshooting Progressing Cavity Pumps 7-16

Treating and Disposing Produced Water Figure 8-1

Water Disposal System in Black Warrior Basin 8-13

Table 8-1

Typical NPDES Water Discharge Limitations 8-7

8-1

v

Figures and Tables

Chapter 9

9-1

Testing the Well Figure 9-1 Figure 9-2 Figure 9-3 Figure 9-4 Table 9-1

Slug Test Equipment Configuration 9-4 Typical Coalbed Methane Production Decline Curve 9-23 Two-Seam Well Test Using the ZIP Tool 9-24 Three-Seam Well Test Using the ZIP Tool 9-25 Data Frequency for Slug Tests 9-8 ❖

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(Cont'd)

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Conventions Used in This Guide

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everal special elements in this guide’s text will help you quickly identify different types of information: 4.

Numbered information gives step-by-step instructions for a procedure.

n

A solid box indicates general guidelines to follow before or during a particular task.

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A cut diamond highlights a list of characteristics, features, benefits, or limitations of an object, technique, or procedure.

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A solid diamond describes a circumstance or condition you might encounter and then explains possible ways to respond to the situation.

▲ Caution A triangular “caution” note warns you about a situation that could be unsafe, environmentally hazardous, or damaging to equipment. ❈Important Information that is particularly important for you to understand is highlighted with the symbol above.

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1 A

Acknowledgments

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Guide to Coalbed Methane Operations was possible because of the generous contributions of experience and knowledge by the people listed below: Dr. Richard Schraufnagel — Gas Research Institute (GRI) Senior Project Manager, Coalbed Methane Engineering Dr. Schraufnagel generated the concept for this guide and provided important guidance and support throughout its development. Stephen Spafford — Taurus Exploration, Inc. Manager, Rock Creek Project Selecting and preparing a field site, drilling, completing, fracturing, and treating and disposing produced water Francis Dobscha — GeoMet, Inc. Special thanks to Fran for his extensive contributions on selecting and preparing a field site, drilling, completing, fracturing, selecting production equipment, operating wells and production equipment, treating and disposing produced water, and testing wells Jerry Saulsberry — Taurus Exploration, Inc. Drilling, wireline logging, fracturing, and testing wells Peter Steidl — Taurus Exploration, Inc. Wireline logging Paul Stubbs — GeoMet, Inc. Testing wells Randy McDaniel — Taurus Exploration, Inc. Selecting and preparing a field site, and treating and disposing produced water Brian Luckianow — Taurus Exploration, Inc. Selecting and preparing a field site, and treating and disposing produced water

viii

Jerry Sanders and Eddie Jones — Black Warrior Methane, Inc. Drilling, fracturing, selecting production equipment and facilities, and operating wells and production equipment Michael Conway — Stim-Lab, Inc. Completing and Fracturing Allen Neel and Bill Lawrence — Black Warrior Drilling and Completion Company Drilling and completing Brad Taff and Ted Martin — Halliburton Logging Services, Inc. Wireline logging Daniel Felcman and Doug Womack — Tidewater Compression Services, Inc. Selecting gas compression equipment Brad Benge and Roger Hudson — Tidewater Compression Services, Inc. Operating and maintaining gas compression equipment Richard Montman, Dick Bretzke, and Robert Singleton — Halliburton Services, Inc. Fracturing and cementing Jerry Broadway — Black Warrior Drilling and Completion Company Selecting and operating progressing cavity pumps Adam Olszewski — ResTech, Inc. Wireline logging Larry Strider — AMPCO Resources, Inc. Drilling, completing, and selecting pumps Gary Conner — Computalog Wireline Services, Inc. Production logging David Stuart — Robbins and Myers, Inc. Selecting and operating progressing cavity pumps Matt Hollub — Graphic Artist Cover Art ❖

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ix

About ProducingCoalbed Methane

C

oalbed methane is produced commercially in the United States, and it has attracted worldwide attention as a potential source of costcompetitive natu ral gas. Since the beginning of the coalbed methane industry in the mid1970s, operators have modified and applied petroleum industry technology to improve the operation of their fields. However, conventional oil and gas technology does not always work effectively for producing coalbed methane. Because coal geology is so different from that of typical gas formations, you must use a different approach that takes into account: ■

The composition of the rock. Coal is 90 percent organic, whereas conven tional gas formations are nearly 100 percent inorganic.

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The different mechanical properties of coal. Coal is brittle and weak, and it tends to collapse in the wellbore.

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Coal’s naturally occurring fractures, or cleats. These fractures, called face cleats and butt cleats, are extensive in coals. Most coal reservoirs, however, require hydraulic fracturing to stimulate produc tion.

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Coal’s gas storage mechanism. Gas is adsorbed or attached onto the internal surfaces of the coal, whereas gas is confined in the pore spaces of conventional rocks.

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The large volumes of water present in the coal seams. Water must be pumped continuously from coal seams to reduce reservoir pressure and release the gas.

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The low pressure of coal reservoirs. Backpressure on the wellhead must be kept low to maximize gas flow. And all produced gas must be compressed for delivery to a sales pipeline.

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The modest gasflow rates from coal reservoirs. Capital outlays and operating expenses must be minimized to produce an economical project.

x

These unique characteristics of coalbed reservoirs will allow few inefficiencies. Successfully developing a coalbed methane field requires pru dently managing the technical as well as the economic aspects of the project. To develop techniques for economically producing coalbed methane fields, Gas Research Institute (GRI) and Taurus Exploration, Inc. designed The Rock Creek Methane from Multiple Coal Seams Completion Project. This field research site is located in the Black Warrior Basin southwest of Bir mingham, Alabama. The overall objective of this project, initiated in 1983, is to develop tech nology for more cost-effective production of methane from shallow, thin multiple coal seams using single vertical wellbores. Ile project has specifi cally focused on determining the best combination of drilling, completing, stimulating, and operating techniques to economically produce these wells. The Rock Creek project and the work of other operators in the Black Warrior Basin have produced many practical techniques and guidelines for developing coalbed methane fields. The cooperation and open communication between operators and service companies in the Black Warrior Basin have been necessary to advance both basic knowledge and applied experience in producing methane from coal seams.

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1

Selecting and Preparing a Field Site

Chapter

I

n selecting and preparing a field site, you will make some of the most important decisions about the coalbed methane project. These decisions will affect the environmental, safety and operations aspects of the project. These factors, in turn, will likely influence the project’s economic success.

Environmental Guidelines As citizens become increasingly aware of and concerned about environmental issues, the number and scope of environmental regulations continue to grow. Certain activities related to coalbed methane production are regulated by State and Federal agencies to help prevent damage to the environment. By incorporating sound environmental management into the planning and operation of a coalbed methane field, you will help protect the environment, minimize current regulatory requirements, and possibly avoid costly penalties. You should become familiar with the applicable environmental regulations in your area before selecting and preparing a field site. The U.S. Environmental Protection Agency (EPA) has primary jurisdiction over environmental regulations in the United States, but administration of regulations varies from state to state. In the Black Warrior Basin of Alabama, the Alabama Department of Environmental Management (ADEM) and the Army Corps of Engineers (ACOE) administer most environmental regulations.

Chapter

1

Selecting and Preparing a Field Site

The primary environmental regulations for developing coalbed methane sites in the Black Warrior Basin are:

• Protecting Wetland Areas • Disposing Produced Water • Controlling Non-Point Source (NPS) Pollution • Preventing Oil Spills • Protecting Historical Sites

Protecting Wetland Areas The impact of wetlands presents the single most critical regulatory issue in establishing right-of-way for pipelines, roads, and pads. Operating coalbed methane facilities often requires some activity in wetlands (e.g. an access road or a pipeline system). Coalbed methane facilities or activities which occur in wetlands are regulated and require a permit. By knowing wetlands regulations, you can incorporate them into site planning to avoid or minimize dirt fill placed in wetlands. If you consider wetlands at the onset of planning, you can likely locate most facilities in non-wetland (upland) areas and thus avoid or minimize regulatory permitting. To identify or verify wetlands areas within the proposed site, you should have a qualified biologist who knows the wetlands regulations conduct a field survey. Make sure this wetlands survey is conducted before completing final field development plans. Regulatory agencies use “The Federal Manual for Identifying and Delineating Wetlands” (“Federal Manual”) as the technical basis for identifying and delineating wetlands. The person conducting the field investigation must be familiar with wetlands and must be trained to use this manual. Because the ACOE makes final decisions on jurisdictional wetlands delineations, you should confirm the findings of the field survey with the ACOE. If the area is determined to be a wetland, a jurisdictional wetland boundary should be delineated. If possible, you should move the proposed facility site to avoid or minimize impacts to wetlands. If you cannot avoid impacts to wetlands, you must apply for a wetlands

1-2

Disposing Produced Water

permit. For more information about permits, refer to Additional Resources at the end of this chapter.

Disposing Produced Water The ability to dispose produced water is key to the successful operation of a coalbed methane field. Produced water must be managed to comply with the National Pollutant Discharge Elimination System (NPDES) requirements. The NPDES is governed by the U.S. Environmental Protection Agency (EPA) and is administered locally by the states. If NPDES standards are not met, production from the field could be forced to stop. Therefore, you must carefully plan for the management of produced water when selecting the field site. The NPDES program defines the criteria for discharging water produced from coalbed methane wells into waterways. No produced water can be discharged into a river or stream without an NPDES permit. In the Black Warrior Basin, this program is administered by the Alabama Department of Environmental Management (ADEM). Your selection of a field site should be based on a thorough analysis of water treatment and disposal options (refer to Chapter Eight for more information). Begin by learning the NPDES permitting requirements and procedures in your area. Give special attention to the questions below, which could influence your choice of a site: ■

What is the maximum volume of produced water which I will need to dispose?

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What is the chemical composition of this water?

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Are there waterways near the site that could be used for water discharge?

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Do these waterways have sufficient year-round flow to allow discharge in compliance with discharge limits?

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Are other operators using the same drainage basin to discharge produced water?

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Chapter

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Selecting and Preparing a Field Site

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What discharge limits do the regulatory agencies place on the waterway overall and on individual dischargers into the waterway?

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What is the life of a discharge permit?

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How do I renew a discharge permit?

For more information on treating and disposing of produced water, refer to Chapter Eight.

Controlling Non-Point Source (NPS) Pollution The Alabama Department of Environmental Management (ADEM) defines a pollutant as any item entering a waterbody that changes the composition of the water. A pollutant entering a waterbody through a NPDES permitted discharge is called a point source discharge. However, a pollutant that reaches a waterbody by other means that are not traceable to an identifiable facility, such as storm water runoff, seepage, percolation, etc., is called a non-point source discharge. Non-point source regulation, which is controlled in Alabama by ADEM and EPA, probably receives the highest priority of any regulation during coalbed methane development, and has increased the finding cost for methane significantly in recent years. Therefore, when planning a field site, you should consider the requirements concerning non-point source pollution. One of the best ways to manage potential non-point source discharge is by implementing a Best Management Practices Plan (BMP) A BMP presents policies and procedures that can lessen the probability of initial causes of non-point source pollution. The Coalbed Methane Association of Alabama developed such a plan to assist operators in the Black Warrior Basin. This BMP, which is presented below, provides sound guidelines for:

• Controlling Erosion • Siting and Constructing Roads

1-4

Controlling Non-Point Source Pollution

• Developing Drilling Locations • Siting and Constructing Pipelines • Preventing Oil Spills

Controlling Erosion The major component of non-point source pollution is sedimentation from soil erosion. Sedimentation reduces stream capacities, interrupts ecosystems, carries other pollutants into a waterbody and may cause other potential environmental problems. Soil types, which vary greatly from one location to another, significantly influence soil erosion characteristics and are a factor in designing and implementing BMPs. To minimize erosion when constructing coalbed methane facilities, practice these general erosion control techniques:

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Divert runoff from well sites and roads onto level vegetated areas, terracing, riprap, or other areas that will disperse the water and prevent soil erosion.

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Install temporary erosion controls such as hay bales and/or silt fences in the natural drainage areas before or during the construction of well sites, roads, etc.

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Install more permanent erosion control devices (i.e., geotextiles, riprap, matting, etc.) in areas of severe erosion.

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Line, fertilize, and seed and/or mulch roadsides, drilling locations and pipelines where slopes are sufficient to cause high velocity flow and erosion. Perform this operation as soon as practical after construction and use accepted soil conservation practices.

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Chapter

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Selecting and Preparing a Field Site

■

Pave and cover with gravel or plant vegetation on all disturbed areas, regardless of location. Perform this operation as soon as practical, and maintain all erosion controls until the disturbed area is covered or permanent vegetation is re-established.

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Reuse onsite topsoil, if available, on the surface of each site. This action will help maintain vegetation in disturbed areas.

Siting and Constructing Roads Roads are necessary to provide access to each well and to facilities. Permanent access roads are usually built so that equipment can be moved in and out of the locations as needed initially and during later maintenance. Roads also provide access for monitoring wells and facilities. When siting access roads, follow the guidelines below to the extent practical: ■

Use existing roads, when suitable, to prevent further soil disturbance.

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Site roads along ridge lines to minimize road grades and to lessen the potential of disturbing a water course.

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Minimize road grades whenever practical.

When constructing roads, follow the guidelines below whenever practical:

1-6

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Construct roads and roadway drainage only under the guidance of a person experienced in road construction techniques and erosion control.

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Install velocity breakers (stabilized water bars) to control high velocity flow and potential stream erosion.

Controlling Non-Point Source Pollution

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Avoid constructing roads through areas having highly erodible soils, wetlands or wet meadows. If necessary to build roads in these areas, use erosion control methods and wetland road construction techniques to minimize disturbance. If operations are not permitted under Section 404 of the Clean Water Act (Nationwide Permit) you must obtain individual permits from the U.S. Corps of Engineers (ACOE) before disturbing any wetland area. In addition, you may need an ACOE permit under the requirements of Section 10 of the Rivers and Harbors Act of 1899 and/or section 193 of the Marine Protection, Research and Sanctuaries Act.

❈ Important

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Test quarterly for pH any mine tailings (i.e., black or red rock) used in roadbed construction. Test each source of “black or red” rock. The pH must range from 6 to 9 pH units. Keep good records of the testing for three years.

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Never use known hazardous or toxic materials in constructing roadbeds.

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Maintain vegetated filter strips of sufficient length to assist sediment deposition between streams and roads. If terrain limitations necessitate, use other permanent methods (geotextiles, riprap, matting, etc.) instead of or in conjunction with vegetated filter strips, provided the water course is not altered or diverted.

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Take measures to prevent construction materials (dirt, boulders, rock, trees, etc.) from being deposited into water-bodies. If these materials inadvertently enter the water, take environmentally sound measures to remove them immediately. These measures should prevent further environmental damage.

Constructing Stream Crossings

Because of the topography of coalbed methane operations in many areas, you may need to cross a stream with a road. Roadways can cause

1-7

Chapter

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Selecting and Preparing a Field Site

more water course disturbance, redirect flow, and/or possibly limit movement of stream life. Through planning and careful construction, you can eliminate or significantly lessen potential environmental damage when crossing streams. When developing roadstream crossings, follow the guidelines below whenever practical:

❈ Important

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Minimize stream crossings whenever practical. Use existing culverts, bridges, fords and/or other crossings whenever possible.

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Make stream crossings at right angles to the main stream channel, when practical and/or when it will limit environmental damage.

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Test quarterly for pH each source of mine tailings (black or red rock) used for fill material during construction of the stream crossing. The pH must range from 6 to 9 pH units. Keep good records of the testing for 3 years.

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Never use known hazardous or toxic materials in constructing stream crossings.

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Submit a stream crossing plan for pre-approval to the state environmental agency. In Alabama, these plans are based on mean stream water flow of less than 10 cfs (using the best available historical data). If the crossing plan is for a stream with mean water flow of 10 cfs or greater or where there is greater than 200 cubic yards of fill below the plane of the ordinary high water mark, you must coordinate the plan with the Alabama Department of Environmental Management (ADEM) and the Army Corps of Engineers (ACOE) or the environmental agency in your state.

1-8

Controlling Non-Point Source Pollution

Developing Drilling Locations Drilling pads are constructed to allow movement of a drilling rig and other heavy equipment into the location. This location is usually an allweather installation that provides access for field people to maintain and observe the well. A drilling or reserve pit is a temporary earthen pit for storing materials used or generated in drilling or working over the well. The reserve pit may also be used as an emergency catch basin for location runoff, water produced during drilling operations, or oil from equipment which may be inadvertently spilled. This pit helps prevent environmental damage by eliminating discharge of liquids and solids off the drilling pad. To eliminate or minimize environmental damage, practice the following guidelines, whenever possible, in constructing drilling pads: ■

Keep the size of the drilling pad as small as practical to lessen the amount of surface area disturbed.

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Minimize all slopes and use appropriate erosion control and construction techniques to lessen erosion of those slopes.

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Construct pads and/or pits at a sufficient distance from a waterbody for maintenance of a streamside management zone (SMZ). A streamside management zone is an area along a stream bank where existing vegetation is not disturbed, which helps prevent soil from moving into the stream. If pads and/or pits are necessarily built adjacent to water bodies, take appropriate measures to protect that waterbody and water quality. If sufficient SMZ area is not available, use other erosion control measures in conjunction with available SMZ to lessen potential water quality and water body damage, provided the water course is not altered or diverted.

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Take measures to prevent construction materials (dirt, boulders, rock, trees, etc.) from being deposited into waterbodies. If these materials inadvertently enter the water, take environmen-

1-9

Chapter

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Selecting and Preparing a Field Site

tally sound measures to remove them immediately. These measures should prevent further environmental damage.

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Contour sites during construction to prevent stormwater runoff from creating erosion paths.

To eliminate or minimize environmental damage, practice the following guidelines, whenever possible, in constructing drilling pits: ■

Do not use materials that adversely affect pit wall integrity (i.e., trees, tree stumps, large boulders, etc.).

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Construct pits, if practical, in cut or non-disturbed areas instead of areas that have been dirt filled. If necessary, to construct pits in fill, take measures to compact the pit walls to ensure structural integrity. Compact all fill areas and all containment pits built in fill material.

1-10

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Line pits with polyethylene or other non-permeable material in areas where soil types do not prevent potential contamination of groundwater.

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Dispose of pit waste waters under the guidelines established by the ADEM Interim Land Application Guidelines (or your state environmental agency), and the subsequent BMP plans filed by each operator for handling these fluids.

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Do not place in or over levees or walls siphons or openings that would permit escape of contents thereby causing pollution or contamination.

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Do not allow liquid level in pits to rise within two feet of the pit levees or walls. Maintain pit levees or walls at all times to prevent deterioration, subsequent overfill, and leakage of contents to the environment.

Controlling Non-Point Source Pollution

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Do not place into a reserve pit any oil, trash or other materials which would increase the difficulty in cleanup of the pit or otherwise harm the environment. Properly store or dispose such material according to applicable state or federal regulations. Do not burn or bury garbage on site. Dispose all garbage at an approved landfill site.

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You may burn trees and stumps (not household garbage) on location after notifying the Alabama Forestry Commission and according to local, State, and Federal regulations.

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Empty and close drilling pits by burying them after drilling and fracturing operations are completed. Contour and seed the area. Before closing the pit, drain and haul away liquids in the pit and remove or perforate the pit liner.

Siting and Constructing Pipelines Pipelines are necessary in coalbed methane operations to collect produced water to a central facility and discharge site. Pipelines are also needed to collect natural gas from individual wells to compression facilities, and from compression facilities to gas sales lines. Because pipelines are usually buried, they disturb a water course for a very short time. By applying proper erosion/sedimentation control techniques, you can limit environmental damage. When siting pipelines, follow the guidelines below to the extent practical: ■

Site gathering lines along road rights-of-way.

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Minimize stream crossings if you cannot follow roadways. If necessary to cross streams while constructing a pipeline, minimize stream disturbance and use erosion control techniques to prevent sedimentation of the stream body downstream of the crossing.

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Chapter

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Selecting and Preparing a Field Site

If operations are not permitted under Section 404 of the Clean Water Act (Nationwide Permit), the operator must obtain individual permits from the Army Corps of Engineers before disturbing any wetland area.

■

Minimize pipeline grades where practical.

■

Minimize rights-of-way within acceptable pipeline construction techniques.

When constructing pipelines, follow the guidelines below to the extent practical: ■

Construct pipelines only under the guidance of a person experienced in pipeline construction techniques and erosion control.

■

Install water bars on extreme pipeline right-of-way grades to reduce runoff velocities.

■

Avoid areas of highly erodible soils, wetlands and wet meadows. If necessary to construct pipelines in these areas, use erosion control methods and wetland pipeline construction techniques to minimize disturbance to these areas.

■

Maintain vegetated filter strips of sufficient length to assist sediment depositions between streams and pipelines. If terrain limitations necessitate, use other permanent methods (geotextiles, riprap, matting, etc.) instead of, or in conjunction with, vegetated filter strips.

■

Backfill trenches with soil according to accepted pipeline construction techniques. ■ Minimize pipeline surface disturbance.

1-12

Preventing Spills

Preventing Spills By properly siting a coalbed methane facility, you can greatly reduce control requirements and impacts associated with a release event (spill). Any coalbed methane operation must prepare a Spill Prevention Control and Countermeasure Plan (SPCC) to prevent the discharge of oil from any facility into or upon any waters of the state. This plan is required under Title 40 of the Code of Federal Regulations, Part 112 (40 CFR 112), “Oil Pollution Prevention-Non-Transportation Related Onshore and Offshore Facilities”. The basic elements of an SPCC Plan consist of the identification and description of the following: ❖

General setting of the facility

❖

Inventory of spills and potential spill sources

❖

Structures and/or equipment to prevent spills from reaching waters of the state and conformance with applicable SPCC guidelines.

The operator of a coalbed methane operation is responsible for determining which specific parts of the regulation apply to his operation. When planning a coalbed methane site, you should carefully consider where you locate potential oil spill sources such as compressor stations, bulk waste oil storage, and fuel bulk storage. For example, in most cases it is advantageous to locate compressors on top of hills or knolls. However, if a large oil spill occurred at the compressor, oil could migrate quickly down the hill and into streams. Siting a facility away from potentially environmentally sensitive areas such as streams, rivers, and wetlands greatly reduces exposure to any mitigative action required in the event of an oil release. Planning facilities to comply with SPCC requirements will help reduce unforeseen spill cleanup costs. If a spill should occur, effective control

1-13

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Selecting and Preparing a Field Site

measures will help reduce impacts to the environment and necessary clean-up efforts.

Protecting Historical Sites To protect any sites having potential historical or cultural significance, you should have an historical or cultural resource assessment performed on the site before beginning any development. Such an assessment can identify areas that should not be disturbed and can help avoid unnecessary problems in developing the site. To find a person qualified to perform an historical or cultural resource assessment, you can contact a university or historical center in your area.

Safety and Operating Guidelines In planning a coalbed methane site, you will make many important decisions that will affect the safety of workers and the efficient operation of the field throughout its life. To help ensure a sound site development plan, follow the guidelines below:

Pre-Planning

❈ Important

■

Learn all applicable State and Federal environmental regulations before selecting and preparing a site. For more information see “Environmental Guidelines” in this guide.

■

Establish good relations with landowners and residents near the field site. These people can be great allies for your project if treated with courtesy and respect. They may be instrumental in granting mineral rights and access rights-of-way and in reporting any trespassing or vandalism at the site. Meet and talk with landowners and residents individually before conducting any site surveys or other field activities. Explain plans for developing the field and what types of activities they could expect from a coalbed methane operation. Candidly address their questions, concerns, and fears.

1-14

Safety and Operating Guidelines

■

Before beginning site development, delineate roads, drilling pads and pits, and facility locations with visible reference markers. Carefully review development plans with the site developers. These preparations will minimize environmental impact and help ensure that site developers do not harm life or property of nearby landowners and residents.

Clearing Timber ■

If site development will involve clearing a substantial amount of timber, you may consider contracting with a timber company to cut and purchase the timber. Obtain necessary authorization from landowners before clearing any timber. Contracting timbering to a qualified timber company may make site development safer and easier. In addition, revenue from selling the timber may help offset any payments to landowners for timber removed during site preparation.

Constructing Access Roads ■

Place gravel or similar material on roadbeds to provide a stable surface for heavy equipment. Road surfacing is especially important during the winter and wet seasons.

■

Plan main access road(s) into the site with the help and cooperation of a county commissioner (or equivalent public official) to help ensure safe road design.

■

Construct roads along ridge tops when practical. Attempt to design roads so drivers will have a clear line of sight.

■

Avoid designing roads with sharp curves, blind spots, steep grades, or in or near streams, valleys, or severe drop-offs.

■

Place state-approved caution signs on both sides of the en-

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Selecting and Preparing a Field Site

trance to the road(s) from any highways. Consult the state Department of Transportation for the correct specifications and placement of these signs and any other requirements.

Developing Well Sites

1-16

■

Develop the well site at least several months in advance of well work. This step will facilitate proper drainage and create a more stable surface for heavy equipment.

■

Develop well sites during the dry summer months to significantly reduce costs.

■

Determine the size of the well site based on the space needed to accommodate not only the drilling rig, but the fracturing equipment (fluid tanks, pumps, blenders, turbines, etc.) as well.

■

Locate production equipment (separators, meters, compressors, tanks, etc.) around the perimeter of the site to create an open work area near the wellhead.

■

Locate production equipment (separators, meters, compressors, tanks, etc.) near main gas and water collection lines and power lines to avoid digging up the well pad area for repairs.

❖

❖

❖

Additional Resources

Additional Resources

“Best Management Practices Plan For Non-Point Source Discharge Control, Coalbed Methane Resource Extraction Industry,” Coalbed Methane Association of Alabama and Alabama Department of Environmental Management, 1990.

“Environmental Protection Agency Regulations on Oil Pollution Prevention,” 40 CFR 112, March 26, 1976.

Federal Interagency Committee for Wetland Delineation, 1989. “Federal Manual for Identifying and Delineating Jurisdictional Wetlands,” U.S. Army Corps of Engineers, U.S. Environmental Protection Agency, U.S. Fish and Wildlife Service, and U.S.D.A. Soil Conservation Service, Washington, D.C. Cooperative Publication.

Federal Register, Part II Department of Defense, Corps of Engineers, Department of the Army, 33 CFR Parts 320 through 330, “Regulatory Programs of the Corps of Engineers,” Final Rule, Vol. 51, No. 219, Thursday November 13, 1986, Rules and Regulations.

Luckianow, B.J., W.C. Burkett, and C. Bertram, “Overview of Environmental Concerns for Siting of Coalbed Methane Facilities,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, (May 13-16).

Simpson, T.E., “Environmental Overview, Coalbed Methane Gas Development in Alabama, 1984-1989,” Dames & Moore, 1989.

1-17

2

Drilling and Casing the Wellbore

T

o successfully drill and case a coalbed methane well, you must consider several operational factors not usually encountered with conventional wells. For example, most coalbed wells in the Black Warrior Basin are drilled into relatively shallow (500-3500 feet), lowpressure coal formations. Because these formations produce very low rates of gas, project economics require an extremely efficient and costeffective drilling program. A significant part of this drilling program will be shaped by the stimulation treatment and completion methods you select for the wells. Similarly, the unique mechanical properties of coals require that you use procedures that avoid damaging the coal formation. This chapter explains these and other important considerations for drilling a coalbed methane well. This chapter will guide you through:

• Planning the Drilling Program • Drilling the Wellbore • Coring the Wellbore • Casing and Cementing the Wellbore

Chapter

2

Drilling and Casing the Wellbore

Planning the Drilling Program By carefully planning your coalbed drilling program, you can help ensure productive, economical coalbed methane wells. Figure 2-1 illustrates the steps of an effective planning process. Each of the steps is explained below.

Figure 2-1 The Planning Process for Drilling a Coalbed Methane Well

1. Collecting

2. Evaluating

Information

Formations

6. Selecting a

5. Selecting Casing

4. Selecting

Drilling Technique

Weight and Grade

Hole Size

7. Designing the Hydraulics of the Drillstring

8. Selecting the Drillbit and Drillstring

10. Selecting the Drilling Rig

9. Designing the

and Drilling Equipment

Cementing Program

11. Complying with Regulatory Permitting Requirements

2-2

3. Selecting Casing Setting Depth

Planning the Drilling Program

1.

Collecting Information Before you can make informed decisions about a drilling program, you must learn as much as possible about coalbed drilling and production operations in your area. Begin by collecting any well information available from offset coalbed methane operators. You may also find some of this information recorded as public information at your local and state oil and gas regulatory agencies. Specifically, you should try to obtain this well information: ❖

Formation depth, pressure, and production

❖

Type of coal and non-coal formations

❖

Well logs

❖

Rig type and drilling assembly

❖

Drilling fluid specifications

❖

Casing program

❖

Drilling problems encountered

❖

Stimulation and completion methods

In addition, you should talk with drilling contractors who have substantial experience in your area of interest. You should try to find out: ❖

Types of rigs, surface and downhole equipment commonly used

❖

Drilling problems typically encountered

❖

Drilling procedures for eliminating problems

❖

Equipment cost and availability

You should also become familiar with considerations for preparing the well site for drilling operations. For information on this topic, refer to

2-3

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Drilling and Casing the Wellbore

Chapter 1 of this guide. Finally, you should consult with your local and state oil and gas agencies and environmental agencies to learn what laws and regulations you must follow.

2.

Evaluating Formations After collecting offset well information, you should evaluate any available well logs and drilling records to determine approximate depths for prospective coal intervals. You should also attempt to identify any potential problem zones, such as: ❖

Depleted zones that may cause lost circulation

❖

Sloughing shales

❖

Overpressured zones or water disposal zones

❖

Fresh water aquifers

Accurately identifying prospective coal intervals and problem zones will help you to design an effective casing and cementing program.

3.

Selecting Casing Setting Depth To select the casing string and drilling equipment, you must first determine at which depths to set casing in the wellbore. The casing setting depths will depend primarily on these factors: ❖

Fracture gradients of coal seams and adjacent formations

❖

Regulatory requirements

❖

Drilling problems

❖

Isolation of coal seams

Before selecting the casing setting depth, you first must determine the fracture gradient, or pressure per foot of depth, required to fracture the coal seams and adjacent formations. In general, you should set casing through zones that have a fracture gradient that is

2-4

Planning the Drilling Program

significantly different than the fracture gradient of deeper zones. Figure 2-2 illustrates how an operator could prevent possible lost circulation problems by setting casing through a low-fracturegradient coal seam before drilling ahead through a coal seam having a significantly higher fracture gradient.

Figure 2-2 Setting Casing Through Zones with Lower Fracture Gradients

You can predict fracture gradients by using various published correlations or by using a fracture gradient formula, such as Eaton’s Equation, shown below: F =

(

S-P x v 1D v

)

+ P D

where: F = fracture gradient, psi/ft S = overburden stress, psi P = wellbore pressure, psi D = depth, ft v = Poisson’s ratio

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Drilling and Casing the Wellbore

Fracture gradients for coal seams in the Black Warrior Basin range from as low as 0.5 psi/ft to over 1.0 psi/ft. To determine proper casing setting depths, you must also consider the requirements of state and local regulatory agencies. For example, regulatory agencies governing the Black Warrior Basin require that you set a minimum of 300 feet of surface casing in wells up to 4000 feet deep. You should also consider potential drilling problems when determining casing setting depths. Set casing to isolate zones that may cause problems such as water influx, sloughing shales, or abnormal pressures. Finally, when selecting casing setting depths, you should isolate prospective coal seams to optimize well completions. For example, set surface casing deep enough to eliminate drilling problems, but try not to set surface or intermediate casing across coal intervals that you plan to complete. A well completed through two strings of casing (surface and production casing) will likely be much less productive than a well completed through only one string.

4.

Selecting Hole Size Before the rest of the drilling program can be designed, you must first determine the sizes of the hole to be drilled. You should base the hole sizes on the casing program rather than selecting casing based on a pre-selected hole size. By carefully planning the hole and casing sizes, you can avoid many operational problems later in the life of the well. This section will guide you through the steps for determining proper hole sizes. Figure 2-3 illustrates the steps in this process. Each of these steps is explained below.

2-6

Planning the Drilling Program

Figure 2-3 Selecting Hole Size

Production Considerations

Other Considerations

Production Rates

Performing Stimulation Treatments

Artificial Lift Method Removing Drilling Cuttings Tubing Size Performing Future Workovers and Recompletions

Completion Method

Select Optimum Production Casing Size

Select Production Hole Size

Select Optimum Surface Casing Size

Select Surface Hole Size

2-7

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Drilling and Casing the Wellbore

Production Considerations in Selecting Hole Size Production Rates

To select optimum hole size, you should begin by estimating the expected water and gas production rates for the well. You may be able to obtain these estimates from offset well data, as explained earlier in Collecting Information.

Artificial Lift Method

Next, you must decide what method of artificial lift you will use to remove water from the wellbore. Because coalbed methane reservoirs typically have very low pressures, you must select a lift system that will maintain a low wellbore water level to minimize bottomhole pressure and optimize gas production. For more information on selecting an artificial lift system, refer to Chapter 6. Tubing Size

When you design the artificial lift system, you will determine the optimum production tubing size to install in the well. This decision is based on the type and size of lift system you select as well as the estimated production rates. For more information on selecting tubing size, refer to Chapter 4.

❈ Important Selecting an insufficient tubing size may prevent you from effectively dewatering a coalbed reservoir, and thus severely limit ultimate gas production.

Completion Method

Next, you should consider how you will complete the well. Your choice of an open hole or cased hole completion will influence the amount and size of production casing you run. For example, you must select casing sizes that will accommodate the diameter of completion tools (e.g., perforation guns, slotting tools, underreamers) you will need to complete the well. For more information on designing the well completion, refer to Chapter 4. After determining the optimum casing string for your tubing and completion requirements, you should consider several other factors.

2-8

Planning the Drilling Program

Other Considerations In Selecting Hole Size Performing Stimulation Treatments

In addition to the production considerations above, you must also consider whether you will perform a fracture stimulation on the well. If you plan to fracture the well, determine whether the fracture will be pumped down the tubing string or down the casing string. If you plan to pump the treatment down the casing, size the casing large enough to accommodate the desired treatment rates. In addition, you must determine whether you will run isolation baffles for fracturing treatments. If you plan to use isolation baffles, you must install them when you run the casing string. For more information on fracturing considerations, refer to Chapter 5.

❈ Important Selecting an insufficient casing size can limit the injection rate or fluid type needed for an effective fracture treatment.

Removing Drilling Cuttings

You should also determine the hole size required to effectively remove cuttings from the hole. Because of the shallow, low-pressure coal formations in the Black Warrior Basin, most wells in this basin are drilled using compressed air or air mist instead of drilling mud. To effectively remove cuttings from an air-drilled hole, you must properly size the hole and the air compressors. The larger the hole size you select, the greater will be the volume of air required to remove cuttings. As you increase hole size, you also increase the horsepower required to lift cuttings. Therefore, when selecting the optimum hole size for removing cuttings, you must also consider the cost for the size of compressor you will use.

Performing Future Workovers and Recompletions

When selecting hole size, you should also consider the sizes of any downhole tools that you may need to run to workover or recomplete the well in the future. Make sure casing strings have sufficient clearance to accommodate these tools. For more information on the types of tools you may need to use, refer to Chapter 4.

2-9

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Drilling and Casing the Wellbore

Analyzing Production Considerations and Other Considerations Next, independently evaluate the hole size requirements of each production and other consideration explained above. Then select the optimum production casing size that best satisfies all these requirements. For additional guidance in evaluating hole sizes for particular applications, consult with drilling contractors, service company representatives, and well operators who are experienced in drilling, stimulating, completing, and producing coalbed methane wells. These people can explain the specifications and operation of their tools and discuss the requirements of your particular operation.

Selecting Optimum Production Casing Size

Select the production casing size that best satisfies all of the production and other considerations explained above. Many operators in the Black Warrior Basin run 4-1/2 inch or 5-1/2 inch production casing. Most of the wells at the Rock Creek Project were cased with 5-1/2 inch production casing.

Selecting Production Hole Size

The size of the production casing you select will help determine the size of the production hole required. The hole size you select should be large enough to prevent the casing from sticking while being run. In addition, the hole size should allow sufficient annular space to provide an effective cement job. Many operators in the Black Warrior Basin drill a 7-7/8 inch production hole to accommodate a 5-1/2 inch production casing string. For additional guidance in selecting a proper hole size, refer to Figure 2-4.

2-10

Planning the Drilling Program

Figure 2-4 Casing Selection Chart

You can use this chart to select the casing, hole, and bit sizes for many drilling programs. To use the chart, follow the steps below: 1.

Determine the size of the last casing to be run.

2.

Enter the chart at that casing size.

3.

Follow the arrows to select the hole size required to set that size pipe (e.g., 5 in. casing inside 6-1/8 in. or 6-1/2 in. hole). Solid lines indicate commonly used bits for that size pipe. This bit size will normally provide adequate clearance to run and cement the casing (e.g., 5-1/2 in. casing inside 7-7/8 in. hole). Dashed lines indicate less common hole sizes (e.g., 5 in. casing inside 6-1/8 in. hole). If you select a dashed path, you should carefully consider casing connections, mud weight, cementing, and doglegs. Large OD connections, thick mudcake buildup, problem cementing areas (high water loss, lost returns, etc.), and doglegs may aggravate attempts to run casing when clearance is low.

4.

Follow the arrows to select a casing large enough to allow passage of a bit to drill the hole selected in step 3. Solid lines indicate commonly required casing sizes, encompassing most weights (e.g., 6-1/2 in. bit inside 7-5/8 in. casing). Dashed lines indicate casing sizes for which you can use only the lighter weights (e.g., 6-1/8 in. bit inside 7 in. casing).

5.

Repeat steps 2-4 until you have selected all casing sizes for the well.

2-11

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Drilling and Casing the Wellbore

Selecting Optimum Surface Casing Size

The size of the production casing you select will determine the size of the surface casing string to run. You should select surface casing large enough to accommodate the bit needed to drill the hole for the production casing string. If you plan to run a cement collar on the production string, make sure the drift diameter of the surface casing is large enough to accommodate the bit required to provide the maximum hole size for the cementing collar, as specified by the cementing collar manufacturer. Many operators in the Black Warrior Basin run an 8-5/8 inch surface casing string. Most of the wells at the Rock Creek Project were also cased with 8-5/8 inch surface casing.

Selecting Surface Hole Size

The size of the surface casing you select will determine the size of the surface hole required. Many operators in the Black Warrior Basin drill a 12-1/4 inch surface hole to accommodate an 8-5/8 inch surface casing string. For additional guidance in selecting surface hole size, refer to Figure 2-4.

5.

Selecting Casing Weight and Grade Before beginning your casing and cementing program you should obtain a casing and cementing handbook from one of the major oilfield service companies. This handbook provides specifications and other useful information on casing and cementing equipment and materials. When you design a casing string, you must consider three principal forces:

• Burst Pressure • Collapse Pressure • Tensile Load

2-12

Planning the Drilling Program

Burst Pressure Burst pressure refers to a condition of unbalanced internal pressure. Burst pressure is probably the most important factor in designing the coalbed casing string because the pipe will likely experience the greatest pressures during fracturing stimulations, when treating pressures can exceed 5000 psi. You can estimate the treating pressures required by using the fracture gradients you predicted when determining casing setting depth (step 3 above). Once you have estimated fracture gradients for the coal seams of interest, you can select the proper casing weight and grade. For more information on casing specifications, refer to a service company casing handbook.

Collapse Pressure Collapse pressure is the unbalanced external pressure imposed on the pipe. The worst operational case is for the pipe to be empty with a normal hydrostatic pressure gradient exerted on it from the outside. The greatest differential pressure exerted on the casing is most likely to occur during flowback of a fracture treatment or during the later stage of production when pressure inside the wellbore decreases significantly. You should design the casing string for this worst case scenario. Typically, water levels in coalbed wells are pumped down to minimize hydrostatic pressure and optimize gas production. The collapse pressure becomes a more significant factor in deeper coalbed wells. Because of the relatively shallow wells (500-3500 feet) in the Black Warrior Basin, casing collapse has posed few problems in this area. However, the collapse strength of the casing may be reduced by mechanical operations such as slotting or high density perforating.

Tensile Load Tensile load is the force exerted on a joint by the weight of the joints below it. Because each joint supports all the weight below it, the greatest tension occurs at the top of the string. Most coalbed wells in the Black Warrior Basin are shallow; therefore, tensile load is not a primary consideration for this area. Production casing is usually available in sizes ranging from 4.5 inches to 7.0 inches and in a variety of weights and grades. Casing is also

2-13

Chapter

2

Drilling and Casing the Wellbore

classified as API (American Petroleum Institute) standard casing or limited service casing. API standard meets all specifications for wall thickness, outside diameter, inside diameter, drift, collapse, internal yield, and joint yield strength ratings for its respective grade. Limited service casing is also called “mill reject” because one or more specifications does not meet API standards. However, limited service casing may also be tested to 80 percent of the minimum yield as set forth by API specifications. Therefore, to reduce cost you may choose to use limited service casing for some applications. Typical casing grades are F-25, H-40, J-55, K-55, C-75, N-80, C-95, and P-110. These grades represent the strength of the casing. A variety of casing weights and wall thicknesses is also available for use according to well conditions. Select the size, weight, and grade of production casing based on the individual well design and completion technique. For more information on completing coalbed methane wells, refer to Chapter 4.

❈ Important Before ordering casing, find out the limitations of casing weight and length for the rig you will use to run the tubulars. By ordering Range Two casing and tubing, which have lengths of 28-32 feet, you may be able to use a smaller, less costly rig.

Casing Used in the Black Warrior Basin Most Black Warrior Basin operators complete coalbed methane wells simply using a production string set through a shallow surface casing. They generally run 5-1/2 inch casing in a 7-7/8 inch hole. The surface casing usually consists of 300 feet of 8-5/8 inch casing set in a 12-1/4 inch hole.

▲ Caution Using casing smaller than 4-1/2 inch (O.D) limits the size of production tubing you can run inside it. If the casing/tubing annulus is too small, the flow path for gas will be restricted and the annulus can easily plug.

2-14

Planning the Drilling Program

6.

Selecting A Drilling Technique To select the most effective drilling technique for your area of interest, you must consider the geologic and reservoir conditions of the coal basin. Generally, wells drilled in the eastern United States target shallow coal beds (less than 4000 feet) in geologically older (Pennsylvanian) and more competent formations. Operators in this area usually employ relatively simple drilling techniques. In contrast, complex drilling techniques are used to drill wells in the western United States, which usually target younger (Cretaceous) formations that are deeper, over-pressured, and less competent. Operators in the Black Warrior Basin frequently drill coalbed wells using the rotary-percussion technique, with air or air-foam mist as the circulating fluid. Figure 2-5 shows a comparison of the conventional rotary and the rotary-percussion drilling techniques. Rotary-percussion drilling has become a standard technique in the Black Warrior Basin because it typically yields higher penetration rates and lower drilling costs than conventional rotary drilling. In addition, the rotary-percussion technique minimizes formation damage because it uses no drilling mud. In the northern end of the Black Warrior Basin, where the surface formations are hard, coalbed wells are often drilled from surface to total depth using the rotary-percussion technique. In this area, drilling with a tri-cone rotary bit yields lower penetration rates because at shallow depths it is not possible to apply sufficient weight on the bit. In the southern end of the Black Warrior Basin, however, where the softer Cretaceous formations are encountered from surface to as deep as 500 feet, the surface hole must be drilled using a tri-cone rotary bit with drilling fluid (usually water) to prevent hole collapse. After drilling through the Cretaceous formations and setting surface casing, drillers usually switch to rotary-percussion drilling to achieve greater penetration rates in the harder formations. Most of the coalbeds in the Black Warrior Basin are water saturated, low pressure, low permeability formations. In some parts of the basin, little formation water flows into the wellbore during drilling, and air circulation can easily remove not only cuttings, but any produced water as well. When the wells at the Rock Creek site

2-15

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Drilling and Casing the Wellbore

were drilled, a mixture of water and liquid soap was added to the compressed air to enhance lifting of cuttings and cleaning of the hole. For more information on removing drilling cuttings, refer to step 7, Designing the Hydraulics of the Drillstring.

Figure 2-5 Conventional Rotary and Rotary-Percussion Drilling Techniques

2-16

Planning the Drilling Program

In most cases, you can achieve the greatest penetration rate in hard formations by using a percussion bit with an air hammer. However, if you encounter a particularly hard formation when drilling with a tri-cone roller bit, you may switch from air to water to better cool the bit. All of the wells at the Rock Creek site were drilled using only air or air mist as the circulating fluid. The main benefits and limitations of drilling with air circulation are: Benefits ❖

Eliminates possible filtration damage to coal

❖

Reduces loss-of-circulation problems

❖

Provides straighter holes because of less weight-on-bit

❖

Lower cost because no mud is used

❖

Faster drilling rate

Limitations ❖

Unable to effectively lift large volumes of water

❖

Bit gauge can degrade appreciably during drilling

❖

Drillpipe can wear excessively from sandblasting effect

❖

Air compressor packages may not be available in some areas

When drilling in some parts of the Black Warrior Basin, you may encounter permeable faults and fracture systems that produce large volumes of water. Because state and federal environmental regulations prohibit overflow of drilling pits, you must stop air drilling if a well produces water faster than it can be hauled away. This problem can severely jeopardize projects with economics based on the lower cost of air drilling. Water producing zones can also cause loss of circulation problems with wellbores that are rotary drilled with fluid. Using conventional lost circulation materials to control fluid loss has sometimes proven ineffective and expensive. In addition, lost circulation materials may greatly reduce the effective permeability and the gas producing potential of coal formations. Similarly, squeeze cementing to control water influx and loss of returns can be prohibitively expensive.

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Drilling and Casing the Wellbore

Alternating Drilling with Air Mist and Water To solve these water problems, a drilling contractor in the Black Warrior Basin has successfully used a system of alternately drilling with air mist and water. The contractor has successfully demonstrated that if the wellbore is generally competent, you can drill with air mist until all surface recovery tanks are full of produced formation water. You can then continue drilling by switching to water circulation until the surface storage tanks are pumped dry. By continuing this process of alternating air mist and water drilling, you can drill to the total depth of the well. This technique of alternating drilling fluids can minimize excess water production and allow you to reach target depths without pumping potentially damaging lost circulation materials or expensive squeeze cement treatments. For more information on this technique, refer to Additional References at the end of this chapter. To optimize the alternating fluid technique, you should strive to circulate a mixture of air and water that will balance the pressure in the hole. That is, the mixture should neither permit a large influx of water into the wellbore nor a large loss of fluid to formations. This balance requires carefully monitoring the drilling pits and adjusting the water/air mixture. When you achieve the proper mixture, the pits will neither lose nor gain large amounts of water. If you use the alternating fluid technique, you should use bits that do not contain jets. (Air bits usually do not have jets installed.) If you must use jets, they should be large enough to keep standpipe pressure below maximum compressor pressure. (For more information on drillbits, refer to step 8, Selecting the Drillbit and Drillstring). ▲ Caution

2-18

When drilling with a rotary-percussion assembly, you cannot use the technique of alternating air mist and water. Percussion hammers operate pneumatically and will not tolerate large amounts of water.

Planning the Drilling Program

7.

Designing the Hydraulics of the Drillstring Designing a hydraulics program for the drillstring involves selecting the proper combination of drilling fluids and drillbits. An optimum drilling hydraulics program can accelerate drilling rate and lower rig cost. A poorly designed program can slow penetration, increase cost, and possibly damage the formation. The design of the hydraulics program for deep coalbed methane wells can be complex. If you plan to drill in an area where drilling fluids are needed to control formation pressure and maintain wellbore integrity, you should consult with experienced drilling engineers. They can use hydraulics software to determine the optimum design for your application. Service companies can also assist you in designing an effective hydraulics program. Fortunately, most coalbed methane wells in the Black Warrior Basin can be drilled with air and thus require a relatively simple hydraulics program. The three main considerations in designing the hydraulics program are:

• Minimizing Damage to Coal Formations • Effectively Cleaning the Hole • Cooling and Lubricating the Bit

Minimizing Damage to Coal Formations By minimizing damage caused by invasion of drilling fluids into prospective coal intervals, you can help ensure optimum gas production rates. You should drill holes using air, air mist, or water instead of drilling muds, when possible, to minimize formation damage. Air circulation exposes the coal to less solids and chemical additives, and it exerts minimal hydrostatic pressure on the coal.

❈ Important

If you need to use a drilling fluid to control formation pressures, you should carefully select the type of fluid and additives. If formation pressures permit, the safest and most economical fluid to use is fresh water with a small amount of bentonite to add viscosity. Using heavy muds could plug or even fracture the coal. You should use them only as a last resort. You should also avoid chemicals that could damage the coals.

2-19

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Drilling and Casing the Wellbore

Effectively Cleaning the Hole Effectively removing drilling cuttings from the hole increases the penetration rate and thus reduces rig time. Keeping the hole clean can also increase the life of the drillbit. Air drilling removes cuttings from the hole effectively if the air is circulated at an adequate rate. Determining the Air Rate Needed to Lift Cuttings

The optimum air circulation rate is a function of drilling depth, the annular area between drillpipe and hole, and the rate of penetration. In 1957, R. R. Angel published a set of charts that show the minimum air circulation rate at various depths for given drillpipe diameters and hole sizes. These charts are based on the minimum annular velocity of 3000 ft/min, which is necessary to lift cuttings from the hole. Angel converted this velocity to volumetric flow rates based on depth, the annular areas for various pipe and hole sizes, and the effects of bottomhole pressures and air compressibility on the downhole volumes. Recent research has shown the actual volumetric rate of flow necessary to efficiently lift cuttings is slightly higher than the volumes in the Angel curves. Some drilling contractors in the Black Warrior Basin recommend using an air volume at least 25% greater than the values in the Angel curves. Determining the Air Pressure Needed for Air Drilling

To effectively clean the hole, you must also inject air at sufficient pressure to keep cuttings from falling back. Determining the required surface, or injection, pressure in advance of drilling will help you to properly size the air compressor for the job. You can estimate the required surface air pressure using the equation below: Psurf = Pf + Pah + Pcsg

where: Psurf = the compressor discharge pressure at the surface Pf = the friction pressure of air in the drillpipe and the friction pressure of air, water, and cuttings in the annulus

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Planning the Drilling Program

Pah = the total hydrostatic head in the annulus minus the hydrostatic head in the drillpipe. Pcsg = the backpressure on the discharge line to the drilling pit. (This pressure should be zero under normal drilling conditions.)

The most difficult variable to estimate is Pah. For example, if you are drilling with air and there is no influx of formation water into the annulus, there would be air in the drillpipe and air plus cuttings in the annulus. Thus, Pah could be near zero, depending on the amount of cuttings in the annulus. However, if water flows into the annulus, Pah would be essentially equal to the hydrostatic pressure created by that water influx. Because it is difficult to predict the amount of water influx, it is likewise difficult to accurately estimate the surface air pressure required. In the Black Warrior Basin, drilling contractors have found they can drill a 7-7/8 inch hole with an air compressor capable of an air injection rate of 2000 cfm. Most compressors used for air drilling have a maximum allowable discharge pressure of 350 psi. If you need greater pressure, you can route the primary compressor through a booster compressor. If you are drilling with an air percussion hammer, you should consult the hammer manufacturer’s air pressure charts for the surface pressure required to operate the hammer.

Using Air Mist to Remove Cuttings

To enhance removal of cuttings, you can use a mixture of air, water, and chemicals to create an air mist drilling fluid. Common chemical additives for air mist systems are detergents for foaming, lubricants for reducing friction, corrosion inhibitors, and viscosifiers. Because air mist fluids have a higher viscosity than air fluids, they can effectively lift cuttings at a much lower flow velocity than air. For example, air circulation usually requires a flow velocity of 3000 ft/minute to effectively clean the hole, whereas a stable foam fluid may require a velocity of only 200-300 ft/minute. The high flow velocity needed for air drilling can erode and enlarge the hole, greatly reducing the ability to remove cuttings.

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To effectively remove cuttings from an air or air mist hole, you must properly size the hole and the air compressors. The larger the hole size you select, the greater will be the volume of air required to remove cuttings. Therefore, as you increase hole size, you also increase the horsepower required to lift cuttings. When selecting the optimum hole size for removing cuttings, you must also consider the cost for the size of compressor you will use.

Cooling and Lubricating the Bit In wells drilled with drilling mud, the mud helps reduce the large amount of heat that is generated as the bit cuts through rock. Muds also help to reduce the torque and drag on the drillstring by lubricating the wellbore. When drilling with air or air mist, you do not have the advantage of drilling fluid in the wellbore to cool the bit. However, specially designed tri-cone rotary bits are available for air drilling. These bits contain ports that allow air to circulate around the bearings in the bit to dissipate heat and extend bit life. When using a common rotary bit with air mist drilling, the water in the mist helps to cool the bit. If you encounter a particularly hard formation when drilling with a tri-cone roller bit, you may switch from air to water to better cool the bit. You will find more information on drillbits for air drilling in the next section.

8.

Selecting the Drillbit and Drillstring The drillstring includes the drillbit, drill collars, and drillpipe. In some areas, you may also use stabilizers to control hole deviation.

DRILLBITS When determining the bit program for a coalbed well, you should consider these factors:

2-22

❖

Bit cost

❖

Formation types

❖

Drilling techniques

❖

Hydraulics

❖

Rig cost

Planning the Drilling Program

Before selecting the bits for your drilling program, the data that you gathered as discussed in Section 1 should provide information about formation types, drilling techniques, and commonly used hydraulics. The bit records of offset wells should be included in that data. If not, this type of information can often be obtained from bit suppliers. A review of the offset bit records will help to estimate the number and types of bits to use. You will determine the size of the drillbits based on the sizes of the holes for the surface casing and production casing, which you selected in step 4, Selecting Hole Size, earlier in this chapter. The bits most commonly used in drilling coalbed methane wells are tricone rotary bits and percussion bits. Tri-Cone Rotary Bits

The sealed bearing,tri-cone rotary bit is the most common and the most versatile bit used in the oil and gas industry. These bits are available for drilling a variety of different formations. A specially designed tri-cone rotary bit is available for air drilling. This bit contains ports which allow air to flow through the bearing assembly for cooling. Most tri-cone air bits are open port bits and are thus more susceptible to corrosion than sealed bearing tri-cone rotary bits. If you drill with air only, a tri-cone air bit may provide the longest bit life. However, if you plan to alternate drilling air mist and water, a sealed bearing bit will likely last longer. You should consider using sealed bearing bits to provide the flexibility of drilling with either airmist or water. Percussion bits

Percussion bits are used in combination with air hammers. This type of bit is used exclusively for drilling hard formations with air or air-foam mist. As discussed earlier in step 6, Selecting a Drilling Technique, percussion drilling is necessary when drilling hard formations at very shallow depths. Percussion bits with air hammers cannot be used in soft or sloughing formations. A typical percussion bit and air hammer is shown in Figure 2-5. If you encounter a soft formation, such as the Cretaceous in the Southwestern part of the Black Warrior Basin, you should use tri-cone rotary bits with fluid.

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At the Rock Creek project, the surface holes were drilled with rotary bits because the first several feet of the hole are in a soft formation. Because the State Oil and Gas Board of Alabama required less surface casing then than it does now, drilling was continued with the rotary bit down to the setting depth for the surface casing. After setting surface casing, the production holes at Rock Creek were drilled with percussion bits and air hammers.

Drill Collars To select the number of drill collars for the drillstring, you must consider the weight-on-bit that the operator or drilling contractor has determined necessary to drill the hole. You can determine the optimum weight-on-bit by conducting drilloff tests or by estimating it from offset bit records. For more information on determining weighton-bit, you may consult with drilling contractors in your areas of interest as well as drillbit suppliers. When air drilling, the drillstring and bottomhole assembly (BHA) are subjected to high vibration loads. This vibration is often extreme on the bottomhole assembly and the connection between the BHA and the drillpipe, especially when drilling hard formations. To protect the drillstring and the drillstring/BHA connection, you should design the drillstring so that the neutral point between axial, tensile, and compressive stresses during normal drilling is located in the drill collars. You can calculate the length of drill collars needed to achieve this condition by using this equation:

Length of drill collars =

BW ,ft (BF) (CW)

where: BW = Desired bit weight, lb BF = Buoyancy factor, dimensionless (The BF for air is 1.0 because the collar weights are measured in air.) CW = Collar Weight (in-air), lb/ft

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Planning the Drilling Program

Industry experts recommend adding ten percent to this calculation to account for unforeseen forces such as bounce, hole friction, hole deviation, etc. Operators in the Black Warrior Basin typically run enough 6-inch collars to provide a weight-on-bit of approximately 5000 pounds/inch for tri-cone bits and 500 pounds/inch for air-hammer bits.

Drillpipe When selecting drillpipe, you should base your selection on the worst case drilling scenario. If you are drilling wells in a developed area, consult with drilling contractors in the area. They likely have gained enough experience to recommend drillpipe designs that work effectively in that area. In the Black Warrior Basin, most drilling contractors use 4-1/2 inch drillpipe. For more information on designing drillstrings, refer to Additional Resources at the end of this chapter.

Stabilizers Stabilizers are sometimes run in the drillstring to control hole deviation. The operator must usually decide what arrangement of stabilizers, if any, to run. When determining the type and number of stabilizers to run, you should consider the desired weight-on-bit, penetration rate, and type of formations to be drilled. To learn what arrangements of stabilizers work best in your area of interest, you should consult with drilling contractors in the area. In most parts of the the Black Warrior Basin, drilling contractors do not use stabilizers because controlling hole deviation is not a problem. Most of the wells in the basin are drilled with air or air mist. Because air drilling requires less weight-on-bit than fluid drilling, there is less tendency for the bit to “walk,” or deviate. However, in a few parts of the Black Warrior Basin stabilizers are needed to prevent deviation. These are areas where the formations are stressed by extensive faulting and folding. When stabilizers are used, the typical bottomhole assembly includes: ❖

Drillbit

❖

Percussion hammer

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❖

Short drill collar

❖

First stabilizer

❖

Full drill collar

❖

Second stabilizer

Check Valves You should install check valves at specific intervals in the drillstring to: ❖

Prevent backflow of cuttings into the drillstring during connections or other shut-downs that would otherwise plug the bit.

❖

Reduce the volume of air that must be bled off when making a connection.

To learn what combination of check valves works best in your area of interest, consult with drilling contractors experienced in the area. For the Rock Creek Project, check valves were usually placed at intervals of 400 feet in the drillstring.

9.

Designing the Cementing Program Because coals have a low mechanical strength, you must design the cementing program to prevent the weight of the cement from fracturing the coal formations. You can avoid fracturing coal formations during cementing by selecting proper cement and additives and proper cementing techniques.

Selecting Cement and Additives To select a cement that is strong enough to provide a sufficient bond, but that will not fracture the coal because of its weight, follow these procedures:

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Planning the Drilling Program

1.

Determine the fracture gradient of the coal formation(s) you plan to cement. For more information on fracture gradients, see step 3, Selecting Casing Setting Depth, earlier in this chapter.

2.

Determine the depth for the top-of-cement based on regulations of the oil and gas regulatory agencies.

3.

Using the equation below, calculate the maximum cement density that the coal can support. Maximum height of cement = FG-(0.052 ρm Td) , ft 0.052(ρc - ρm)

where: FG = fracture gradient of the coal, psi/ft ρm = density of drilling mud in the hole, lbs/gal ρc = density of the cement, lbs/gal Td = depth to the coal seam, ft

4.

If the coal formation(s) cannot support a cement column to the required top-of-cement depth (using a cement with the lightest acceptable density), calculate the maximum height of cement the coal can support.

5.

Design a two-stage cement job based on the height of cement calculated in step 4.

For more information on specific types of cement and additives, refer to Selecting Cement and Additives, later in this chapter.

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Selecting Cementing Techniques Use cement placement techniques that will minimize stress on the coal formations. For information on these techniques, refer to Casing and Cementing the Wellbore, later in this chapter.

10.

Selecting the Drilling Rig and Drilling Equipment After you have designed the casing, drillstring, and hydraulics programs, you can select a drilling rig. If the availability of drilling rigs is limited in your area, you may have to modify the casing, drillstring, and hydraulics programs to meet the rig’s capabilities. When selecting a rig for your drilling program, consider each of these factors explained below:

• Type of Drilling Rig • Air Compressors • Derrick • Drive System • Blowout Preventers or Diverter System • Other Rig Equipment

Type of Drilling Rig You can normally use a portable (truck-mounted) rig to drill shallow coalbed methane wells. Portable rigs are normally more economical than conventional rigs because they require less rig-up and rig-down time. Most wells drilled in the Black Warrior Basin are drilled with portable rigs.

Air Compressors In the Black Warrior Basin, most wells are drilled with compressed air. To determine the number and size of air compressors needed to drill a particular well, you must first estimate an air circulation rate and maximum injection pressure. For information on estimating air circulation rate and injection pressure, refer to step 7, Designing the Hydraulics of the Drillstring, earlier in this chapter.

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Planning the Drilling Program

At the Rock Creek site, an auxiliary compressor was used to provide the additional volumes of air at higher pressures needed to drill deeper formations and formations that produced large volumes of water. The auxiliary compressor ensured sufficient air velocity to carry cuttings to the surface. It also helped prevent flooding the downhole air percussion hammer with excessive water.

Derrick You should select a rig with a derrick weight capacity that will enable the operator to use the designed drillstring and to run the desired casing string. The maximum loading on the rig usually occurs when running casing. You should also select a derrick height (single or double stand) that fits your well location size and is compatible with the depth of your well. The increased cost for a rig that can run doubles (two joints of pipe connected), may be justified in deeper wells because it could significantly reduce trip time. However, a rig with a single-stand derrick is usually sufficient for most coalbed wells. In the Black Warrior Basin, drilling contractors generally use single and double rigs. Some portable rigs have a derrick capacity up to 350,000 pounds, which is more than adequate for drilling in the Black Warrior Basin.

Drive System In general, you can choose from two types of drive systems. The most common system is the conventional rotary table and kelly used in most oil and gas fields. The other is a top-drive system. The top-drive system uses a power swivel on top of the drillstring to rotate the string. The power swivel eliminates the rotary table and kelly. Because the top-drive system requires fewer drillpipe connections, it can reduce drilling time as well as provide greater safety. In the Black Warrior Basin, drilling companies use both conventional drives and top drives. The selection of a drive system is mostly a matter of personal preference and rig availability.

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Blowout Preventers or Diverter System The blowout preventer (BOP) stack used to drill most conventional wells includes a set of pipe rams, blind rams, and an annular preventer. However, drilling contractors in the Black Warrior Basin do not use a conventional BOP stack. Instead, they use a diverter system. The diverter system consists of an annular preventer called a rotating head and two remotely-controlled valves which open to separate flowlines that vent to the reserve pit.

Other Rig Equipment Though the equipment listed below is usually supplied by the drilling contractor, you should verify that the equipment has the proper capacity and other specifications to meet the requirements of the job. Blooey Line

The return line, or blooey line, carries the exhaust air and cuttings from the annulus to the flare pit. The blooey line should be long enough to keep dust from interfering with rig operations. In most cases, the line should be 100-300 feet long. You should size the blooey line so that the internal cross-sectional area is about 10% greater than the annular area of the near-surface borehole. This slightly larger area is needed to compensate for the fluid energy loss that occurs as the air and cuttings make a 90-degree turn from vertical flow to horizontal flow under the rig floor. The end of the line should terminate downwind from the prevailing wind direction. You should also make sure the end of the blooey line is tied down securely.

Chemical Pumps

Chemical pumps are used to inject water or chemical foamers into the wellbore during drilling.

Orifice Plate Meter

A standard orifice plate meter is normally used to measure the rate of air circulation. The size of the orifice plate selected will depend on the circulation rate needed to effectively clean the hole. To ensure accurate readings, make sure the meter has been calibrated recently. An alternative to the orifice plate meter is the turbine meter. If no

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Planning the Drilling Program

meter is available, you can estimate the air rate based on the size of the compressor and the suction and discharge pressures.

Pump Gauges

Accurate pressure gauges should be installed on the standpipe and at the compressor discharge. These gauges can be used to monitor wellbore conditions and predict potential downhole problems.

Bleed-Off Line

A bleed-off line should be installed to bleed pressure off the standpipe and the drillpipe down to the top check valve. This pressure is bled through the blooey line.

Burn Pit

A burn pit at the end of the blooey line can be used to catch any wellbore effluent (such as chemicals or hydrocarbons) that would otherwise contaminate the reserve pit. Because few chemicals are used to drill coalbed methane wells in the Black Warrior Basin, contamination of the reserve pit is usually not a problem. Thus most drilling contractors vent the blooey line directly to the reserve pit.

11.

Complying With Regulatory Permitting Requirements Before spudding a well, you must satisfy all state and federal regulatory requirements. In some states, two or more regulatory agencies are involved in permitting wells. Typically, one agency regulates actual well activities (drilling permits, well completion permits, pit preparation, production allowables, etc.). However, several other agencies may regulate the environmental aspects of site selection, site preparation, spill prevention, spill clean-up, and disposal of produced water. For information on selecting and preparing a field site, refer to Chapter 1. For information on treating and disposing produced water, refer to Chapter 8. In some states, obtaining necessary permits requires approval from several different agencies which work interdependently. Therefore, in many cases you may have to obtain all required environmental audits and/or permits before the oil and gas regulatory agency will grant approval to spud a well. Consequently, permitting can be a lengthy

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process, depending on the number of agencies involved and their relationships with each other. In some states, the process to permit a well could take as long as six months to a year. When planning a coalbed project, you should read and understand the state and local regulations that may affect your operation. In most states, the initial application for a permit to drill a well must include a certified survey showing the exact well location. Some field procedures, such as cementing and testing casing, may require that you notify the proper agency and obtain approval before proceeding on to the next step in the operation. Though permitting requirements vary from state to state, many requirements are similar. To get some sense of typical regulations for coalbed methane operations, refer to the summary of Alabama’s well permitting procedures, shown in Appendix A.

Drilling the Wellbore Drilling practices for coalbed methane wells can vary significantly from one coal basin to another. The depth and geology of the coal seams generally determine the drilling techniques and equipment that work best. When you are new to an area, you often can avoid many drilling problems and save considerable money by applying the experience gained by other operators in that area. Try to keep an open mind about unfamiliar practices that at first seem inappropriate. They may turn out to be the most successful and costeffective methods. During the past 10 years, operators and drilling contractors in the Black Warrior Basin have learned much about drilling coalbed methane wells through trial and error. They have found the general procedures below particularly effective for drilling coalbed methane wells in the Black Warrior Basin:

▲ Caution

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1.

Before beginning drilling, stake down the return (Blooey) line and chain down all compressed air lines. An air line that blows out can seriously harm workers if it is not properly secured.

Drilling the Wellbore

2.

If there is any loosely compacted fill dirt at the surface, install conductor casing through it. Drill a 16-inch surface hole and install 14-inch conductor pipe down to solid earth. Backfill and compact dirt around the outside of the conductor pipe. The conductor casing provides for return of drilling water while drilling the surface hole and for cement slurry while cementing surface casing.

3.

Drill the initial part of the surface hole (20-30 feet) using a tricone roller bit with compressed air. ◆

4.

❈ Important

5.

If the surface formations are unconsolidated (such as the Cretaceous section in the Black Warrior Basin), drill these formations using tri-cone rotary bit with drilling fluid.

After drilling initial surface hole or after reaching competent formations, switch from the tri-cone bit to an air-hammer and hammer-bit assembly to drill the remainder of the hole. ◆

If you encounter a hard formation at a shallow depth, you may use a percussion bit with an air hammer. Conventional bits may yield low penetration rates at shallow depths because of the inability to apply sufficient weight on the bit while drilling.

◆

When drilling 7-7/8 inch hole, the optimum rate of rotation for a percussion bit and air hammer is 10-30 RPM, and the optimum rate of rotation for a tri-cone rotary bit is 50-60 RPM.

◆

Drill with air, whenever practical, to achieve the best penetration rate and to minimize damaging the coal formation with liquid drilling fluid invasion.

◆

Do not use an aerated drilling fluid (air and water mixed) when using an air-hammer assembly. Water can flood an air hammer.

Circulate compressed air at a rate that lifts cuttings and water to the surface.

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◆

If you use the “Angel” curves or charts from a drillbit company to determine the air circulation rate needed to effectively lift cuttings, add at least 25% to these values. The Angel curves show circulation rates required for air drilling. These curves are presented in Volume Requirements for Air and Gas Drilling, R.R. Angel, Gulf Publishing Company, Fourth Printing 1985.

◆

If the drilling cuttings are fine dust instead of large angular pieces, you should increase the air circulation rate. Fine dust is created when cuttings are pulverized by the bit instead of being removed from the hole. This action reduces the penetration rate and the bit life. For more information on keeping the hole clean, see Designing the Hydraulics of the Drillstring, earlier in this chapter.

◆

6.

▲ Caution

7.

2-34

If you encounter a hard formation that causes a large decrease in penetration rate, switch from air to an air mist drilling fluid to help cool the bit.

If you encounter a formation that produces significant water when drilling with a tri-cone rotary bit, you may have to switch from air to water circulation to effectively lift cuttings to the surface. If you are drilling with a percussion bit and air hammer, you may have to switch to a tri-cone rotary bit with water circulation. ◆

Once you begin circulating water, you must continue using some water to drill the rest of the hole. If you switch back to just air after using water, you risk mixing dry and wet cuttings and causing severe plugging in the drillpipe-casing annulus.

◆

If you are drilling with water, add ordinary laundry detergent to the water to create a foam that will help clean up the hole.

If the well begins to flow while drilling, switch to a heavyweight clear water or mud drilling fluid to control formation pressure.

Drilling the Wellbore

▲ Caution

Use drilling mud and other additives only if clear heavyweight fluids are not available or are not sufficient to control formation pressure. Drilling mud invasion into the coal may cause formation damage and may permanently destroy the productivity of the well.

8.

Monitor and control weight on bit to optimize penetration rate and drilling hydraulics. ◆

In the Black Warrior Basin, the optimum weight-on-bit for a tri-cone bit is approximately 5000 lb/inch and 500 lb/inch for a percussion bit.

❈ Important 9. Drill at least 250 to 300 feet below the deepest target coal seam to provide adequate sump for logging, fracturing, and production operations.

10. After drilling to the total depth of the well, circulate a mixture of air, water and soap, until returns are free of cuttings and the water is clean. You may also circulate water with a viscous pill to clean up the hole. This practice will eliminate excessive fill in the hole and make casing installation easier.

11. After the drillbit is removed from the hole, measure the diameter of the bit to make sure the diameter of the hole will provide the required clearance for the casing and casing hardware. ◆

If the bit has been worn below the minimum diameter required, you will have to ream the hole to the appropriate size with a bit or hole opener.

For more information on drilling the wellbore, refer to the Additional Resources at the end of this chapter.

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Coring the Wellbore Analyzing core samples obtained from wells is one of the earliest methods of formation evaluation, and it continues to be the most reliable method of obtaining detailed formation descriptions and specific rock properties. Some of the most important coalbed reservoir data are obtained from cores. These data include gas content, desorption rate, adsorption isotherms, cleat and fracture data, coal rank, gas quality, and porosity. This section explains the equipment used for three different coring methods as well as important considerations and guidelines for coring operations: •

Coring with a Drilling Rig

•

Coring with a Coring Rig

•

Coring with Sidewall Tools

•

Special Considerations for Coring

•

Guidelines for Coring with a Rig

Coring with a Drilling Rig In conventional oil and gas fields, cores are usually obtained with a drilling rig during drilling operations. However, this method is not often used to core coalbed methane wells because it requires pulling the drillstring to retrieve the core. The trip time can allow significant gas to escape from the core sample. In addition, coring with a drilling rig is usually more expensive than the other coring methods. The conventional coring barrel assembly consists of a coring bit, a finger type “catcher,” an outer barrel, and a floating inner barrel. Coring bits may be drag bits, rolling cutter bits, or diamond coring bits. The inner barrel contains a check valve (or a dropped ball sealed on a seat) at the top, which allows flow upward out of the barrel, but not downward into the barrel. This check valve diverts the drilling fluid (usually water) from the drillpipe to the bit via the annulus between the outer barrel and the inner barrel. This designprevents the drilling fluid from eroding the core.

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Coring the Wellbore

The primary advantages of coring with a drilling rig are: ❖

Can obtain a large-diameter core. Larger cores provide a more representative sample of the coal seam

❖

Can recover a high percentage of the formation cored

❖

Requires no additional surface equipment

❖

Provides a larger wellbore, which allows using standard oilfield equipment for completion, production, and workover operations

The primary disadvantages of coring with a drilling rig are: ❖

Must pull drillstring to recover the core

❖

May lose an excessive amount of gas from the core, which adversely affects estimates of gas content

❖

Requires good stratigraphic control to accurately select the coring point

Coring with a Coring Rig When coring with a dedicated coring rig, you can retrieve the core by pulling the drillstring (as in conventional coring) or by wireline. Operators in the Black Warrior Basin usually core coalbed methane wells with a coring rig and then retrieve the core with wireline to minimize the amount of gas lost. They generally use a coring rig to obtain at least one core for each of their fields. The cores are used to determine the reservoir and mechanical properties mentioned at the beginning of this section. This coring method is a reliable and relatively inexpensive way to gather this critical data. To retrieve cores by wireline, you will need a hoisting assembly, including a wireline reel, sheave, and wireline lubricator, along with the normal surface drilling equipment. Additional subsurface equipment includes a special coring drill collar and bit; a coring barrel, bit, and bit plug; and a wireline guide and overshot. The special drill collar and bit are part of the drillstring. The coring barrel and bit plug are run inside the drillstring. During normal drilling, the bit plug is installed inside the special drill collar. The bit plug drills the inside area that the core bit does not drill. Prior to coring, the bit plug is

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pulled with the wireline overshot, and it is replaced with the coring barrel. The coring barrel (and core catcher) is dropped inside the drillpipe and it automatically latches into the drill collar. After the core has been cut, the barrel (with the core inside) is pulled with the wireline overshot. The primary advantages of retrieving cores by wireline are: ❖

Can cut and recover consecutive cores without pulling the drillstring

❖

Does not require continuous coring. Can alternate coring and drilling without pulling the drillstring

❖

Allows quicker retrieval of the core, which reduces the amount of gas lost before the core is tested

❖

Usually lower cost

The primary disadvantages of wireline coring are: ❖

Requires considerably more surface equipment

❖

The diameter of the core is limited. The diameters for wireline retrievable cores range from 1-1/64" to 2-13/32".

Coring With Sidewall Tools Sidewall cores are usually taken from the side of the borehole using a wireline tool that is equipped with hollow bullets that are fired into the formation. These bullets are attached to the gun body by short cable wires. To use the sidewall coring tool, the gun is positioned at the selected depth and then each of the bullets are individually fired electronically from the surface. The bullets are then withdrawn by the cable wires. Sidewall coring is performed during open hole logging operations after the hole is drilled. The primary advantage of wireline sidewall coring is: ❖

Can take cores from any depth after the hole is drilled

The primary disadvantages of wireline sidewall coring are: ❖

2-38

Samples may be too small for complete and accurate analysis

Coring the Wellbore

❖

Samples may be partly crushed or at least severely altered

To reduce the possibility of crushing the core inherent in wireline sidewall coring, a newer sidewall coring tool was developed. This tool uses a rotary sidewall drill rather than a bullet gun. The wirelineconveyed rotary tool has a diamond bit that drills the core horizontally from the side of the wellbore. Rotary sidewall coring may provide cores that are less disturbed than those obtained with wireline sidewall coring. However, this method is usually more expensive than wireline sidewall coring. The rotary sidewall coring tool is offered by Halliburton Logging Services.

Special Considerations for Coring In many respects, coring coalbed methane wells is similar to coring conventional wells. However, you may improve your coalbed coring operations by considering the guidelines below: ■

If coring with a coring rig, retrieve the core with a wireline assembly to minimize the amount of gas lost from the core. Cores that are quickly retrieved by wireline usually provide more reliable gas desorption data.

■

Fill the wellbore with fluid before coring to reduce the amount of gas lost from core samples. Cores taken from air-drilled holes may lose a large amount of gas.

■

Data on coal joints and/or cleats can be obtained by oriented coring. Oriented coring allows the directional measurement of geologic features. Oriented coring was used successfully at the Rock Creek project to determine cleat direction, rock joint orientation, faults, etc.

■

Unconsolidated or highly fractured formations can be cored with a rubber sleeve core barrel. Because the inner diameter of a rubber sleeve is smaller than the diameter of the core, the rubber sleeve stretches and contracts around the core as it enters the catcher. The rubber sleeve may help preserve the core enough to allow identification of fractures and lithological features.

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Guidelines for Coring with a Rig When coring coalbed methane wells with either conventional or wireline retrievable tools, you may find the guidelines below useful:

2-40

■

Select core points with competent rock above and below the coal interval. Competent core above and below the coal in the core barrel will increase the probability of successfully retrieving the core.

■

Run the core barrel into the hole slowly. Running in the hole at excessive speeds may damage the barrel if a dogleg is hit or may cause the barrel to plug.

■

Begin coring with a light bit weight and low rotary speed and then gradually increase weight and speed as cutting is established.

■

Use low pump rates when coring to avoid washing away the coal.

■

Monitor the pump pressure to ensure that fluid is passing over the bit and that the core barrel is not plugged. If the pump pressure increases, raise the bit off bottom. If raising the bit does not decrease pump pressure, the core barrel is probably plugged and should be pulled.

■

A sudden decrease in penetration rate that is not caused by a formation change could indicate the core barrel is plugged or jammed and should be pulled.

■

When finished coring, pull the drillstring very slowly. Pulling the drillstring too quickly can create suction, which can pull the core out of the barrel.

Casing and Cementing the Wellbore

Casing and Cementing the Wellbore A proper wellbore casing and cementing job is critical to the successful completion of a coalbed methane well. When designing the casing program, you should select the proper equipment and materials for your application. If you have not read Selecting Hole Size and Selecting Casing Weight and Grade earlier in this chapter, you may want to do so now. This section will help you in:

• Selecting Casing Hardware • Selecting Cement and Additives • Running the Casing String • Cementing the Casing String

Selecting Casing Hardware You should select casing hardware that is compatible with the cementing, stimulation, and completion plan for the well. Because of the marginal economics for coalbed wells, most coalbed methane operators try to minimize investment in casing hardware. However, savings on casing hardware can be easily overshadowed by formation damage or loss in well control caused by lack of proper equipment. Before beginning your casing and cementing program you should obtain a casing and cementing handbook from one of the major oilfield service companies. This handbook provides specifications and other useful information on casing and cementing equipment and materials. Operators in the Black Warrior Basin use a variety of casing hardware when running casing. The purpose and procedure for using several of these tools is described below:

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Cement Wiper Plug A cement wiper plug is a rubber plug (or rubber with a cast aluminum insert) used to separate the cement slurry from the displacement fluid to prevent contamination and/or dilution of the tail end of the slurry. Because water is normally used as the displacement fluid in coalbed methane wells, slurry contamination is usually not a problem, but dilution could occur. The wiper plugs are mounted in a cementing head at the top of the casing so they can be released directly behind the slurry without shutting down.

Guide Shoe A guide shoe is a short heavy-walled pipe or collar with a round nose on bottom. The shoe is installed on the bottom of the casing to prevent the casing from hanging on ledges or other borehole irregularities. The guide shoe is attached to the bottom of the production casing before running the casing into the hole.

Float Collar A float collar contains an internal valve which prevents backflow of cement up the casing string during cementing operations. It also increases the buoyancy of the casing, thus reducing the load on the rig while running casing. In addition, the float collar serves as a stop for the cement wiper plug so that all of the cement is not inadvertently pumped out of the casing. The float collar is usually installed one joint above the guide shoe.

Casing Centralizers Casing centralizers ensure the casing remains in the center of the wellbore during cementing operations to allow for cement coverage on all sides of the casing string. Centralizing the casing improves the probability of effective cement jobs and zone isolation. In addition, centralization reduces the negative effects of bends or doglegs in the casing which could hamper artificial lift equipment and workover operations. When cementing across a coal seam, you should always run centralizers above and below each seam that may be produced at some future time.

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Casing and Cementing the Wellbore

The number of centralizers that you should run in the rest of the casing string depends on the hole size and the amount of hole deviation. When running 5-1/2 inch casing in a 7-7/8 inch hole, most service companies recommend running a centralizer at least every third or fourth joint. If the hole is highly deviated, you will need to space the centralizers closer together. ❈ Important Inadequate centralization of the casing can prevent an effective cement job.

Cement Basket A cement basket is a tool attached to the outside of the casing to provide support for the cement column while it cures. Cement baskets can be placed above zones that have low fracture gradients to prevent them from breaking down. If cement baskets become filled with debris, they may inhibit reciprocation of casing.

Baffle Plates with Latch-Down Plugs Baffle plates are installed in the casing, usually instead of or along with other cementing equipment. The plates are installed between the guide shoe and the first joint of casing or between the first two joints of casing if you would like to have one joint filled with cement at the bottom of the string. Baffle plates are held in place by the pin end of the casing or tool (such as a float shoe) below them. The latch-down plugs wipe the casing free of cement during displacement. The wiper plug latches in an internal catch in the baffle plate to prevent flow back into the casing after cementing.

Float Shoe A float shoe is a combination guide shoe and float collar. It has a round nose, and it contains a check valve and may also contain a catcher for the wiper plug. A latch-down plug may be used to prevent backflow in case the check valve fails. A float shoe can be used instead of a float collar and guide shoe.

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External Casing Packer An external casing packer, which is run in the casing string, forms a seal between the casing and the hole. If running casing in a deep well or in a well with weak coal zones (i.e., coals with low fracture gradients), you can run an external casing packer in the casing string to help support the cement column and reduce the pressure the cement exerts on the coal formation. To operate the packer, a plug is pumped down to a seat below the packer such as a baffle plate or cementing collar. Once the plug is seated, pressure is applied above it to open the ports to the packer. When the ports open, cement can be pumped. The cement fills the packer and inflates the packer element against the wall of the hole. After the packer is inflated, the ports in the cementing collar above the packer can be opened by applying additional pressure, allowing cement to flow into the annulus above the packer. External casing packers are normally used in coalbed methane wells to protect the lower-most coal seam in open hole completions. This technique is described in Chapter 4 - Completing the Well.

Multi-Stage Cementing Tool A multi-stage cementing tool is used when the required column of cement is too large to be pumped in a single slurry. The tool contains a plug catcher and side ports. To activate the tool, a plug is dropped, and then the casing is pressured up. This pressure seats the plug in the plug catcher to seal off the casing and open the side ports. Then the second cement stage is pumped, and it flows out the side ports to the annulus. This tool is run with the casing string. It is installed in the casing at a depth above the calculated top of the primary cement and above the coal formation to be isolated from cement intrusion. For more information on stage cementing, refer to Cementing the Casing String, later in this chapter.

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Casing and Cementing the Wellbore

Selecting Cement and Additives Because coals have a low mechanical strength, you must select a proper cement density to prevent the weight of the cement from fracturing the coal formations. For information on calculating proper cement density, refer to “Designing the Cementing Program” earlier in this chapter. After you have determined the correct cement density for your well, you can then select the proper cement. Experience in the Black Warrior Basin has demonstrated that you can usually avoid potential cementing problems and accommodate the tight economic constraints of coalbed methane completions by using one of the following cement slurry applications:

• Class A Slurry • Pozmix® Slurry • Silicalite Slurry • Foam Slurry • Specialized Slurry

Cement Slurry Designs Class A Slurry

Operators have used several different types of cement in coalbed methane wells. The simplest type used is Class A, which is a common portland cement. Class A cement has a density of 15.6 ib/ gal without additives. Adding bentonite to Class A cement can lower its density by increasing the maximum allowable volume of water that can be added to the cement. Adding 6% bentonite can reduce the density to 13.5 lb/gal. You can use Class A cement for relatively shallow coals if the coal will support its density. The maximum depth recommended for Class A is 6000 ft. Class A cement is more economical than the other premium cements.

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Pozmix ® Slurry

Pozzolans are siliceous or siliceous/aluminuous materials which you can use to lower the density of cement slurries, much the same as bentonite. If you are working in an area where the coal formation will support cement densities of 12 to 14 lb/gal, you can use a Pozmix® slurry to provide zone isolation and adequate compressive strength. A typical pozzolan blend is 50% Class A and 50% pozzolan. This mixture is commonly called "50/50 Poz." A 50/50 Poz cement has a density of 14.15 lb/gal. An advantage of pozzolan slurries is their resistance to corrosive fluids. A disadvantage is their lower compressive strength compared to Class A cement. A Pozmix® cement design which has been used successfully at the Rock Creek project is listed below: 1.

To mix the lead slurry, combine a 50/50 blend of Pozmix®/ Class A cement with 4% total bentonite for a slurry weight of 12.7 to 12.8 lb/gal.

2.

To mix the tail cement slurry, combine the same mixture as for the lead cement, but mix at 13.5 lb/gal. You can also mix a tail cement of 15.6 lb/gal using neat cement, if the coal formation will support this weight.

Silicalite Slurry

A Silicalite slurry is a blend of Class A, Pozmix®, and Silicalite. Including Pozmix® and Silicalite in the blend helps reduce the density by inceasing the amount of water which may be added to the slurry. In areas where coals will not support cement densities of 12 to 14 lb/ gal, a Silicalite cement may work effectively.You can mix a Silicalite slurry with a density from 11 to 13 lb/gal. A typical Silicalite slurry has a density of 11.5 lb/gal. Because the properties of silicalite cement are so well suited to coalbed methane wells, some operators use this slurry even in wellbores strong enough for a higher weight cement. The cement has excellent fluid loss characteristics, low slurry viscosity, set times

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Casing and Cementing the Wellbore

faster than Pozmix® blends, essentially no free water, and high early compressive strengths. Foam Slurry

Operators often use foam cement slurries to cement shallow, low pressure coalbed methane wells where weak zones would break down if a normal density cement were used. If you are working in an area where wellbore integrity requires slurries under 11 lb/gal, you may consider using a foam cement. Foam cement is usually a mixture of basic cement, foaming agents, stabilizing agents, and nitrogen. This combination provides a lightweight cement slurry with a high yield. Foam cement slurry may be the most economical if you have nearby access to nitrogen facilities. If nitrogen is not readily available, you may consider using conventional cement with multistage cementing tools. When comparing the cost of using a multistage tool to the cost of using foam cement, be sure to include the drillout cost for the multistage tool.

▲ Caution Pumping foam cement at too high a rate may create a higher friction pressure in the casing annulus than would other types of cement. This increased friction pressure may offset the benefit of the lighter weight of foam cement. To fully realize the benefits of foam cement’s lighter weight, do not pump foam cement at an excessive rate.

Specialized Slurries

You can use a variety of specialized slurries and additives to meet individual well requirements. For example, if you encounter a highly permeable zone that causes lost circulation, you could seal it off using a thixotropic cement, which sets very quickly. Thixotropic cements are also very effective for secondary or remedial cementing. Some types of light weight cement achieve lower densities by utilizing additives which allow adding more water to the slurry. However, the added water lowers the ultimate compressive strength of the cement. If you need a light cement for a primary cement job, you might use a special cement that incorporates hollow glass beads, or microspheres, with a base cement. You can add these hollow microspheres to any type

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of cement to produce slurries ranging in density form 9 to 12 lb/gal. This type of slurry can greatly reduce the density of the slurry without significantly reducing the compressive strength of the cured cement. Some glass microspheres may begin to crush at pressures near 4000 psi. Because the crush resistance of glass microspheres varies, you should check with the manufacturer or supplier of microspheres before using them. Though the depth to which glass microsphere slurrries can be used is limited, most coalbed methane wells are shallow enough to use them.

Cement Additives Special additives are usually mixed with the base cement to alter or improve slurry properties. You can use additives to accelerate or retard cement curing, to reduce slurry density, to control fluid loss or lost circulation, or to modify other slurry properties. For example, you can add calcium chloride or sodium chloride to cement to accelerate the time required for the cement to set or to hydrate. As mentioned earlier, you also can add pozzolans or bentonite to reduce the density of the cured cement. When designing your casing program, consult several different cementing company representatives who are trained and experienced in cementing coalbed methane wells. They can provide information about a variety of additives available for altering slurry properties to meet the requirements of your particular well. In areas where leakoff is high, consider the following guidelines:

2-48

◆

Add a low fluid loss additive to the slurry. Use an additive that does not delay thickening time or increase slurry viscosity.

◆

Add a lost circulation material such as gilsonite, cellophane flakes, or walnut shells to help prevent cement contamination of the fractured coal.

Casing and Cementing the Wellbore

Cementing the Casing String The following techniques have proven effective in cementing coalbed methane wellbores in the Black Warrior Basin.

Before the Cementing Job Before beginning to pump cement, you should follow the procedures below: 1.

Several hours before pumping the cement, meet with the service company people to discuss the goals of the cement job and the responsibilities of each person. Also discuss contingency plans for handling possible operational problems. Invite questions or suggestions regarding any aspect of the operation.

2.

Several hours before pumping the cement, conduct a safety meeting with all people who will be on location during the cementing job. Discuss safe operating procedures, use of safety equipment, and contingency plans in case of an emergency.

3.

Obtain a sample of the actual dry cement mixture (with additives) that will be pumped. Maintain this sample as a quality control check in case problems arise on the cement job. You can have it sent to a lab for analysis, if necessary.

4.

Install the cementing manifold with plug(s) (from the cementing company) on top of the casing. Figure 2-6 shows a cementing manifold similar to the type used to cement the wells at the Rock Creek project.

5.

Pressure test all surface pumping lines with water. Test up to the maximum anticipated surface pump pressure.

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6.

Obtain a sample of the mixed cement slurry so you can monitor its strength and curing characteristics over time.

Figure 2-6 Typical Cementing Manifold

Single Stage Cementing Operators in the Black Warrior Basin have successfully pumped single stage cement jobs on air drilled holes using only one plug. The procedures they use are listed below: 1.

Establish circulation down the casing and up the annulus with fresh water. This circulation will flush any debris in the wellbore to the surface. ◆

2-50

If the wellbore contains large amounts of debris, first circulate the wellbore with water, and then circulate again with a gelled fluid to more effectively flush out cuttings and debris.

Casing and Cementing the Wellbore

2.

Pump the cement slurry. To help ensure the cement slurry distributes evenly around the casing, reciprocate or rotate the casing string while pumping the slurry.

3.

Release the plug from the cementing manifold.

4.

Pump the displacement fluid (usually fresh water).

5.

Pump fluid until the plug “bumps bottom”. When the plug bumps, you will see a sharp increase in surface pump pressure.

▲ Caution Be careful not to bump the plug so hard that the pressure increase exceeds the casing burst pressure. Make sure the cementing service company uses a pump operator with enough experience to avoid this problem. If the well was drilled with mud, pump a bottom plug ahead of the cement slurry to wipe the mud from the casing and prevent contamination of the lead cement. As an alternative to pumping a bottom plug, you can pump a spacer or a mud preflush ahead of the cement. In wells drilled with air and circulated with fresh water, you do not need to pump a plug or spacer ahead of the cement.

Multiple Stage Cementing A common problem with cementing coalbed wells has been formation damage caused by fracturing the coal with cement. Early in the Rock Creek research project, a stage cementing technique was successfully used to prevent cement from contracting coal seams. The stage cementing procedures below were uesd at the Rock Creek project: Pumping the first stage

1. Calculte the volume of cement needed to fill the annulus from the float shoe to the desired cement top. To determine this volume, use caliper log and add a safety factor of 10-20%.

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2.

Establish circulation down the casing and up the annulus with fresh water. This circulation will flush to the surface any debris in the wellbore. ◆

If the wellbore contains large amounts of debris, first circulate the wellbore with water, and then circulate again with a gelled water fluid to more effectively flush out debris.

3.

Pump the first stage of cement.

4.

Run a rubber closing plug above the cement at the cementing head. See Figure 2-7. The closing plug prevents the displacement water from intermingling with and contaminating the cement.

Figure 2-7 Two Stage Cementing

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Casing and Cementing the Wellbore

5.

Pump the volume of displacement water behind the closing plug needed to move the plug to the bottom of the casing. You should see a sharp increase in pump pressure when the plug bumps bottom. After the plug reaches the bottom of the casing, it latches into a seat in the float shoe, preventing any further flow into or out of the annulus.

Pumping the second stage

6.

Calculate the volume of cement needed to fill the annulus from the cement collar up to the desired height above the collar. To determine this volume, use the caliper log and add a safety factor of 10-20%.

7.

Drop an opening plug down the casing to the opening plug seat in the cementing collar. See Figure 2-7.

8.

After the plug is set, apply pump pressure inside the casing to open the lower sleeve of the cementing collar or to open the ports of the external casing packer, whichever is used. For more information on cementing collars and external casing packers, refer to Selecting Casing Hardware, earlier in this chapter.

9.

Pump water to establish circulation up the annulus to the surface. Circulate until returns are clean. ◆

If using a cement collar only, allow at least 6 hours between the primary cement job and the second stage. This time is needed for the primary cement to gain sufficient strength to support the second stage.

◆

If using an external casing packer, you do not need to wait for the primary cement to cure. The packer will support the weight of the cement above it.

10. Pump second cement stage into the casing.

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11. Release a rubber closing plug at the cementing head. See Figure 2-7.

12. Pump water behind the plug to displace the cement into the annulus. See Figure 2-7. When the closing plug reaches the closing seat, the pump pressure in the casing closes the cementing collar ports to the annulus.

13. Shut in the well for at least 48 hours to allow the cement time to cure. A curing time of 72 hours is even better.

14. Pump into the casing with water and pressure test the cement to 1000 psi or to the pressure specified by your company. Pumping additional stages

15. Repeat steps 6 through 14. Because all of the internal parts of the cementing collar and float shoes are drillable, you can pass drillbits through the casing to complete open hole intervals below the casing.

For information on completing the well, refer to Chapter 4.

Rotating or Reciprocating Casing while Cementing One of the factors critical to the success of primary cementing jobs on mud-drilled holes is the displacement of the mud during cementing. Mud that is not displaced occupies space that should be filled with cement. Channels in the cement are often caused by mud that was not properly displaced. Rotating and/or reciprocating the casing during cementing operations helps to break the gel strength of the mud and thus allows the cement to more effectively displace the mud. Studies have demonstrated that for shallow wells (less than 6000 ft) rotating the casing is more

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Casing and Cementing the Wellbore

effective than reciprocating the casing. Some operators prefer to both rotate and reciprocate the casing.

▲ Caution

Reciprocating casing too rapidly can create pressure surges in the wellbore and fracture the coal. To prevent pressure surges, reciprocate the casing no more than 15-20 ft over a period of two minutes.

Because wells drilled with air contain no drilling mud, rotating or reciprocating the casing is not needed to displace mud. Many airdrilled holes in the Black Warrior Basin have been successfully cemented without moving the casing. However, in air-drilled holes which have casing that is not centralized, cement may tend to channel up one side of the casing. In this case, rotating the casing may help to more evenly distribute the cement around the casing. Using an adequate number of centralizers can help centralize the casing and promote an effective cement job. ❖

❖

❖

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Additional Resources

Adams, N.J., and T. Charrier, “Drilling Engineering: A Complete Well Planning Approach,” Pennwell Publishing Company, Tulsa, Oklahoma, 1985.

Graves, S.L., J.D. Niederhofer, and W.M. Beavers, “A Combination Air and Fluid Drilling Technique for Zones of Lost Circulation in the Black Warrior Basin,” SPE Paper 12873, SPE Drilling Engineering, February 1986.

Lambert, S.W. et al, “Multiple Coal Seam Well Completion Experience in the Deerlick Creek Field, Black Warrior Basin, Alabama,” Proceedings of the 1987 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (November 16-19).

Lambert, S.W., M.A. Trevits, and P.F. Steidl, “Vertical Borehole Design and Completion Practices to Remove Methane Gas from Mineable Coalbeds,” U.S. Department of Energy, Carbondale Mining Technology Center, Carbondale, Illinois, 1980.

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Wireline Logging

T

o evaluate the gas producing potential of a coal formation, you must first know the reservoir and mechanical properties of the coal. Knowing these properties will also enable you to design effective, economical well completions and stimulations. You can determine most of these coal properties by analyzing data from wireline logs and whole cores retrieved while drilling the well. After the well is completed, you can obtain additional reservoir data from well tests. This chapter will guide you through:

• Sources For Estimating Reservoir Properties • Open Hole Logging Tools • Selecting an Open Hole Logging Suite • Guidelines For Open Hole Logging • Cased Hole Logging Tools • Selecting a Cased Hole Logging Suite • Guidelines For Cased Hole Logging • Production Logging Tools

Chapter

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Wireline Logging

Sources for Estimating Reservoir Properties The sources for obtaining the properties you will need to evaluate coal reservoirs are shown in Tables 3-1 and 3-2 below.

Primary Non-Log Sources For Estimating Reservoir Properties Table 3-1

Reservoir Property

3-2

Source

Coal Thickness

Core Test

Permeability

Well Test

Adsorbed Gas Content

Core Test

Desorption Isotherm

Core Test

Desorption Time

Core Test

Initial Water Saturation

Well Test

Porosity

Core Test, History match with simulator

Ash Content

Core Test

Initial Pressure

Well Test

Sources For Estimating Reservoir Properties

Table 3-2 Logging Sources for Estimating Reservoir Properties Reservoir Property

Open Hole Log

Cased Hole Log

Coal identification

Density, Gamma Ray, Caliper

Neutron (Pulsed or Compensated)

Net thickness

High Resolution Density

Neutron (Pulsed or Compensated)

Proximate Analysis*

High Resolution Density, Compensated Neutron, Gamma Ray, Spectral Density, Sonic

None

Permeability* (qualitative estimate)

Dual Laterolog, Microlog, Resistivity/SP

None

Cleat Orientation*

Formation MicroScanner®

None

Mechanical Properties*

Bulk Density, Full Waveform Sonic

None

* For a detailed discussion of each of these properties and how to obtain them, refer to The Development of Formation Evaluation Technology for Coalbed Methane - Annual Technical Report (December 1990 - December 1991) by ResTech, Inc. for GRI.

3-3

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Wireline Logging

Open Hole Logging Tools To estimate reservoir properties for coal seams, you can use a variety of wireline logging tools. This section provides a background for these logging tools; however, it does not cover log interpretation. For information on interpreting these logs, refer to Additional Resources at the end of this chapter. The operation of each tool, its response in coalbeds, and important considerations for using the tool are explained below.

Open Hole Logging Tools for Identifying Coal Seams When possible, you should log the open hole as soon as practical after drilling and cleaning it up. This practice helps to reduce the chance of damaging the formation before measuring its properties. It also decreases the possibility of encountering hole obstructions when logging. You can identify and estimate the thickness of coal seams using the logging tools listed below:

• Bulk Density Log • Spectral Density Log • Caliper Log • Natural Gamma Ray Log • Dual induction/Shallow Induction Log • High Resolution Induction Logs

Bulk Density Log The density log measures the bulk density of the formation as emitted gamma rays are scattered by the formation. In most non-coal formations, you can relate bulk density to porosity when you know the lithology. The bulk density log is an excellent tool for identifying and evaluating coal seams. Generally, you can identify coal seams by comparing

3-4

Open Hole Logging Tools for Identifying Coal Seams

the bulk density of coal (1.20 to 1.80 g/cc) to that of other formations (2.2 to 2.7 g/cc). The density of coal is affected by ash content. The higher the ash content, the higher the density response on the log. Density instruments generally consist of a gamma source (usually Cesium 137) and two detectors. The source and detectors are located on a skid (pad) which is forced against the side of the hole. The longspaced detector primarily measures the formation. The short-spaced detector measures the formation and the materials that occur between the pad and the formation. For wells drilled with air, the short-spaced tool will read the formation unless there is a washout in the wellbore. Gamma rays are emitted from the source into the formation and then are scattered by the orbital electrons of the atoms in the material being measured. This phenomena, called “Compton Scattering,” causes the gamma rays to lose energy. If the material is very dense (i.e., contains many electrons), the gamma rays become more scattered and more of them are absorbed by the material. Because of this absorption of gamma rays near the detector, fewer gamma rays reach the detector. In formations with fewer electrons (lower density), the gamma rays are not slowed as much and therefore more of them reach the detector. Identifying coal seams using the density log is generally straightforward. Figure 3-1 shows a bulk density log run at the Rock Creek Project. The relatively low bulk density in the Mary Lee seam at 10451048 ft (RHOB = 1.24 g/cc) and in the Blue Creek seam at 1051-1057 ft (RHOB = 1.4 g/cc) sharply contrasts with the density of the surrounding formations. A washout or borehole caving could cause a similar logging response; however, you can look at the caliper log and gamma ray log to check the hole condition across the interval.

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Figure 3-1 Bulk Density Log

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Open Hole Logging Tools for Identifying Coal Seams

Some of the more common matrix densities are listed in Table 3-3.

Table 3-3 Matrix Densities

for Common Formations Mineral

Density (g/cc)

Sandstone

2.65 - 2.70

Shale

2.2 - 2.65

Limestone

2.71

Dolomite

2.83 - 2.89

Anhydrite

2.94 - 3.00

Salt (halite)

2.03

Coal Anthracite Bituminous Lignite

1.4 - 1.8 1.2 - 1.5 0.7 - 1.5

Once you determine from the density log that an interval contains a coal seam, be sure also to check the caliper log and gamma ray log to verify that the density response was not caused by a hole washout. Evaluating seam thickness using log data is directly related to the vertical resolution and sample rate of the logging device. The distance of the detector from the radioactive source strongly influences the vertical resolution of the logging device. Most standard oilfield density tools have a source-to-detector spacing of 18 inches. The vertical resolution of this tool has been improved by increasing the sample rate from every 6 inches to every tenth of a foot. Currently, oilfield density tools can provide a resolution of about 6 inches. The oilfield density logs can be computer enhanced to provide results similar to the density tools available from mineral logging service companies.

3-7

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Wireline Logging

The density tool available from mineral logging service companies has a source-to-detector spacing of 0.75 inch and samples data at a rate of 50 samples per foot. This device has a vertical resolution of approximately one inch. Because the mineral logging density tool is smaller in diameter than a standard bulk density tool, make sure the mineral logging tool can offer the log quality for the wellbore size you have drilled. Figure 3-2 shows a comparison of the mineral logging density (high resolution) and the oilfield density (computer enhanced). The comparison shows that computer enhancement of the oilfield logging measurement is an accurate method for improving vertical resolution. [From The Development of Formation Evaluation Technology for Coalbed Methane - Annual Technical Report (December 1990 - December 1991) by ResTech, Inc. for GRI]

❈ Important

When using a density log, make sure to question the validity of density measurements across washed out zones. The density tool is a pad device which requires good borehole contact to measure accurately. As a guide for determining net pay thickness of coal seams for use in reservoir simulators and well test analysis, ResTech, Inc. recommends using a density cutoff of 1.75 g/cc. The coal thickness obtained using this method should be compared to core data (if available). In thin coal seams, the density value on the density log can be erroneously high.

3-8

Open Hole Logging Tools for Identifying Coal Seams

Figure 3-2 Comparison of Conventional Density and Mineral Logging Density Logs

Spectral Density Log The spectral density tool is similar to the bulk density tool described earlier. However, in addition to measuring gamma rays from “Compton Scattering,” which is indicative of bulk density, it also measures gamma rays from the photoelectric effect, which is indicative of lithology. By comparing these two different gamma ray counts, you can determine the photoelectric absorption index (Pe) and

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Wireline Logging

the lithology. The average photoelectric absorption index for some common formations is shown in Table 3-4.

Table 3-4 Photoelectric Absorption Index for Common Formations

Formation

Photoelectric Absorption Index

Sandstone

1.810

Shale

3.420

Coal

0.180

Caliper Log The caliper log measures the gauge of the borehole. Formations may remain in gauge during drilling or they may have severe washouts. The hole condition will depend on the formations encountered and the drilling techniques used. If a well has severe washouts, you could easily mistake a low density log reading across the washout for a coal seam. By checking the caliper log, you may avoid such an erroneous interpretation. Conversely, a washed out interval could occur across a coal seam. To make sure a washed out interval does not contain a coal seam, you should check all available data, such as gamma ray log, neutron log, sonic log, cores, or drilling cuttings. Figure 3-3 shows a caliper log run with a bulk density log. The caliper shows that the Mary Lee seam at (1045-1048 ft) and the Blue Creek seam at (1051-1057 ft) are in gauge.

3-10

Open Hole Logging Tools for Identifying Coal Seams

Natural Gamma Ray Log The natural gamma ray log records natural radioactivity in formations and is useful for correlating coalbeds. All rocks exhibit some natural radioactivity: the amount depends on the concentration of potassium, thorium, and uranium. Table 3-5 shows the total natural radioactivity for sandstone, coal, and shale.

Table 3-5 Total Natural Radioactivity of Common Formations

Total Natural Radioactivity Formation

(API units)

Sandstone

10 - 30

Coal