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)

1

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. ❖

❖

❖

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.

1 A

About This Guide

A

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. ❖

❖

❖

i

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

❖

❖

❖

iii

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

i v

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 ❖

v i

(Cont'd)

❖

❖

Conventions Used in This Guide

S

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.

v

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

u

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.

vii

1 A

Acknowledgments

A

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 ❖

❖

❖

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.

■

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

■

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.

■

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.

■

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.

■

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.

■

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.

❖

xi

❖

❖

1


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


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?

■

What is the chemical composition of this water?

■

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

■

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

■

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

1-3

Chapter

1


■

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

■

What is the life of a discharge permit?

■

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:

■

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.

■

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.

■

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

■

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.

1-5

Chapter

1


■

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.

■

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.

■

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

■

Minimize road grades whenever practical.

When constructing roads, follow the guidelines below whenever practical:

1-6

■

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

■

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


■

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

■

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.

■

Never use known hazardous or toxic materials in constructing roadbeds.

■

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.

■

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

1


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

■

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

■

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

■

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.

■

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

■

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


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.

■

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

■

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.

■

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

1


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

■

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.).

■

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

■

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

■

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.

■

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

■

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.


■

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.

■

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.

■

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.

■

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.

1-11

Chapter

1


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

Chapter

1


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-

1-15

Chapter

1


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


“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


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

Chapter

2


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


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

2-5

Chapter

2


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


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

Chapter

2


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


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

Chapter

2


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


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

Chapter

2


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


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


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


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

Chapter

2


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


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.

2-17

Chapter

2


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.


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

Chapter

2


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

2-20


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.

2-21

Chapter

2


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


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.

2-23

Chapter

2


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

2-24


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

2-25

Chapter

2


❖

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:

2-26


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.

2-27

Chapter

2


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.

2-28


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.

2-29

Chapter

2


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

2-30


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

2-31

Chapter

2


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

2-32

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.

2-33

Chapter

2


◆

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.

2-35

Chapter

2


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.

2-36

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

2-37

Chapter

2


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.

2-39

Chapter

2


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:

2-41

Chapter

2


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.

2-42


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.

2-43

Chapter

2


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.

2-44


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.

2-45

Chapter

2


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

2-46


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

2-47

Chapter

2


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.


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.

2-49

Chapter

2


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.


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%.

2-51

Chapter

2


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

2-52


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.

2-53

Chapter

2


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

2-54


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. ❖

❖

❖

2-55

Chapter

2



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.

2-56

3

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

3

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

Chapter

3

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.

3-5

Chapter

3

Wireline Logging

Figure 3-1 Bulk Density Log

3-6


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

Chapter

3

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


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

3-9

Chapter

3

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


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

<70

Shale

80 - 140

Because coal usually exhibits low total natural radioactivity (usually less than 70 API units), you can identify coal seams by the deflection of the gamma ray curve to the left. Figure 3-1 shows the gamma ray response across two coal intervals in the Black Warrior Basin. The gamma ray resolution is greater across the slightly thicker Blue Creek seam (1051-1057 ft) than across the Mary Lee seam (1045-1048 ft). The presence of thin partings, consisting of various clay minerals, will increase the measured natural radioactivity. Under certain localized conditions (e.g., the absence of high and widely varying kaolinite concentrations), ash content may be determined empirically from the gamma ray log. Because this log can also be recorded in cased hole, it is used as a correlation log for other cased hole wireline operations such as perforating and production logs.

3-11

Chapter

3

Wireline Logging

Dual Induction/Shallow Induction Log The dual induction log is a tool that measures the resistivity (or conductivity) of a formation to an electrical current which is induced into the formation. Coal, limestones, and most lowporosity sandstones in coalbed methane regions are highly resistive. Shales, in contrast, are nearly always low in resistivity, and they therefore show up distinctly on resistivity logs. You can use the deep induction curve primarily for correlating coalbeds. The deep induction shows a very gradual increase in resistivity at coalbed boundaries because of its large vertical resolution (approximately 6 feet). Because most coals in the Black Warrior Basin are less than 2 feet thick (the Blue Creek seam is approximately 5 feet thick), the dual induction log is not widely used on wells in this basin. Dual induction logs are limited by thin bed effects, borehole washouts, and mud resistivity. The shallow induction log, which is usually run with the dual induction log, is a resistivity device that normally shows sharp increases in resistivity at coalbed boundaries. Because this tool has a resolution of approximately 18 inches, you can use it for measuring the thickness of coalbeds. When using the dual induction log, you should follow these guidelines: ■

Use the shallow curve to measure coal thickness. Sometimes you will be able to identify partings, or shale stringers, of one foot or greater in the coalbed to help you measure the thickness of the coal.

■

Use the shallow resistivity curve to read resistivity in the coalbed. Because of bed thickness effects on deep induction measurement, the shallow resistivity curve of the tool usually gives a more accurate measure of resistivity in the coalbed.

Figure 3-3 shows a dual induction/shallow induction log run on a well at the Rock Creek project.

3-12


Figure 3-3 Dual Induction/Shallow Log

High Resolution Induction Logs Because of the increased need for methods to identify thin, interbedded hydrocarbon reservoirs in conventional wells, wireline companies have been working to develop logging tools with improved vertical resolution. Until recently, only nuclear logging tools had the capability of defining thin beds. However, several new resistivity tools have been developed recently that have proven particularly effective for defining thin coalbeds. One of these tools is called the High Resolution Induction (HRI) log. It was developed by Halliburton Logging Services and was introduced to the industry in 1987. This log incorporates a new coil-array design that optimizes both vertical and horizontal responses. With this log, both the deep and medium resistivity measurements have a vertical resolution of two feet. The HRI tool also provides a depth of investigation 40% greater than the conventional induction tool. In addition, this tool significantly reduces shoulderbed effects and provides a better indication of bed thickness.

3-13

Chapter

3

Wireline Logging

Other wireline logging companies have developed similar high resolution resistivity tools. Schlumberger offers the Phasor Induction Log, which has also been used successfully to define thin coalbeds in the Black Warrior Basin. Figure 3-4 shows a Phasor Induction Log with a coalseam at 2444-2448 ft.

Figure 3-4 Phasor Induction Log

The Phasor Induction Log is an improved version of the dual induction log. It collects eight measurements and can generate three induction curves. The tool detects signals returning from the

3-14

Open Hole Logging Tools for Determining the Quality and Properties of Coal

formation that previously were unused by the dual induction log (i.e., signals that are out of phase, or that do not return perpendicularly). The tool uses these out-of-phase signals to display a much sharper bed boundary. The Phasor Induction Log has a normal resolution of three feet. Like the dual induction log, this tool displays deep, medium, and shallow curves. The resolution of the tool may be enhanced to two feet by computer processing the shallow and medium curves. The most recent advance in the induction log is the Array Induction Tool (AIT). This Schlumberger log, which is an improvement over the Phasor Induction Log, collects 28 measurements and can display five induction curves. This tool can investigate as deep as 90 inches and as shallow as 10 inches. The AIT provides even better definition of shoulder beds than the Phasor Induction Log. The AIT has only been available to the industry for a few months, and it has not yet been used in coalbed methane wells in the Black Warrior Basin.

Open Hole Logging Tools for Determining the Quality and Properties of Coal Because each type of formation has a characteristic (but not necessarily unique) log response, it is possible not only to identify specific formations, but also to assess their quality. Logs have been used to estimate reservoir quality in conventional wells for many years. Based on these same principles, logs are now being used to evaluate the quality and mechanical properties of coal seams. Table 3-6 shows typical log responses in sandstone, shale, and coal for the logs most commonly used to evaluate coals: Density, Gamma Ray, Neutron, and Sonic.

3-15

Chapter

3

Wireline Logging

Table 3-6 Responses for Logs Commonly Used to Evaluate Coals

Density Logs

Formation

Bulk Density (g/cc)

Photoelectric Index

Sandstone

2.65-2.70

1.810

10-30

-2

47-56

Shale

2.20-2.65

3.420

80-140

25-75

70-150

Coal

1.20-1.80

0.180

<70

>50

95-135

Gamma Ray (API units)

Neutron Porosity (%)

Sonic TravelTime (µ sec/ft)

You can run several logs to evaluate the quality and mechanical properties of coal and non-coal formations encountered in the wellbore. This section provides a brief discussion of the logging tools listed below:

• Microlog • Dual Laterolog/Microspherically Focussed Log • Spontaneous Potential (SP) Log • Compensated Neutron Log • Epithermal Neutron Log • Formation Microscanner ® • Sonic Log • Full Waveform Sonic Log

3-16


• Geochemical Logs • Carbon/Oxygen Log • Spectral Gamma Ray Log • Borehole Televiewer • Temperature Log • Computer-Processed Log Presentations • Geophysical Well Log Models

Microlog The microlog is a tool that measures resistivities at two different depths in the formation immediately adjacent to the borehole. One of the resistivities is the mudcake resistivity and the other is the formation (or coal) resistivity. The resistivity of the mudcake is significantly less than that of coal. Consequently, if mudcake has formed in the borehole across an interval, the two resistivity curves will separate because they are reading different levels of resistivity. For mudcake to form, mud filtrate (liquid) must pass into the formation. Thus, the presence of mudcake across a formation is an indication of permeability in that formation. Therefore, positive separation of the resistivity curves on a microlog could indicate coal cleat development in coalbed wells drilled with mud. Because most wells in the Black Warrior Basin are drilled with air or water instead of mud, the microlog is not usually run in this basin. In areas where coalbed methane wells are drilled with mud, there are several factors that can affect the microlog: ❖

Resistivity of the mud

❖

Mudcake thickness

❖

Depth of invasion

❖

Borehole rugosity

❖

Formation porosity

3-17

Chapter

3

Wireline Logging

The resistivity of the mud compresses or expands the microlog resistivity values. In low-resistivity muds, the microlog resistivities are compressed to a narrow range, which reduces the accuracy of the microlog ratio. In high-resistivity muds, the microlog resistivities are expanded, which enhances the accuracy of the microlog ratio interpretation. An optimum mud resistivity at bottomhole temperature is normally from 1 to 3 ohm-meters. Mudcake thickness controls the amount of separation between the normal and lateral curves. In general, the positive separation you see on the log increases as the thickness of the mudcake increases. This separation may indicate fluid filtration into the formation. You can qualitatively assess the permeability (and hence cleat development) of the coal by comparing the microlog separation across the coals to that across adjacent formations.

❈ Important

Some drilling mud additives used as flocculants can cause erroneous microlog interpretations. These flocculants, which plate boreholes with mudcake, may cause the microlog to show positive separation in low permeability coalbeds. Very heavy or viscous muds may also cause erroneously high estimates of coal cleating. You should closely monitor and control fluid loss while drilling the hole. Fluid loss of the mud system controls mudcake thickness.

❈ Important

The microlog is a pad device and is sensitive to rapid changes in the borehole wall. In washed out boreholes, the microlog often measures the resistivity of the mud. Therefore, you should run the log down the hole, with the tool closed, over the bottom 1,000 feet of hole to record a log of the mud resistivity. The log of mud resistivity will highlight any changes in mud resistivity over the zone of interest and help ensure that you use the correct value of Rm when interpreting the log.

Dual Laterolog/Microspherically Focussed Log The dual laterolog/microspherically-focused log (DLL/MSFL) is a resistivity tool run primarily in coalbed wells drilled with a salty mud system. Most DLL/MSFL tools are run in wells drilled with a mud salinity of 50,000 ppm NaCl. Typically, the DLL/MSFL is used in these mud-drilled wells to calculate porosity.

3-18


The DLL/MSFL is well suited to coalbed wells because it yields more accurate resistivity measurement in formations with high resistivity values such as coalbeds. In general, using the DLL/ MSFL to determine the thickness of coalbeds is more accurate than using the deep induction curve. Because most wells in the Black Warrior Basin are air-drilled, the DLL/MSFL log is not usually run in this basin.

Spontaneous Potential (SP) Log The spontaneous potential (SP) log measures the differences between the electrical potential in the borehole and the fixed potential of a surface electrode. Because SP responses are not consistent in coalbeds, the SP log is not often used to evaluate wells in the Black Warrior Basin. However, the SP log may sometimes be useful in some areas as a qualitative indicator of coal permeability. Quantitative estimates of permeability from the SP log are not possible. SP response is highly sensitive to the resistivity of connate water and resistivity of drilling mud. When analyzing an SP log, make sure to consider the salinity of the formation water. The SP log cannot be recorded in holes that contain only air. However, if you drill a hole with air, you can fill the hole with water and then run the SP log. Figure 3-5 shows an example of an SP log run in the Black Warrior Basin. Because the coals in this section are relatively thin, the SP log shows poor resolution across both coal intervals.

Compensated Neutron Log In conventional oil fields, the compensated neutron log (CNL) is used principally for identifying porous formations and quantifying their porosity. However, in coalbeds, the neutron log shows erroneously high porosities (often 40-70%). For coalbed applications, the compensated neutron log is usually run to help determine proximate analysis and to estimate gas content. Neutron logs measure the formation’s ability to slow the movement of neutrons through the formation. The neutron log emits neutrons

3-19

Chapter

3

Wireline Logging

Figure 3-5 SP Log

into the formation. These neutrons collide with hydrogen atoms and are slowed down. The receivers on the neutron tool measure the speed, or energy, of the neutrons that have collided. This measurement reflects the concentration of hydrogen in the formation. Because the only hydrogen in clean reservoir rock is associated with water or oil, the neutron measurement indicates the porosity of the formation. In coalbeds, however, the high concentration of hydrogen (even when water is not present) causes the neutron log to measure erroneously high porosity values.

3-20


❈ Important The CNL can be run in liquid-filled holes, either open hole or cased hole. However, the CNL cannot be run in air or gas-filled holes. When using the compensated neutron log, you should question the validity of compensated neutron log measurements across washed out intervals. Figure 3-6 shows a compensated neutron log run on a well in the Black Warrior Basin. The log shows a neutron porosity of about 55% across both the Mary Lee seam (1045-1048 ft) and the Blue Creek seam (1051-1057 ft).

Figure 3-6 Compensated Neutron Log

3-21

Chapter

3

Wireline Logging

Epithermal Neutron Log Neutron logs emit high energy neutrons into the formation. As these neutrons collide with the formation they are slowed to a lower energy level, or thermal state. The neutrons that remain at a high energy level are called epithermal neutrons. The compensated neutron log (CNL) can detect only thermal neutrons. However, the epithermal neutron log contains detectors which can distinguish between thermal and epithermal neutrons. Both the CNL and epithermal logs are useful for identifying coalbeds. However, the epithermal log can provide more accurate porosity measurements in non-coal formations. In addition, the epithermal log can be run in both open and cased holes.

Formation MicroScanner® The Formation Microscanner (a registered trademark of Schlumberger) is a pad device that records microresistivity variations around the borehole wall. The tool can be used to determine coal cleat orientation. Formation MicroScanner® data from the Rock Creek Project in the Black Warrior Basin were successfully analyzed to determine the orientation of coal cleat. Measurements from the Formation MicroScanner agreed favorably with cleat orientations determined from whole core data recovered from several wells. Figure 3-7 compares the Rose Diagrams determined from a Formation MicroScanner® log and from cores for a well in the Black Warrior Basin. Rose Diagrams show the orientation of coal cleat.

3-22


Figure 3-7 Comparison of Cleat Orientation Determined from a Formation MicroScanner® Log and from Cores

Cleats were identified as small conductive breaks on opposing resistivity pad images that were enhanced. Cleat orientation was determined by selecting points on the resistivity images at the conductive breaks. An equidistant midpoint was also selected so that a plane defining cleat azimuth could be defined by the computer. Then, the cleat strike was determined by adding or subtracting ninety degrees to or from the computed azimuth.

3-23

Chapter

3

Wireline Logging

The Formation MicroScanner can also be used to determine the strike, dip, and azimuth of coalbeds, and to identify fractures in coal seams and adjacent formations.

Sonic Log In conventional applications, empirical correlations are used to relate sonic travel time to porosity if the lithology is known. In coalbed methane wells, sonic logs may be used to determine coal rank. They also may be used to identify coalbeds; however, they are not as accurate as the density and gamma ray logs. Sonic tools measure the shortest time required for a compressional wave to travel vertically through one foot of formation adjacent to the wellbore. In coalbeds, sonic travel times range from 95 - 135 microseconds per foot. Sonic travel times in non-coal formations typically range from 60 - 90 microseconds per foot. Shales usually have a sonic travel time less than 100 microseconds per foot. However, it is often difficult to distinguish shale from anthracite coal.

❈ Important

You should evaluate all log information available when using the sonic tool to identify coal. You can easily confuse carbonaceous shales for coal if you rely only on analysis of transit time. Figure 3-8 shows a sonic log run at the Rock Creek project. The sonic travel time in the Blue Creek coal (1050-1056 ft) and the Mary Lee coal (1044-1047 ft) show travel times greater than 125 microseconds and 115 microseconds, respectively. The travel time in the Mary Lee coal is shorter because it is a thinner bed.

3-24


Figure 3-8 Sonic Log

Full Waveform Sonic Log For many years, the only information used from the sonic log was the first wave arrival (the compressional wave). However, each pulse from the transmitter of a sonic log creates several types of waves in the formation. Because it has long been recognized that these waves would change forms at bed boundaries, much work has been done to understand and correlate the waveforms to formation characteristics. This work first led to the development of methods to

3-25

Chapter

3

Wireline Logging

measure the shear wave (which follows the compressional wave), and more recently to full waveform logging. Because of its complexity, full waveform logging technology is still in a developmental stage. Most waveform sonic logs are run in coalbed wells to evaluate mechanical rock properties, such as compressive strength and elastic moduli, for use in designing fracture treatments. Sonic logs may also be used to tie-in seismic data. For conventional formations, you may be able to infer formation permeability from full waveform sonic data. In this method, you first compare the shear or compressional arrivals in a permeable zone and a non-permeable zone. Then, you compare the energy levels of the sonic arrivals in the zone of interest to the other two values to estimate permeability. Experience has shown, however, that this correlation does not work well for coals because coals naturally attenuate the sonic signal. Figure 3-9 shows the shear, compressional, and Stonely travel times obtained from a full waveform sonic log run at the Rock Creek project. The coal seam is shown at 973-979 ft. Using empirical equations, Poisson's ratio and Young's modulus can be calculated from these travel times for both the coal and non-coal formations in the well. These rock properties can then be used to estimate the maximum fracture height that might occur during a fracture treatment.

3-26


Figure 3-9 Full Waveform Sonic Log

Geochemical Logs Geochemical logs are useful in measuring elemental components of the formation. These logs can be used in creating depositional models for coalbeds and in correlating ash beds from well-to-well, similar to the use of the spectral gamma ray tools. Currently, GRI is sponsoring research on developing depositional models for coalbeds based on geochemical logging.

3-27

Chapter

3

Wireline Logging

A typical geochemical string includes a natural gamma ray tool, an aluminum activation clay tool, and a gamma ray spectroscopy tool. The combination of these tools can measure up to 10 elemental concentrations in the formation. You can use these elemental concentrations together with data from the density, neutron, and spectral density tools to detect the presence of up to 10 minerals. Geochemical logs are most accurate when run in open hole, but you can also run them in cased holes. Two methods are currently used to convert the elemental data to mineral data. You can calibrate the logging tool by using a data base containing core measurements from around the world. Or alternatively, you can calibrate the tool with local core data measurements. The geochemical log and the carbon/oxygen log are often run together and displayed on a computer-processed presentation such as the one shown in Figure 3-10 from the Rock Creek project. The right hand track of this presentation shows the formation composition derived by a computer model from the base logs (gamma ray spectroscopy, natural gamma ray, neutron, density, and dual induction). Because early lithology models could not adequately account for coal intervals, this log erroneously shows a quartz (sandstone) formation with high porosity across the Mary Lee/Blue Creek coal seam at 1044-1056 ft. Most logging companies now have computer-processed lithology models that can accurately identify coal seams. For example, Figure 3-11 shows a Schlumberger VOLAN® geochemical log run in the same Rock Creek well. The VOLAN® log, which is derived from the base logs (gamma ray spectroscopy, natural gamma ray, neutron, density, and dual induction), accurately identifies the Mary Lee/Blue Creek coal seam at 1045-1058 ft.

Carbon/Oxygen Log The carbon/oxygen log provides a measure of the carbon content of the formation. In conventional oil and gas applications, the carbon/ oxygen (C/O) log is used to help determine oil saturation behind pipe. In coalbed methane wells, the carbon/oxygen log may be used to determine the BTU content of coal. Bituminous coal yields a large contrast between the carbon/oxygen ratio at the sand-shale baseline and in the coal. This contrast can help you identify coals behind pipe.

3-28


Figure 3-10 Geochemical and Carbon/Oxygen Log

In most formations, the carbon/oxygen log responds primarily to the fluids that fill the rock's pore spaces (carbonate formations are an exception). In conventional oil fields, the carbon/oxygen maximum curve shows what the carbon content of the formation would be if the pore spaces were 100% oil-filled. The minimum curve shows what the carbon content would be if the pore spaces were 100% water-filled. The middle curve on the log indicates the actual carbon content of the formation. In conventional oil fields, these three curves would be used to calculate water saturation.

3-29

Chapter

3

Wireline Logging

Because coals have very low porosity (2-6%) and very high carbon content, the carbon/oxygen log responds primarily to the carbon content of the coal rather than to fluid-filled porosity. In fact, the carbon/oxygen log response is much more pronounced across a coal seam than across an oil-bearing sandstone. Figure 3-10 shows a carbon/oxygen log run across the Blue Creek/Mary Lee coal seam at 1044-1056 ft.

❈ Important

The C/O log is most accurate in a uniform gauge, open hole. In cased holes, washouts behind the pipe will degrade the C/O ratio.

Figure 3-11 VOLAN ® Geochemical Log

3-30


Spectral Gamma Ray Log The natural gamma ray spectrometry log, or spectral gamma ray log, measures the total radioactivity of formations and the concentrations of thorium, uranium, and potassium that produce the radioactivity. This log, which can be run in either open hole or cased hole wells, provides useful data for identifying formations adjacent to coalbeds, and for correlating ash beds from well-to-well. You can also use the spectral gamma ray log for modeling depositional environments. For example, many coals, especially low rank coals, can be identified by their high concentrations of Uranium. You may also enhance depositional models by estimating clay mineral content from the spectral gamma ray log. Some spectral gamma ray tools can be modified to record a natural lithology curve which is similar to the photoelectric measurement on the modern bulk density tools. The low lithology ratio values correlate to the low Pe (photoelectric effect) values in the coalbeds. The lithology ratio works only in open holes. On the left-hand track of the spectral gamma ray log, total radioactivity counts are recorded in either counts per minute or API units. On the right-hand track of the log, the potassium (K) curve is recorded in percent, and the uranium (U) and Thorium (Th) curves are recorded in parts per million (ppm). Figure 3-12 shows a spectral gamma ray log run at the Rock Creek project. The Mary Lee and Blue Creek coal seams are shown at 1045-1057 ft.

Borehole Televiewer The borehole televiewer is an acoustic device that scans the borehole horizontally with a rotating, focused receiver. The televiewer has been used with only limited success in detecting coalbed thickness and in identifying coal cleats. Borehole televiewers are very sensitive to borehole geometry. Because it provides poor measurements in elongated, rugose, or collapsing boreholes, the borehole televiewer has been used little in coalbed wells.

Temperature Log Because temperature changes across coalbeds are usually very subtle, temperature logs are not useful for delineating coalbeds.

3-31

Chapter

3

Wireline Logging

However, you can use a temperature log to locate water-producing zones, points of gas entry into the wellbore encountered during drilling, which may have to be cased off before completing the well.

Figure 3-12 Spectral Gamma Ray Log

Computer-Processed Log Presentations Many of the logging service companies offer customized log presentations that may help you identify coals and evaluate their quality and producibility. These logs contain computer-processed data based on the responses of the basic logs, such as the density, gamma

3-32


ray, resistivity, sonic, and neutron logs. Some of the computerprocessed logs also incorporate core data provided by the operator. Because the basic logs have better resolution in thicker formations, the accuracy of computer-processed logs is likewise greater in thick formations, such as those in the San Juan Basin, than it is in thin formations, such as those in the Black Warrior Basin. Though computer-processed logs may prove useful, if you decide to use them, make sure you fully understand what log data is used to generate the presentation and how that data is processed. The value of the computer-processed presentation will be no greater than the quality of the data used to create it. The computer-processed geochemical log shown earlier in Figure 3-10 is based on the gamma ray spectroscopy, natural gamma ray, neutron, bulk density, and dual induction logs. This geochemical log shows the formation composition of all intervals. Figure 3-13 shows a computer-processed coal quality log based on the sonic and bulk density logs. This log graphically shows the percentage composition of carbon, ash, volatiles, and moisture in the Upper Pratt "A" and Upper Pratt "B" coal seams.

Geophysical Well Log Models Estimating coal quality, gas content, and coal permeability from open hole logs certainly is not a proven technique. However, research is underway to develop methods for accurately correlating open hole logs to core data so that the coals in a development well can be evaluated with open hole logs alone. When a correlation between the core and log data has been established for one well, a model based on that correlation can be developed for the entire field. The model can then be used to estimate coal quality, gas content, and coal permeability for development wells in that field based solely on well log information. This technique, when perfected, could eliminate the need to obtain cores from each well. For more information on this GRI research, refer to The Development of Formation Evaluation Technology for Coalbed Methane - Annual Technical Report (December 1990 December 1991), ResTech, Inc. for GRI, March, 1992.

3-33

Chapter

3

Wireline Logging

Figure 3-13 Computer-Processed Coal Quality Log

If you use geophysical modelling for a field, you should model each coal seam separately. Don't assume correlations for one coal seam will apply to another seam. In addition, you should understand the geology of the field well enough to recognize what factors might cause a variation in coal quality, gas content, or coal permeability. The reservoir and rock properties of the coal and overlying rock can vary considerably over short distances. Some of the variables that may contribute to this heterogeneity are the presence or absence of fractures in the overlying rock, stress regimes in the rock, cleat development within the coal, and the presence of mineral filling in the cleat system.

3-34

Selecting an Open Hole Logging Suite

Selecting an Open Hole Logging Suite Selecting a proper suite of logs will help you to obtain the information you need to accurately evaluate coalbed reservoirs. Tables 3-7 and 3-8 show logging tools that have proven effective in the Black Warrior Basin for obtaining various reservoir information in open hole exploration and development wells. The extensive suite of logs suggested for exploration wells might help provide information about both coal seams and non-coal formations in the well.

Table 3-7 Logging Tools for Open Hole Exploration Wells Logging Tool

Information Obtained

High Resolution Density, Spectral Density, Gamma Ray

Coal identification and thickness

Caliper

Hole size and wellbore condition

Dual Laterolog, Microlog, Resistivity, SP

Permeability

Neutron

Gas content

Formation Microscanner®

Cleat orientation

Density, Full Waveform Sonic

Mechanical properties

3-35

Chapter

3

Wireline Logging

Table 3-8 Logging Tools for Open Hole Development Wells

Logging Tool


High Resolution Density or Spectral Density, Gamma Ray

Coal identification and thickness

Caliper

Hole size and wellbore condition

Guidelines for Open Hole Logging Before logging an open hole coalbed methane well, carefully consider the type of reservoir properties you want to obtain from wireline logs and select the appropriate logging suite. Then review the guidelines below to help ensure the quality of the data you obtain.

❈ Important ■ When possible, you should log the open (uncased) hole as soon as practical after drilling and conditioning it. This practice helps to reduce the chance of damaging the formation before measuring its properties.

■

3-36

If the well has sufficient rathole and the logging truck is properly equipped, stack all of the logging tools and run them on a single trip in the hole. This procedure saves rig time for logging and eliminates possible depth discrepancies that could occur if you run the tools separately.

Cased Hole Logging Tools

■

If you are logging in a new area, you can refer to well logs from offset wells (if they are available) to approximate coal seam depths.

■

Make one or two repeat runs over the coal beds before making the main logging run. Repeat runs help you to validate the logging measurement.

■

When running nuclear logging tools, use a logging speed of 30 feet/minute.

■

Make one logging pass at 18 feet/minute using high resolution processing to record maximum detail in the coalbeds. Shale stringers in coalbeds may be masked because they are thinner than the standard vertical resolution. High resolution processing of the density log can reduce the vertical resolution to six inches. You may be able to accurately identify shale stringers six inches thick, but you still may not be able to identify thinner stringers.

❈ Important ■ High-resolution processing must be done when you originally log the well. It is not possible to re-process a log recorded with a two-foot resolution to change its resolution to one foot.

■

To obtain greater detail from logs, you can present them on an expanded scale, (e.g., 20 inches equal to 100 feet).

Cased Hole Logging Tools To obtain the most accurate measurements of formation properties, you should log the open (uncased) hole. However, if hole conditions or other constraints prevent you from running an open hole log, you may still obtain some formation data by running a cased hole log. You may also run cased hole logs during the producing life of a well to monitor reservoir properties, to evaluate additional coal seams, or to diagnose mechanical wellbore problems. This section describes tools you can use to log cased hole coalbed methane wells.

3-37

Chapter

3

Wireline Logging

Compensated Neutron Log The dual detector-compensated neutron log is the tool most frequently run in cased holes to identify coalbeds and to measure net coal thickness. The measurements from a cased hole compensated neutron log should be as reliable as those obtained from an open hole compensated neutron log.

❈ Important

Washouts behind pipe can be difficult to interpret with a compensated neutron tool.

Pulsed Neutron Log The pulsed neutron log is often run in cased holes to identify coalbeds and to measure net coal thickness. The pulsed neutron log is interpreted in much the same way as the compensated neutron log, except that pulsed neutron log displays a neutron ratio instead of a neutron porosity. Increasing neutron ratio corresponds to increasing porosity, which is indicative of coal. The neutron ratio curve is not as sensitive as the compensated neutron porosity. However, the pulsed neutron log may have a slightly better depth of investigation than the compensated neutron log. Therefore, the pulsed neutron log may give better resolution in cased hole than the compensated neutron log. These general guidelines apply to the pulsed neutron log: ■

The pulsed neutron log is ineffective when it encounters hole washouts behind pipe.

■

You should establish the pulsed neutron ratio cutoff for coal on a well-by-well basis. Differences in hole size, cement quality, casing size, and tubing size affect the accuracy of the ratio curve.

Gamma Ray Log The gamma ray log records the natural radioactivity of formations. Because coal usually exhibits low total natural radioactivity (usually less than 70 API units), you can identify coal seams by the deflection of the gamma ray curve to the left. The presence of thin partings, consisting of various clay minerals, will increase the measured natural radioactivity.

3-38

Cased Hole Logging Tools

Because the gamma ray log can be recorded in cased holes, it is very useful for: ❖

Correlating coalbeds

❖

Providing accurate depth control when it is run with a casing collar locator

❖

Locating radioactive tracers used in fracturing treatments (If more than one isotope is used, you should use the spectral gamma ray log)

Cement Bond/Variable Density Log Cement evaluation tools that employ acoustic measurements, if correctly interpreted, can provide useful information for evaluating the success of primary cementing on initial well completions. They can also be used to assess the need for remedial cement jobs. The cement bond log (CBL) provides a continuous measurement of the amplitudes of sound pulses after they have traveled a length of casing. This amplitude is maximum in unsupported pipe, and minimum in well-cemented casing. The variable density log (VDL) is usually included with the CBL. The VDL provides information about the quality of the formation bonding. You can run a gamma ray log simultaneously with the CBL/VDL. The primary uses for the CBL/VDL are: ❖

To determine the effectiveness of the cement sheath in the casing-formation annulus

❖

To check the effectiveness of squeeze cementing

❖

To locate the cement top

An improved version of the standard cement bond log is now available. This log can help you evaluate the distribution and quality of cement around the entire wellbore radius. The tool is useful for identifying channels that cannot be detected by standard

3-39

Chapter

3

Wireline Logging

CBL tools. This log also is unaffected by microannulus as is the standard CBL. Figure 3-14 shows a Cement Bond/Variable Density Log (CBL/ VDL) run in a well at the Rock Creek project. The log shows a transition from "free pipe" (poor cement bond) to good cement bond at 651 ft.

Figure 3-14 Cement Bond/Variable Density Log

3-40

Selecting a Cased Hole Logging Suite

Often the decision whether to run cement evaluation logs is based primarily on economic considerations. When deciding whether to run cement evaluation logs, you should consider the following guidelines: ■

When well conditions allow you to apply sound primary cementing practices, the cement evaluation logs may not be necessary.

■

When conditions make primary cementing difficult, and where experience has demonstrated that success of primary cement jobs is low, the cement evaluation logs can help you identify potential problem areas and possibly improve cementing practices.

■

When fluid movement behind the casing is suspected, the cement evaluation logs may confirm the problem and may show where remedial cementing can be effectively applied.

■

When oil and gas regulatory agencies may require a CBL prior to completing and producing a well, check with the oil and gas regulatory agency in your area.

Selecting a Cased Hole Logging Suite Selecting a proper suite of logs will help you to obtain the information you need to accurately evaluate coalbed reservoirs. Table 3-9 shows logging tools that have been found effective in the Black Warrior Basin for obtaining various reservoir information in cased hole wells.

3-41

Chapter

3

Wireline Logging

Table 3-9 Logging Tools for Cased Hole Wells Logging Tool


Mineral logging density*

Coalbed identification and seam thickness

Gamma ray/CCL

Coalbed correlation

Cement bond log/VDL/CCL

Integrity of cement job

* Not necessary if an adequate open hole density log was obtained.

Guidelines for Cased Hole Logging Before logging a cased hole coalbed methane well, carefully consider the type of reservoir properties you want to obtain from wireline logs and select the appropriate logging suite. Then review the guidelines below to help ensure the quality of the data you obtain. ■

3-42

Before beginning any wireline completions or workover operations, always compare the depths on the cased hole gamma ray log to the depths on the open hole gamma ray log. For example, when preparing to perforate an interval, never assume the cased hole gamma ray log has been properly correlated to the open hole gamma ray log. The perforations for new wells or recompletions are often selected from the open hole log. If you assume the cased hole log is on depth, and it is not, you could perforate the wrong interval. Always verify which log the perforations were selected from, and then correlate that log with the cased hole log.

Guidelines for Cased HoleLogging

■

When running a cased hole log on a workover, always identify the static fluid level in the wellbore. Knowing the static fluid level can help with later log interpretation.

■

When running a cement bond log, make sure you include the logs or displays listed below. You can use the amplitude curve and variable density curve to evaluate the cement job. ❖

Amplitude curve for cement

❖

Variable density display

❖

Casing collar locator

❖

Gamma ray log

■

Avoid circulating cold fluids in the casing before running the initial cement bond log. Cold fluids could adversely affect the amplitude and VDL measurements on the cement bond log.

■

Correlate the cement bond log with the open hole log to make sure they are recorded at the same depth. The gamma ray log is the primary source for this correlation.

■

When running a cement bond log, make sure you tag and record the plugged back total depth (PBTD) of the well and log from PBTD to the top of the cement.

■

If the cement bond log shows poor cement bond throughout the hole or through a large section, pressure up on the casing and rerun the log under pressure. A microannulus between the casing and cement can cause the cement bond log to show poor bonding. Pressuring up on the casing expands the casing, which can reduce the microannulus and improve the cement bond.

3-43

Chapter

3

Wireline Logging

Production Logging Tools Production (or cased hole) logging refers to running logs after the production casing string has been cemented and the well has been placed on production. Production logging tools are designed to operate downhole under static or producing conditions to provide the data you need to determine the physical condition of the well, to evaluate the performance of the well completion, to diagnose well problems, or to evaluate the results of well workover operations. Most coalbed methane wells require artificial lift to produce. To evaluate a well under dynamic producing conditions, you must run production logs while the artificial lift equipment is operating. Therefore, instead of running logs down the production tubing, you must run them down the tubing/casing annulus. This can be accomplished by using the dual completion wellhead illustrated in Figure 3-15. Using this wellhead, you can pump the well while the production logs are run through the second opening. Installing this wellhead requires a workover rig to lift the tubing.

Figure 3-15 Wellhead Configuration for Annular Logging

3-44

Production Logging Tools

The most common production logging tools used in coalbed methane wells are:

• Continuous Flowmeter • Gradiomanometer • Temperature Log • Downhole Camera

Continuous Flowmeter The continuous flowmeter is used to determine which coal intervals are contributing flow to the wellbore and the percentage flow contribution from each interval. The tool is a spinner type velocimeter which records a continuous flow profile versus depth. Although the continuous flowmeter has no practical upper limit on flow rate which can be measured, there is a minimum flow rate below which the tool will not operate. The flowmeters used for most conventional applications required minimum flow rates that were higher than many coalbed methane wells could produce. To reduce the required minimum flow rate, Computalog Wireline Services developed a flowmeter with a lighter (titanium) impeller and improved bearings. This flowmeter tool, illustrated in Figure 3-16, is being used successfully on coalbed methane wells in the Black Warrior Basin. Fluid viscosity has a marked effect on spinner speed; decreased viscosity increases spinner speed. Therefore, the downhole response curve of spinner speed versus fluid velocity must be established for specific well conditions. A method of interpretation called the Two-Pass Technique is effective for multi-phase flow. In its simplest form, this technique involves making one pass down and one pass up through the zone. The response curves are then matched in the zone of zero flow below the bottom perforations. The Two-Pass Technique should reduce interpretation time and permit recognition of relatively small fluid entries.

3-45

Chapter

3

Wireline Logging

Figure 3-16 Flowmeter Developed for Coalbed Methane Wells

❈ Important To properly calibrate a continuous flowmeter, you must first establish the baseline of no flow below the perforations and then make multiple runs at different speeds.

Figure 3-17 shows a continuous flowmeter log which was run in the Black Warrior Basin .

Gradiomanometer The gradiomanometer is an effective tool for identifying gas entry and for locating standing water levels in wellbores. The gradiomanometer records a continuous profile of pressure gradient by measuring the difference in pressure between two pressure sensors. This pressure difference is principally due to changes in the average density of the wellbore fluid. Therefore, the greater the density difference between wellbore fluids, the more accurate is the resulting interpretation.

3-46


Figure 3-17 Flowmeter Log

❈ Important Repeat runs with the well shut-in are useful in calibrating the gradiomanometer.

Temperature Log The temperature log responds to temperature anomalies produced by fluid flow either within the production tubing, the casing or in the casing annulus. Therefore, the temperature log is useful for detecting tubing leaks or water flow behind casing. Temperature

3-47

Chapter

3

Wireline Logging

log interpretations can also be used to determine flow rates and points of fluid entry into the wellbore.

Downhole Camera The downhole camera is a specially designed video camera that allows viewing of actual conditions in the wellbore. Because the resolution of downhole cameras has improved greatly in recent years, the camera has become an effective tool in diagnosing downhole production problems in coalbed methane wells. It has also helped in evaluating the location and orientation of fractures in open holes. Specifically, you can use downhole camera surveys in: ❖

Determining whether perforations are open or plugged with fines or scale

❖

Determining qualitatively which zones are contributing flow and the amount of flow

❖

Determining the type of influx along vertical coal cleats or in bedding planes

❖

Evaluating the condition of casing (e.g., looking for corrosion or splits)

❖

Inspecting the location and position of a fish left while drilling or working over the well

Limitations of the Camera Survey

Though the camera is a useful tool, it does have limitations. For example, the hole must contain clear fluid for the camera to provide detailed pictures. If the fluid is not clear, you may try to displace it with clear fluid. However, the fluid you pump may flow into shallow perforations or permeable zones. You may find it difficult to displace fluid from deeper intervals without running the tubing back into the well. Another possible limitation is the pressure rating of the camera. This rating not only limits the maximum depth at which the camera can be used, but may also limit the operations that can be performed with the camera in the hole. Because the camera used at

3-48


the Rock Creek Project was rated for 1000 psi, it worked effectively for the shallow zones of the Black Warrior Basin.

Running the Camera Survey

To get the best information from the camera survey, you should discuss your objectives for the survey with the camera crew before they rig up. Tell them specifically what information you would like for them to obtain from the survey. The usual procedure for running a downhole camera survey at the Rock Creek Project is listed below: At least one day before the survey 1.

Prepare a list of features you wish to view in the well and their depths (if you know them).

2.

Schedule the camera unit to be at the well site and ready to run in the hole as soon as the workover rig finishes pulling the tubing.

3.

Schedule a truckload of fresh clear water to remain on standby at the well site while running the camera survey.

4.

Make sure to have a casing collar log on location so you can correlate the depth of the camera as you would with any production log.

The day of the survey 1.

Mobilize the workover rig.

2.

Pull sucker rod string, downhole pump, and tubing string out of the hole.

3.

Rig down the workover rig (unless it is more practical or economical to leave it rigged up during the survey).

3-49

Chapter

3

Wireline Logging

4.

Run in the hole with the camera.

5.

Proceed downhole as quickly as practical so you can view the zone before encroaching water covers it.

6.

Correlate the depth of the camera using a previous casing collar log. The camera survey is not run with a casing collar locator log, but you will be able to identify casing connections with the camera.

7.

Run the camera through the zone of interest and make notes of any pertinent observations.

8.

If the well fluid is too dark to see through, pump the standby water into the wellbore while the camera is downhole. Do not exceed a pressure of 1000 psi on the camera.

9.

When finished viewing the wellbore, pull the camera out of the hole.

10. Rig up the workover rig and run the tubing string, pump, and rod string back into the well. ❖

3-50

❖

❖



“The Development of Formation Evaluation Technology for Coalbed Methane - Annual Technical Report (December 1990 December 1991),” ResTech, Inc. (for GRI), March, 1992.

Hilche, D.W., “Advanced Well Log Interpretation,” Hilche, Inc., Golden, Colorado, 1982.

Douglas W.

Mullen, M.J., “Log Evaluation In Wells Drilled For Coal-Bed Methane,” Geology and Coal-Bed Methane Resources of the Northern San Juan Basin, Colorado and New Mexico, Rocky Mountain Association of Geologists, Denver, 1988.

Rieke, H.H. III, C.T. Rightmire, and W.H Fertl, “Evaluation of Gas-Bearing Coal Seams,” Journal of Petroleum Technology, January, 1981.

3-51

4

Completing the Well

T

echniques for completing coalbed methane wells have evolved from completion experience with conventional oil and gas wells. Though some conventional techniques can be applied directly, others have been modified to accommodate the unique characteristics of coal reservoirs. The primary goal in completing a coalbed methane well is to establish communication between the wellbore and the target formation. Effective formation access is essential to successfully stimulate and produce the well. This chapter will guide you through:

• Reservoir Considerations in Completing the Well • Objectives of Completing the Well • Completing in Open Hole • Completing in Cased Hole • Accessing the Formation • Selecting Production Tubing • Working Over Wells

Chapter

4

Completing the Well

Reservoir Considerations in Completing the Well Completing a coalbed methane well is often similar to completing a conventional oil or gas well. Though the type of formation is different, many of the same reservoir engineering principles apply. When planning a completion for a coalbed methane well, consider these general guidelines for coal reservoirs:

■

In many cases, the cleat system of coal is 100% water saturated. Therefore, you must recover water to lower the formation pressure to initiate gas desorption and flow. The volume of water to be produced will affect the selection of tubulars and artificial lift method.

■

Coalbed methane wells are often drilled through a group of coal seams separated by non-coal formations. Your decision to complete individual seams or groups of seams will determine what completion method you select.

■

Because coal seams have relatively low permeability, you will likely need to hydraulically fracture the well to stimulate production. For more information on fracturing, refer to Chapter 5.

■

Production of coal fines is similar to sand production in unconsolidated sand reservoirs. The flow of fines into the wellbore may cause severe damage and plugging problems to the wellbore and to surface equipment. Hydraulic fracturing may help control coal fines. When you fracture a coalbed well, you redistribute the near-wellbore pressure profile so that the coalface is not exposed to a high pressure drop within a small area.

Objectives of Completing the Well When completing a coalbed methane well, you should attempt to: ■

4-2

Provide effective communication between the wellbore and the natural fractures and cleat system of the coal. This communication is usually achieved by open hole completion and/or perforated/slotted cased hole completion.

Objectives of Completing the Well

Experience at the Rock Creek project and in other parts of the Black Warrior Basin has shown that effective communication with the coal’s natural fractures cannot always be established by perforating or slotting. Additional stimulation is sometimes needed to establish communication.

■

Provide for control over stimulation operations. When you plan to complete multiple coal seams, you must select a completion method that will allow you to effectively control stimulation operations on individual coal seams. These completion methods are explained later in this chapter.

■

Minimize completion cost. To ensure the economical development of low rate coalbed methane wells, you must carefully control the completion cost. A completion method must be relatively inexpensive to be economically viable. However, when designing completions, you must select casing sizes that will not restrict production from multiple zones. For more information on selecting casing size, refer to Chapter 2.

■

Minimize wellbore damage and maximize well productivity. Wellbore damage from drilling operations may cause flow restriction near the wellbore. To connect the wellbore to the virgin reservoir, you must eliminate this flow restriction. You can overcome wellbore damage by either removing the damage or bypassing it. Even if no wellbore damage exists, stimulation is required to establish commercial production because the permeability and productivity of coal is so low. The methods below are effective in minimizing wellbore damage and maximizing productivity. Hole Enlargement

In this method, you remove near-wellbore damage simply by underreaming the hole, but not by applying any other stimulation. (The underreamer tool is described in Equipment for Workovers and Completions, later in this chapter.) This method may help establish economical production if reservoir permeability is high enough to drain a reasonable area of the reservoir. If permeability

4-3

Chapter

4

Completing the Well

is low, then you must use a stimulation treatment that reaches beyond the near-wellbore area. Hydraulic Fracturing

In fracturing the formation, you bypass wellbore damage rather than treating it directly. If the coal seam is not damaged, fracturing can provide a highly conductive flow path between the natural fractures in the coal and the wellbore. This technique creates a long fracture that connects the wellbore to the virgin reservoir. The length of fracture needed depends on many variables including the permeability and gas content of the coal. A fracture stimulation designed only to overcome near wellbore damage will not sufficiently stimulate the well. Experience at the Rock Creek project has shown that an optimum fracture length exists for a coal seam with a given permeability and gas content. In general, the longer the fracture length, the greater will be the gas producing potential of the reservoir. However, beyond a certain size fracture treatment, the incremental gas production may not justify the cost of the larger treatment. For more information on hydraulic fracturing, see Chapter 5.

Completing in Open Hole This section explains the applications and limitations of open hole completions in:

• Single Coal Seams • Multiple Coal Seams

Single Coal Seams in Open Hole Mining companies have used the single-zone, open hole completion extensively to degasify coalbeds before mining operations. Though some coalbed methane producers in the Black Warrior Basin have tried using open hole completions, most now use cased hole completions. A properly performed open hole completion can eliminate the risk of fracturing the coal with cement. However, rubble from a large open hole section can interfere with production. Experience in the Black Warrior Basin has shown that open hole completions usually are not

4-4

Completing in Open Hole

as successful as cased hole completions. Formations in the open portion of the hole must be competent enough to prevent sloughing of formation into the wellbore. Sloughing can cause excessive well fill-up, which may eventually restrict production and require costly cleanout operations. In addition, open hole completions reduce your ability to control access to zones during stimulation. In some areas, open hole completions could also limit the control of water influx from non-coalbed aquifers adjacent to the coalbed. Figure 4-1 shows a typical single-zone, open hole coalbed completion.

Figure 4-1 Single-Zone Open Hole Completion

In the Black Warrior Basin, the three most common methods for performing a single-zone, open hole completion are:

• Drilling to Total Depth and Setting Casing • Drilling to the Top of the Coalbed and Setting Casing • Drilling to Total Depth, Backfilling, and Setting Casing

4-5

Chapter

4

Completing the Well

The general procedures for each of these three methods are explained below:

Drilling to Total Depth and Setting Casing 1.

Drill the entire projected depth of the well.

2.

Locate the target coalbed.

3.

Set casing using a formation packer shoe.

4.

Position the casing shoe from 2 to 10 feet above the highest coalbed you plan to produce.

5.

Cement the casing string.

6.

Drill out the packer/shoe (preferably with water or air mist), leaving the underlying coalbed open.

Drilling to the Top of the Coalbed and Setting Casing 1.

Stop drilling from 2 to 10 feet above the target coal seam.

2.

Set the casing and float shoe.

3.


4.

Drill out the float shoe and hole to total depth, leaving the coalbed exposed.

Drilling to Total Depth, Backfilling, and Setting Casing 1.

4-6

Drill the well to total depth.

Completing in Open Hole

2.

Backfill the hole to the casing point (2 to 10 feet above the coalbed) using sand or other such fill material.

3.

Lower the casing to the top of the fill material.

4.


5.

Wash the fill material from the well, leaving the coalbed open.

In each of these methods, you can also underream or enlarge the open hole portion to remove near-wellbore damage. Underreaming may help establish economical production from the reservoir if the wellbore intersects the natural fractures in the coal and if the permeability of the coal is high enough to drain a large area of the reservoir.

Multiple Coal Seams in Open Hole Completing multiple coal seams in open hole is similar to the method for completing a single zone in open hole. However, to complete multiple seams, you use open hole inflatable packers to separate zones. Open hole completions were used with limited success in the Deerlick Creek Field in the Black Warrior Basin. However, this method was abandoned because of operational problems and resulting low gas production rates. In general, open hole completions have not proven effective for multiple-zone wells. The main disadvantages of the multiple-zone open-hole completion method are: ❖

Separating zones is impractical if pay stringers are thin.

❖

Inflatable packers must be removed after each treatment.

❖

Packers may leak and cause communication between zones.

❖

Fluids may leak past the packer because of hairline stress fractures in the formation caused by the packer. ❖ Some open holes are too irregularly shaped for a packer to seal effectively.

4-7

Chapter

4

Completing the Well

❖

The packer could become stuck in the open hole.

Figure 4-2 shows a multiple-zone, open hole completion.

Figure 4-2 Multiple-Zone Open Hole Completion

Completing in Cased Hole To maximize production from shallow, thin coalseams, most operators today complete multiple coal horizons through casing. Using cased hole completion methods will help avoid the problems of open hole completions and will help: ❖ Maintain hole stability

4-8

Completing in Cased Hole

❖

Allow selective completion of multiple coal seams

❖

Maintain control over the well during stimulation operations

❖

Reduce coal fines production

❖

Allow the use of resettable packers rather than inflatable packers

The cased hole completion method is especially effective for completing multiple zones in a single well. Figure 4-3 shows such a completion. Though cased hole completions provide several important benefits, they also can have some drawbacks that may reduce their effectiveness:

Figure 4-3 Multiple-Zone Cased Hole Completion

4-9

Chapter

4

Completing the Well

❖

Cement invasion caused by fracturing the coal during cementing operations can cause formation damage.

❖

Blockage of access points (perforations or slots) because of coal abrasion during stimulation or because of coal movement behind the casing during production.

At the Rock Creek project, a stage cementing technique was once used successfully to prevent cement invasion into coal seams. For more information on this technique, refer to Cementing the Casing String in Chapter 2. The Rock Creek project also tested a fracturing technique used by some operators in the Black Warrior Basin that can reduce blockage of access points during fracture stimulation. In this technique, called interseam completion, coal seams are fractured by initiating the fracture in noncoal formations adjacent to the coal layers. For more information on interseam completions, refer to Special Formation Access Techniques, later in this chapter.

Accessing the Formation Accessing the formation means providing a physical pathway of communication between the wellbore and the target formation. Access controls the effectiveness of well testing, stimulation treatments, and production operations. Without effective communication to the formation, it is not possible to accurately measure formation properties such as permeability. During stimulation, the type of access affects the amount and type of coal abrasion. Conversely, during production the access points control the quantity of fluid that can move from the formation into the wellbore.

Methods of Formation Access This section first explains the formation access methods that operators in the Black Warrior Basin use most often and then it explains criteria for selecting an access method. Operators in the Black Warrior Basin have used a variety of methods to access coal seams. Some of the methods have proven more successful than others. Each of these methods is explained below:

4-10

Accessing the Formation

• Perforating Through Casing • Jetting Slots Through Casing • Special Formation Access Techniques Perforating Through Casing Perforations provide the most efficient and cost-effective method for accessing coalbeds, especially when you are targeting multiple zones. Using conventional wireline-conveyed perforating guns, you can access the formation rapidly and with pinpoint accuracy. You can perforate the casing using either bullets or jet charges. Jet charges have largely replaced bullets in the oil industry because they penetrate deeper in hard rock formations. However, bullets may provide better penetration and hole uniformity in low density coal formations. Perforations are available in a variety of sizes. A perforation diameter of 0.41 inches can provide sufficient formation access to reduce pressure losses during fracturing and decrease pressure drawdown into the wellbore during production. Smaller diameter shots provide greater penetration for channels through cement-invaded zones. Operators in the Black Warrior Basin use a variety of perforating charges. Some operators prefer to perforate shallow coal seams using charges that create a large hole size to maximize gas flow into the wellbore. However, for deeper coal zones, operators often sacrifice hole size in favor of charges that penetrate deeper into the formation and through any cement invasion. Most operators use a perforation charge that provides a hole size of 0.37 to 0.41 inches and a penetration of 8 to 13 inches. Typically, you can effectively access a coalbed interval with shot densities of 4-12 shots per foot, depending on fracture treatment design and expected production rates. For more information on specifications and operating procedures for perforating equipment, consult with wireline service companies that have experience perforating coalbed wells in your area.

4-11

Chapter

4

Completing the Well

▲ Caution Using an excessively large perforation charge may pulverize the coal and severely damage permeability. To perforate a zone, correlate the ports on the perforating gun with the formation depths using a gamma-ray log and a casing collar locator attached to a retrievable casing gun. (Expendable guns are also available for use in holes with restricted diameters.) Then detonate the guns via wireline. Figure 4-4 shows a typical perforated cased hole completion.

Figure 4-4 Perforated Cased Hole Completion

Jetting Slots through Casing Using the jetting technique, you cut slots in the casing and cement sheath by discharging a water/sand mixture (occasionally nitrogen-

4-12


charged) at high pressure through 1/8 to 1/4 inch jet nozzles on a tubing string. Operators have used various forms of jet cutting to complete coalbed methane wells. Some operators jet open-hole completions to expand the wellbore and to remove skin damage on the coal face caused by invasion of drilling fluids or cement and to possibly induce fracture propagation. Operators most often use jetting in cased hole completions to cut two, three, or four vertical slots in the casing and to remove formation damage. Because of the relatively higher cost of jetting slots, many operators prefer to use perforations instead of slots. Figure 4-5 shows a typical jet-slotted cased hole completion.

Figure 4-5 Slotted Cased Hole Completion

4-13

Chapter

4

Completing the Well

To cut slots, coalbed methane operators normally use one of these jet slotting procedures:

• The “Position-Move-Position” Procedure • The “Reciprocating” Procedure Using the “Position-Move-Position” Procedure This method provides a series of individual holes in the casing. To use this method, follow the steps below:

1.

Rig up the workover rig and wireline truck.

2 . Install a jetting nozzle on the end of the tubing. The jetting tool has a seat on which a ball can be used to plug the end of the tubing.

3 . Trip the tubing into the well to a depth where the end of the tubing is below the target zone.

4 . Run a gamma ray log down through the tubing and locate the target coal seam(s) by correlating this through-tubing gamma ray log with the openhole gamma ray log.

5 . Lower the gamma ray tool to the jetting nozzle and record the depth. Then raise the gamma ray tool up to the target zone and record this depth. Calculate the distance between these two depths and use this value in step 7.

6 . Pull the gamma ray tool out of the tubing.

4-14


7.

Place a mark on the outside of the tubing at the top of the slips or at the top of the wellhead. Raise the tubing string the distance calculated in step 5 and place another mark on the tubing above the slips or wellhead. This mark indicates the position that the tubing must be in to begin jetting.

8.

Connect the injection lines from the pump truck to the tubing.

9 . Circulate water down the tubing, out the bottom opening of the jetting nozzle, and up the annulus to remove any debris that may plug the nozzles.

10. Drop a ball to shut off the bottom opening of the tool. Before running the jetting tool, make sure the ball is the proper size for the seat in the tool. On some tools, the tungsten carbide nozzles may protrude into the throat of the tool, which reduces the I.D. above the ball seat.

1 1 . Circulate with water after the ball is dropped to make sure the ball has seated. When the ball is seated properly, you will notice a pressure increase in the tubing.

1 2 . Begin jetting with water* containing a sand concentration from 1 to 1-1/2 lb/gal. Jet in one place until you observe coal cuttings at the surface. To better monitor returns, set up a screen which will trap the cuttings. You should first observe metal cuttings from the casing at the surface. These cuttings may be so small that you have to use a magnet in the return stream to identify them. When you have cut through the casing, you should

4-15

Chapter

4

Completing the Well

observe return water that is black or dark. This color is from the coal fines. After the color of the water changes, you should begin seeing coal cuttings at the surface.

13. After you see coal cuttings at the surface, move the tubing one or two inches to reposition the nozzle. 14. Begin jetting again, and monitor returns for metal cuttings and coal cuttings. After the first slot is cut, the water may remain dark for the rest of the slotting operation.

15. Repeat steps 14 through 16 until you have slotted the entire target interval.

16. After the interval has been slotted, stop pumping sand and circulate clean water until the returns are free of coal cuttings. The water may remain dark if you are cycling the water, but the coal cuttings should stop when the well is cleaned up.

17. When the returns are clean, shut down the pump and reverse the circulation by pumping down the annulus and up the tubing string to remove the ball in the nozzle.

18. After the ball is at the surface, lower the tubing string slowly while reverse circulating to clean out the casing to bottom. Monitor pump pressure closely. Large pieces of coal can plug the small opening at the bottom of the tool and cause a rapid increase in pump pressure.

* You may circulate nitrogen instead of water for slotting. Nitrogen can enhance cutting because it removes cuttings more quicklythan water. It also ensures returns to the surface. Though most coal seams can support the hydrostatic pressure of a column of water, some seams may not. If a seam cannot support a water column, you would not be able to observe the

4-16


returns at the surface. In such cases, using nitrogen will lower the hydrostatic pressure on the seam and allow you to get returns to the surface. Though nitrogen is more expensive than water, the additional cost may be offset by reduced slotting time.

▲ Caution This method may partially fill the coalbed near the wellbore with sand and coal fines, which can make later fracturing and production operations difficult. This problem occurs because the slots created directly above or below the jet prevent the jet stream from circulating properly back into the wellbore.

Using the “Reciprocating” Procedure A more effective jetting method is called “reciprocating.” This method involves moving the jet up and down continuously until you observe coal returns at the surface of the well. This procedure cuts a continuous vertical slot through the casing by a sand-fluid mixture discharged at high pressure through jet nozzles. Constant washing of the slotted area minimizes buildup of debris. Continuous slots are more likely to be clear and open for later fracturing and production operations. To use this method, follow the steps below:

1.

Rig up the workover rig and wireline truck.

2.

Install a jetting nozzle on the end of the tubing. The jetting tool has a seat on which a ball can be used to plug the end of the tubing.

3.

Trip the tubing into the well so the end of the tubing is below the target zone.

4.

Run a gamma ray log down through the tubing and locate the target coal seam(s) by correlating this through-tubing gamma ray log with the openhole gamma ray log.

4-17

Chapter

4

Completing the Well

5.

Lower the gamma ray tool in the tubing to the jetting nozzle and record the depth. Then raise the gamma ray tool up to the target zone and record this depth. Calculate the distance between these two depths and use this value in step 7.

6.

Pull the gamma ray tool out of the tubing.

7.

Place a mark on the outside of the tubing at the top of the slips or the top of the wellhead. Raise the tubing string the distance calculated in step 5 and place another mark on the tubing at the top of the slips or wellhead. This mark indicates the position that the tubing must be in to begin jetting.

8.

Draw a vertical line on the tubing in a place that can be referenced to a stationary point on the rig floor or the wellhead. This line will be observed when reciprocating the pipe to make sure the pipe does not rotate. Preventing the pipe from rotating will ensure the jetting nozzle is properly oriented inside the casing.

9.

Connect the injection lines from the pump truck to the tubing.

10. Circulate water down the tubing, out the bottom opening of the jetting nozzle, and up the annulus to remove any debris that may plug the nozzles.

11. Drop a ball to shut off the bottom opening of the tool. Before running the jetting tool, make sure the ball is the proper size for the seat in the tool. On some tools, the tungsten carbide nozzles may protrude into the throat of the tool, which reduces the I.D. above the ball seat.

12. Circulate with water after the ball is dropped to make sure the ball has seated. When the ball is seated properly, you will notice a pressure increase in the tubing.

13. Begin jetting with water* containing a sand concentration

4-18


from 1 to 1-1/2 lb/gal while reciprocating the pipe up and down across the interval to be slotted. Watch the vertical line marked on the tubing to make sure the pipe does not rotate. Continue jetting and reciprocating until you observe a continuous stream of coal cuttings at the surface. To better monitor returns, set up a screen which will trap the cuttings. You should first observe metal cuttings from the casing at the surface. These cuttings may be so small that you have to use a magnet in the return stream to identify them. When you have cut through the casing, you should observe return water that is black or dark. This color is from the coal fines. After the color of the water changes, you should begin seeing coal cuttings at the surface.

14. Repeat step 13 until you have slotted the entire target interval.

15. After the interval has been slotted, stop pumping sand and clean up the well by circulating clean water until the returns are free of coal cuttings. The water may remain dark if you are cycling the water, but the coal cuttings should stop when the well is cleaned up.

16. When the returns are clean, shut down the pump and reverse the circulation by pumping down the annulus and up the tubing string to remove the ball in the nozzle.

17. After the ball is at the surface, lower the tubing string slowly while reverse circulating to clean out the casing to bottom. Monitor pump pressure closely. Large pieces of coal can plug the small opening at the bottom of the tool and cause a rapid increase in pump pressure.

* You may circulate nitrogen instead of water for slotting. Nitrogen can enhance cutting because it removes cuttings more quickly than water. It also ensures returns to the surface.

4-19

Chapter

4

Completing the Well

Though most coal seams can support the hydrostatic pressure of a column of water, some seams may not. If a seam cannot support a water column, you would not be able to observe the returns at the surface. In such cases, using nitrogen will lower the hydrostatic pressure on the seam and allow you to get returns to the surface. Though nitrogen is more expensive than water, the additional cost may be offset by reduced slotting time.

Special Formation Access Techniques In the Black Warrior Basin, three specialized formation access techniques have been used to complete multiseam wells. These techniques are: • Restricted Access Completion • Limited Entry Completion

• Interseam Completion Restricted Access Completion

A special formation access technique called “restricted access completion” was developed at the Rock Creek project to propagate more effective fractures. Restricted access refers to the technique of perforating only one seam in a group of thin, closely-spaced seams. The primary objective of restricting access to a single seam is to stimulate multiple seams (via the single seam) without the expense of perforating and treating each thin seam individually. The technique also offers the following potential benefits: ❖

Helps prevent high pressures during stimulation

❖

Helps prevent propagation of multiple parallel fractures

❖

Reduces excessive fracture height growth

❖

Reduces migration of sand and coal fines

Tests conducted at the Rock Creek project demonstrated the effectiveness of the restricted access technique. Monitor well data, interference testing, dye tracing, and reservoir modelling all confirmed that fracture treatments initiated at the bottom of the multi-layer Black Creek interval are at least as effective as fracturing stimulations conducted each individual layer of the interval. Figure 4-6 illustrates the fracture communication created in the Black Creek Coal Group by the restricted access completion technique.

4-20


Figure 4-6 Fracture Communication Created by the Restricted Access Completion Technique

The research from the Rock Creek project showed that restricted access completions are effective in a closely-spaced group of coal seams if: ❖

There are no barriers to fracture height growth between the coal seams (i.e., the in-situ stresses of the formations between the seams are not significantly higher than the stress in the coal.)

❖

Stress profiles yield vertical rather than horizontal fractures

❖

Barriers to fracture height growth exist above and below the bottom coal seam

4-21

Chapter

4

Completing the Well

Limited Entry Completion

The limited entry completion method allows you to simultaneously stimulate a group of coal seams in a well instead of stimulating them separately, which requires downhole equipment and sand plugs for isolation. You can use the limited entry method only in perforated cased hole completions. Figure 4-7 shows a typical limited entry multiple-zone completion.

Figure 4-7 Limited Entry Multiple-Zone Completion

You can use the limited entry technique to hydraulically fracture several zones with different rock properties and in-situ stresses. You control stimulation treatments that require different initiation and propagation pressures by the number and size of perforations

4-22


you place across each zone. Adjusting the number and size of perforations at each zone controls the friction pressure through the perforations, which gives you some control over the treating pressure at each zone. The main benefit of a properly designed limited entry completion is the ability to fracture multiple seams with one treatment. To be successful, a limited entry completion must be designed to provide sufficient rate into each seam to adequately widen and extend the fracture. The ability to widen and extend the fracture is a function of the mechanical properties (Young’s Modulus and Poisson’s Ratio) of the formations. To properly design a limited entry completion, you must analyze the mechanical properties of each coal seam and its adjacent formations and account for the differing properties of each zone in the design. A design with perforations based solely on the thickness of the coal seam will likely not be an optimum design. An improperly designed limited entry completion could cause the problems listed below: ❖

Propagation of a fracture at each set of perforations may result in a shorter fracture length and a greater fracture height than desired

❖

Inadequate injection rates into each set of perforations which could cause poor proppant transport, excessive fluid leakoff, and potential bridging in the fracture because of insufficient fracture width

The limited entry completion will likely be most successful when used to fracture multiple coal seams in the same coal group where there are confining barriers between the seams to be fractured. (A confining barrier is a zone that has a higher stress than the zone to be fractured and is thick enough to restrict the height growth of the induced fracture.) If the seams do not have confining barriers between them, a restricted access completion may work more effectively than a limited access completion. The restricted access completion is discussed in the next section. The limited entry completion has not been as successful for fracturing multiple coal groups as it has for fracturing multiple seams within one

4-23

Chapter

4

Completing the Well

coal group. This variation in performance might be due in part to the degree of difference in the mechanical properties of the formations between the coal groups. Interseam Completions

This completion technique involves perforating through casing into rock partings above, below, or between coal seams rather than directly into the seams. Interseam completions have been attempted in the Black Warrior Basin to complete coal zones for which conventional fracture stimulation pressures were excessive. In the basin, unusually high treating pressures are sometimes encountered while attempting to fracture coal seams. In some cases, treating pressures may reach the safe limit for the casing before the operator has established any substantial injection rate. At the Rock Creek project, two separate coal groups in Well P5 were completed using the interseam technique. Though high treating pressures have not presented problems at Rock Creek, the interseam technique was used to assess its effectiveness. Despite having no coal directly connected to the wellbore, Well P5 became one of the highest sustained gas producers in the field following its interseam completion. In addition, Well P5 required no pump repairs for 2 1/2 years. (On average, wells in the Black Warrior Basin require pump work 24 times a year). The results of this one test certainly cannot be considered conclusive; however, they do indicate that interseam completion may be effective for some wells. Figure 4-8 shows the lithology and location of perforations for the Well P5 interseam completion. The decision to complete wells with the interseam technique should be based on a thorough understanding of the in-situ stresses of the coal seams and surrounding strata. Though the usefulness of the interseam completion technique requires further investigation, the technique may offer the advantages listed below:

4-24

❖

High treatment pressures may be avoided

❖

Several target seams may be connected with a single treatment


❖

A propped fracture initiated in interseam strata may inhibit plugging by migrating coal fines and proppant during production

Figure 4-8 Lithology of the Well P5 Interseam Completion

4-25

Chapter

4

Completing the Well

Selecting a Formation Access Method To determine the most effective formation access technique to use, you must consider how the technique will affect your efforts to characterize the reservoir, fracture the coal seams, and produce the well. This section explains these considerations.

Access for Reservoir Characterization In wells where it is important to determine permeability, reservoir pressure, or stimulation pressure, you should use the slotting technique. Because slotting yields a larger access area, it can provide more accurate reservoir pressure measurements. To provide for accurate measurement of reservoir pressures, it is recommended to perform slotting in all pilot wells and in 10-20% of all development wells. In the Black Warrior Basin, permeabilities derived from pressure transient tests have been very erratic and often cannot be correlated with production rates. The inconsistency of the permeability values could have been caused by insufficient access to the formation during these tests.

Access for Hydraulic Fracturing During fracturing stimulation, you must try to minimize the amount of destruction to the coalbed. Because of the friable nature of coal, the fracture slurry can severely abrade the coal. This abrasion may cause the fracture fluid to prematurely load with solids, which can lead to “tip plugging” or premature “bank filling.” (For more information on these problems, refer to Chapter 5.) By selecting the correct type of access and location of access, you can reduce coal destruction and its associated problems. In the Black Warrior Basin, experience has shown that the most effective access for fracturing is obtained by perforating the casing with a casing gun having a charge size between 16 and 23 grams. This charge will create a hole size of approximately 0.37 to 0.41 inch and a depth of penetration from 11 to 20 inches.

Access for Production of the Well During production of a well, formation access must provide a minimal pressure drop between the wellbore and the target formation.

4-26

Selecting Production Tubing

The access also must be able to maintain this low pressure differential for the life of the well (often 10 to 20 years.)

❈ Important You should not perforate or slot the casing until just before you fracture the well or place it on production. In some areas, leaving a coal seam exposed for an extended time without producing it may result in higher than expected treating pressures.

Selecting Production Tubing Selecting the proper tubing string helps ensure the well is capable of producing the water rates necessary to effectively de-water the reservoir and maximize gas production. When selecting a tubing string, consider the guidelines below:

■

Select tubing size based on the estimated maximum water rate to be produced, the type and size of pump you will use, and the formation pressures expected. Most operators in the Black Warrior Basin use 2-3/8 inch tubing for shallow wells (2000 ft or less) and 2-7/8 inch tubing for deeper wells and/or wells expected to produce high rates of water.

■

When ordering the tubing string, order enough tubing so you can set the pump below the lowermost coal seam. Consider also having tubing on location to wash out the well to bottom if necessary. Pup joints usually are not necessary unless you need to set the pump at a precise depth. For example, if there is less than 30 ft between the lowermost coal seam and the bottom of the hole, you may use pup joints to place the pump below the perforations without setting the tubing on bottom.

Working Over Wells Any work on a well (after drilling) that requires a rig can be generally classified as one of the three operations listed below:

Completion - the operations necessary to prepare a well for production. Completions are usually performed after casing has

4-27

Chapter

4

Completing the Well

been set. Completion operations can include running cement bond evaluation tools, perforating or slotting, stimulating the reservoir, and installing artificial lift equipment.

Workover - remedial operations on a well which has produced previously. These operations may include repairing primary cement jobs, changing or adding perforated intervals, cleaning out the wellbore, repairing casing failures, etc.

Pulling Job - the operations necessary to retrieve a downhole pump and/or sucker rod string for replacement or repair. If a tubing-retrievable pump is used, you must pull the tubing string. However, if an insert pump is used, you may retrieve the pump by pulling the rods. You can retrieve the rotor from a progressing cavity (PC) pump by pulling the rods, but to retrieve the stator from a PC pump, you must pull the tubing string.

Because of the marginal economics of most coalbed methane wells, you must perform workovers prudently. For example, some operators work over a well only after its production has declined significantly. They find it more economical to defer workovers as long as possible and to continue producing gas at a lower rate. Of course, this practice will vary from well to well depending on the difference between the cost of the workover and the revenue from lost gas sales. To minimize workover costs, you should plan the workover carefully. The guidelines below will help ensure an economical workover:

4-28

■

Learn as much as you can about your well and offset wells so you can determine the type of equipment needed to do the job safely and effectively.

■

Make sure you perform only operations that are essential.

■

Evaluate several different options for performing a job. The most expensive option is not necessarily the most effective.

Working Over Wells

■

Bid out as much of the work as practical to get the best price. Investigate the reputation and quality of previous work performed by unknown contractors. The lowest price bid may not be a bargain if the work is unsatisfactory.

■

Schedule all equipment to be on location when needed to avoid downtime waiting on equipment and to avoid standby costs if equipment arrives too early.

❈ Important Though economics requires prudent spending on workover operations, you should not jeopardize the safety of workers by eliminating or reducing necessary safety equipment.

Equipment for Workovers and Completions The equipment most commonly used for coalbed methane workovers and completions is described below:

Packers Operators normally use compression or tension packers for stimulation treatments, for testing zones and for squeeze cementing. Compression packers are used for deeper applications because they require sufficient tubing weight above them to set. Usually, the minimum required setting weight is 4,000 - 5,000 lbs. When using 2-3/8 inch, 4.7 lb/ft production tubing, the minimum depth for setting a compression packer is approximately 850 feet. For shallower depths, you should use a tension packer.

Retrievable Bridge Plugs Retrievable bridge plugs are normally used to isolate zones for testing or for production. Retrievable bridge plugs can be tubing set/tubing retrievable or wireline set/tubing retrievable. The tubing set/tubing retrievable bridge plugs are set and retrieved in much the same way as retrievable packers. If you use a retrievable bridge plug in combination with a retrievable packer, make sure the direction of rotation required to set the bridge plug and packer are not the same. If the rotations are the same, the packer and bridge plug will both set.

4-29

Chapter

4

Completing the Well

Gamma Ray Log Before perforating a zone, you must run a cased hole gamma ray log to correlate depths with the open hole gamma ray log. Because perforation intervals are usually selected from the open hole gamma ray, you should correlate the cased hole log as precisely as possible.

Perforating Guns Conventional casing perforating guns are normally used to perforate coalbed methane wells. Before running a perforating gun in the wellbore, make sure the correct number of charges is loaded. Also, make sure length of the charges from one end to the other is equal the desired perforated interval. You should also note the distance from the collar locator tool to the top shot so you position the gun at the correct depth before firing. Keep in mind that you (not the wireline operator) are responsible for ensuring that the perforations are shot in the right location. After firing the gun and pulling it out of the hole, check to see that all shots fired.

Underreamer An underreamer is a tool which may be run through casing to enlarge an openhole section below the casing. The tool is equipped with cutter arms which are normally held within the tool body by a coil spring. When the tool is in the openhole below the casing, the cutter arms may be extended by applying pump pressure through the tubing string. In medium or soft formations, most underreamers can enlarge a hole up to twice the diameter of the tool. The typical tool size for 5-1/2 inch casing is 4-1/2 inches. This size tool can enlarge a hole up to 9 inches.

Zone Isolation Packer The zone isolation packer (ZIP) is a modified surface inflatable packer developed by Gas Research Institute (GRI) at the Rock Creek project. By installing the ZIP tool in the tubing string between an upper and lower coal seam, the ZIP can be inflated to effectively isolate the upper zone’s gas production from the lower zone. Gas production from the upper seam can then be measured until the water level rises above the perforations. Because the ZIP tool has a full opening bore, it will not restrict flow rates.

4-30

Working Over Wells

The ZIP tool is inflated by nitrogen through a 1/4 inch stainless steel line strapped to the outside of the tubing string. A ZIP tool is also available with a “pass-through,” which enables you to run an inflation line through the tool to another ZIP installed below it. For more information on using the ZIP tool to measure production in multiple-seam wells, refer to Chapter 9. ❖

❖

❖

4-31

Chapter

4

Completing the Well


Lambert, S.W.,“Comparison of Open Hole, Slotting, and Perforation Completion Methods for Multiseam Coalbed Gas Wells,” Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (April 17-20).

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).

Schraufnagel, R.A., J.L. Saulsberry, and S.W. Lambert, “Gas Production from Multiple Completion Wells at Rock Creek,” Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (April 17-20).

Schraufnagel, R.A., S.D. Spafford, and J.L. Saulsberry, “Multiple Seam Completion and Production Experience at Rock Creek,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (May 13-17).

Spafford, S. D., “Stimulating Multiple Coal Seams at Rock Creek With Access Restricted to a Single Seam,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (May 13-17).

4-32

5

Fracturing Coal Seams

T

hough most coals are naturally fractured, you normally need to hydraulically fracture coal seams to produce economic gas flow rates. In the reservoir, methane gas is adsorbed onto the surface of the coal. After the reservoir pressure is lowered and the gas desorbs from the coal, it flows through the natural fractures in the coal. For gas to flow to the wellbore at economical rates, effective communication must be established between the natural coal fractures or cleats and the wellbore. The most effective way to create this communication is by hydraulically fracturing the coal seam. In fracturing, large volumes of fluid and sand are pumped at high pressure down the wellbore. The fluid opens a crack in the coal, and after the fluid is removed, the sand remains in place to keep the new channel open. The resulting proppant-filled fracture provides a flow path into the wellbore for water and gas. When successful, hydraulic fracturing can greatly increase methane production from coal seams. Though much conventional fracturing technology can be applied to coalbed fracturing, many techniques have been developed specifically for coalbed methane wells. This chapter will explain these techniques and help you in:

• Performing a Minifracture Test • Planning a Fracture Treatment Design • Preparing for a Fracture Treatment • Performing a Fracture Treatment • Evaluating a Fracture Treatment

Chapter

5


Performing a Minifracture Test A minifracture, or injection-leakoff test, is a series of pump-in tests you can perform before designing a fracture treatment. These tests can help you obtain important data for planning a fracture stimulation. The minifracture test can improve the design and implementation of a hydraulic fracturing treatment by helping you to: ❖

Estimate fracture gradient

❖

Estimate fluid leakoff

❖

Estimate fracture closure pressure

❖

Recognize high fracture pressures

Table 5-1 shows three types of minifracture tests and the data you can obtain from them.

Table 5-1 Minifracture Tests

5-2

Type of Minifracture

Data Obtained

Step Rate Test

Fracture Pressure*

Pump-In/Flowback or Pump-In/Shut-In Test

Fracture Closure Pressure**

Minifracture Pressure Decline Test

Fluid Loss Efficiency

Pump-In/Shut-In Test (Longer Duration)

Fluid Loss Coefficient, Fracture Width, Length, Closure Time

Performing a Minifracture Test

*

The fracture pressure for a coal is the pressure required to create a fracture. It equals the fracture gradient multiplied by the depth of the coal.

** The fracture closure pressure is the pressure at which the stresses in the coal cause the induced fracture to close onto the proppant. The fracture closure pressure is less than the fracture pressure.

Guidelines for Performing a Minifracture Test This guide does not cover design or analysis of minifracture tests; however, you can find information on these topics in Additional Resources at the end of this chapter. Based on experience in the Black Warrior Basin, the general guidelines below will help you in performing a minifracture test:

■

Use pump-in/shut-in tests instead of pump-in/flowback tests. Traditionally, operators have used pump-in/flowback tests to determine the fracture closure pressure in low-permeability (very low fluid loss) reservoirs. However, pump-in/shut-in tests are more effective for coalbed reservoirs, because they have a high fluid loss. Pump-in/shut-in tests provide useful pressure data, called the “estimated closure pressure” (ECP). This data occurs very early in the pressure decline following a pump-in/shut-in test and, therefore, would be lost in a pump-in/flowback test.

■

Instruct the service company pumping the minifracture to use digital pressure recording equipment to record pressure values every few seconds. This step is necessary to obtain sufficient data for estimating the “effective closure pressure” (ECP) that best relates to the fluid loss rate which occurred during the injection period. The ECP, if applicable, will likely occur within the first few minutes of the test. Therefore, you will need sufficient data points for accurate analysis.

5-3

Chapter

5


■

Use the same fracture fluid and injection rate that you plan to use for the stimulation treatment. Because fluid loss in coal seams is essentially limited to the cleat and fracture system, the fluid loss rate is not controlled by a filter cake on the fracture face. Fluid viscosity plays an important role in fluid loss: higher viscosity fluids tend to exhibit lower fluid loss. In conventional (porous rock) reservoirs, small changes in bottomhole treating pressure (BHTP) do not significantly alter fluid loss rate. However, the cleat system in coals may tend to “open” more and allow higher fluid loss when the BHTP increases by even a small percentage.

Planning a Fracture Treatment Design Designing an effective fracture treatment is a complex process that requires thoughtful consideration of formation properties, wellbore design, and fracturing methods and materials. Because the requirements of each fracture job are different, the combination of methods and materials you select can determine the success of the job. This guide does not provide specific procedures for designing a fracture treatment. For assistance in designing a treatment, you may consult a variety of resources. You can contact a service company or a consulting firm with experience in fracturing coalbed methane wells. You might also talk with other operators in the area to learn what types of fracture designs have proven successful for them. In addition, you can utilize one of the many commercially available fracture simulation models to test various treatment designs. Though you can design a fracture treatment using hand calculations and graphical methods, using fracture design software will enable you to quickly evaluate the effects of more design variables and conditions. The primary information you will need to consider in designing a fracture treatment are shown in Table 5-2 and are discussed below:

5-4

Planning a Fracture Treatment Design

Table 5-2 Information Needed for Designing a Fracture Treatment Information

Source

Thickness of the Coal

Wireline Logs, Core Analysis

Permeability of the Coal

Well Tests, Core Tests

Temperature of the Coal

Wireline Logs

Mechanical Properties of the Coal and Adjacent Formations

Minifracture Tests, Core Tests

Fracturing Fluid Leakoff

Minifracture Tests

Fracture Gradient of the Coal

Minifracture Tests

Fracture Length and Height

Length: Fracture Design Software Height: Minifracture Tests, Wireline Logs

Location, Number, and Size of Perforations

Operator’s Completion Design

Mechanical Configuration of the Wellbore

Operator’s Completion Design

Fracturing Fluids

Service Companies

Fracturing Fluid Additives

Service Companies

Fracturing Proppants

Service Companies

Pumping Schedule

Fracture Design Software

5-5

Chapter

5


Thickness of the Coal Coal thickness will affect the number and type of perforations you use across a coal group. For example, if a coal group is relatively thick and composed of many thin stringers, limited entry perforation may be the most effective method for accessing the formation. However, if the interval is a thin coal group, then single zone entry may be more successful. For information on various perforating techniques, refer to Accessing the Formation in Chapter 4. The thickness of the coal also will affect the economics of the fracture design. Because coal thickness affects gas recovery, it is a factor in determining the fracture length needed to make make a coalbed methane well economical. In general, the greater the fracture length needed, the more costly will be the fracture treatment. To select a fracture length, you can run sensitivity evaluations to compare the incremental cost of greater fracture length against the value of expected incremental gas recovery from the fracture. For information on determining coal thickness from wireline logs, refer to Chapter 3.

Permeability of the Coal For conventional wells, you can use the formation permeability to estimate increased production from a fracture treatment. However, for coalbed methane wells, permeability is only useful for estimating the volume of fluid leakoff into the formation during the fracture treatment. For information on determining the permeability of coal, refer to Chapter 9.

Temperature of the Coal Because most coal seams are relatively shallow, the formation temperature does not cause premature degradation of the fracturing fluid. However, you must consider the relatively low temperature when designing the schedule for gel breakers because the temperature does not provide much help in breaking the gel. The circulating bottomhole temperature is usually recorded on openhole logs. Make sure you adjust the recorded temperature to account for the shut-in time between circulating and conditioning the hole and logging it. The bottomhole temperature from log correlations is often underestimated.

5-6


Mechanical Properties of the Coal and Adjacent Formations The rock properties, Young’s Modulus and Poisson’s Ratio, are needed for fracture propagation calculations in fracture simulators. The fracture gradient of the formation is a function of these two properties. For information on estimating mechanical rock properties, refer to Chapter 3. The vertical height of the fracture in a coalbed methane well often will be much greater than the thickness of the coal. The height to which a fracture will grow depends directly on the stresses in the zones above and below the coal seam. Thick, more highly stressed zones will tend to confine the fracture; thinner, less stressed zones will promote fracture growth. When designing a fracture treatment, it is helpful to estimate fracture height. You can estimate fracture height by performing a minifracture test on zones adjacent to the coal seam. For an explanation of minifracture tests, refer to Performing a Minifracture Test at the beginning of this chapter.

Fracturing Fluid Leakoff In many coalbed methane fracturing treatments, the fracturing fluid leaks off into the coal seam simply because the adjacent formations are too impermeable to accept fluid. The rate of fracturing fluid leakoff during a fracture treatment is a critical factor in fracture design. The rate of leakoff determines the fracturing fluid efficiency, which is the ratio of the volume of the induced fracture to the volume treatment pumped. If the fluid efficiency of a fracturing treatment is underestimated, the treatment may screenout prematurely. In addition, because fluid leakoff affects fracture closure time, it may also affect distribution of proppant within the fracture. The volume of fluid leakoff depends on the viscosity and wall building ability of the fracturing fluid, the viscosity and compressibility of the formation fluid, and the relative permeability of the fluids. Though the properties of the fracturing fluids and formation fluids usually can be estimated fairly accurately, the relative permeability effects are more difficult to determine. Coal permeability is a function of the natural fractures in the coal, and estimating fluid

5-7

Chapter

5


loss for a naturally fractured formation is more difficult than for a non-fractured reservoir. To better define fluid loss characteristics for coals, Amoco conducted a field study in the Oak Grove Field (Black Warrior Basin). The study concluded that fluid efficiencies obtained from minifracture tests are not always accurate. This inaccuracy stems not only from the natural fractures in coal, but also from the pressure dependent nature of coal permeability, and from the tendency of proppants to bridge because of width constrictions in the fracture. For more information on the Amoco field study, see the paper in Additional Resources at the end of this chapter.

Fracture Gradient of the Coal The fracture gradient of a coal seam or other formation can be determined from minifracture tests, discussed at the beginning of this chapter. You can estimate the fracture gradient by first measuring an instantaneous shut in pressure (ISIP). An ISIP is simply the pumping pressure required to fracture the formation minus the friction pressure that must be overcome during pumping. Figure 5-1 shows an ISIP.

Figure 5-1 Instantaneous Shut In Pressure (ISIP)

5-8


To obtain an ISIP, follow these simple steps: 1 . Inject fluids at a rate sufficient to fracture the formation . 2.

After establishing this rate, shut the pumps down quickly.

3.

Record the surface pumping pressure the instant the pumps are shut down. Figure 5-1 shows an example of an ISIP recorded during a fracture treatment.

After obtaining an ISIP, you can easily calculate the fracture gradient for the formation using the equation below:

Fracture Gradient = ISIP + Ph , psi/ft Dc where: ISIP = Instantaneous shut in pressure, psi Ph = Hydrostatic pressure of fracturing fluid in the wellbore, psi Dc = Depth of the coal, ft

After you have determined the fracture gradient, you can estimate the bottomhole treating pressure and the surface treating pressure using the equations below: BHTP = FG x Dc, psi SIP = BHTP - (Ph + Pp + Pt) , psi

where: BHTP = Bottomhole treating pressure, psi FG = Fracture gradient, psi/ft

5-9

Chapter

5


Dc = Depth of the coal, ft SIP = Surface injection pressure, psi Ph = Hydrostatic pressure of fracturing fluid in the tubing, psi Pp = Pressure drop across the perforations, psi Pt = Pressure drop in the tubulars, psi

Fracture Length and Height Two of the most important factors in designing a fracture treatment are the desired fracture length and the expected maximum fracture height. The optimum fracture length depends on the permeability and gas content of the coal. To determine optimum fracture length, you can run a fracture model that simulates gas recovery over a time period for various fracture lengths at a given permeability and gas content. The optimum fracture length is the one that beyond which little incremental gas recovery is obtained. The height to which a fracture will grow depends on the mechanical properties of the formations adjacent to the coal, as discussed above in Mechanical Properties of the Coal and Adjacent Formations. If fracture height is estimated incorrectly, then the fracture length will be different than calculated in the design. Because the mechanical properties of the coal and adjacent formations are not always available or are not estimated accurately, fracture height is often estimated incorrectly. If the actual fracture height is less than estimated in the design, the fracture may be longer than expected. However, if the actual fracture height is greater than estimated in the design, the fracture will be shorter than expected. Unfortunately, the latter case occurs much more frequently than the former.

Location, Number, and Size of Perforations It is important to know the location of perforations so you can accurately determine fluid displacement volumes and be able to divert fracture fluids if ball sealers are used in the treatment. The number of perforations used will affect the injection rate. If you use a very large number of perforations, the injection rate may be so low that a moderate to low viscosity fluid may be incapable of carrying proppant into the perforation tunnels. Conversely, using too few perforations may restrict overall injectivity.

5-10


If you are designing a limited entry fracture treatment, you should use enough perforations so that each perforation has a pressure drop of only a few hundred psi. A common rule of thumb for a limited entry treatment is to design for an injection rate of 1/4 to 1 BPM/perforation. For an explanation of the limited entry technique, refer to Accessing the Formation in Chapter 4. The size of the perforation could affect the selection of the proppant size. Each perforation must be large enough relative to the maximum proppant diameter to prevent bridging across the perforation tunnel. Proppant bridging usually is not a problem in coalbed methane wells because most wells are perforated with casing guns that provide a perforation diameter of 0.37 - 0.41 inches. A perforation diameter of 0.41 inch would not limit the concentration of 20/40 or 16/30 proppant to below the maximum concentrations (4-6 lb/gal) that are normally pumped in coalbed methane wells.

❈ Important The discharge coefficient is a factor used to calculate frictional pressure drop of fluid passing through the perforations. Perforations have an initial discharge coefficient of about 0.6. After you begin pumping proppant, the sand erodes the perforations and the discharge coefficient usually increases to around 0.95. The higher the discharge coefficient, the lower the pressure differential through the perforations. You should keep this guideline in mind both when designing the treatment and while pumping it.

Mechanical Configuration of the Wellbore An important element in a fracture design is the configuration of the casing and/or tubing strings in the wellbore. Your selection of tubing and casing configuration will control the maximum pumping rate during the job as well as the flexibility to fracture single or multiple coal zones. Operators in the Black Warrior Basin use two general types of wellbore configurations for fracturing: through-casing fracturing and through-tubing fracturing. In almost all cases, through-casing fracturing is the preferred method.

5-11

Chapter

5


Through-Casing Fracturing Most operators in the Black Warrior Basin fracture wells by pumping the treatment directly down the production casing string into the formation. To fracture through-casing, the low pressure casing head is removed and a high pressure frac valve is installed in its place. If the wellbore contains open perforations shallower than the coal to be fractured, you should not fracture through-casing unless you are certain the shallower perforated intervals have a much higher fracture pressure than will be used during the treatment. (Shallower intervals normally have a lower fracture pressure than deeper intervals.) To help prevent fracturing shallow perforated intervals, you can isolate the perforations with a tubing and packer assembly. Through-casing fracturing offers several advantages over the throughtubing method: ❖

Allows pumping higher injection rates

❖

Provides flexibility for fracturing multiple coal seams in a well

❖

Requires less equipment downhole and at the wellhead and is thus operationally simpler

The through-casing method can be used to fracture single or multiple coal zones. Four different through-casing wellbore configurations have been used in the Black Warrior Basin:

• Single Zone • Multiple Zones Using Limited Entry Technique • Multiple Zones Using Plugback Techniques • Multiple Zones Using the Ball and Baffle Technique Each of these applications are illustrated in Figure 5-2 and are explained below.

5-12


Figure 5-2 Wellbore Configurations for Fracturing

Single Zone

The simplest through-casing method involves perforating or slotting a single coal seam and then pumping the fracture treatment down the casing into the seam. The primary wellhead equipment needed for this method is a frac valve. No downhole equipment is required. Figure 5-2 (a) shows a single-zone, through-casing fracture treatment.

Multiple Zone Using Limited Entry Technique

The limited entry technique involves simultaneously fracturing several coal seams (with differing rock properties and in-situ stresses) instead of fracturing individual seams (or groups of

5-13

Chapter

5


seams) separately. Ideally, the propagation pressures and treating rates for each zone are controlled by the number and size of perforations placed across each zone. By adjusting the number and size of perforations, you may be able to control the friction pressure through the perforations, which results in some control over treating pressure into each interval. The limited entry technique has generally proven ineffective in fracturing two or more coal groups (such as the Mary Lee and Pratt or Mary Lee and Black Creek seams). However, the limited entry technique for fracturing seams within the same coal group (such as the Black Creek) is commonly used. Figure 5-2 (b) shows a limited entry fracture treatment. Recent studies at the Rock Creek project have shown that you can successfully stimulate all seams within the same coal group through a single set of perforations in one seam of the group. This technique, called restricted access, was used successfully in the Black Creek coal group at Rock Creek. For more information on the restricted access completion method, refer to Accessing the Formation in Chapter 4.

Multiple Zones Using Plugback Techniques

The most common method used to fracture multiple zones in a well is to perforate and stimulate the lowermost zone first and then successively plug back, perforate and stimulate the shallower zones. Because plugging back allows you to isolate and treat each zone individually, you can control the treatments more effectively than with the limited entry technique. Several methods are used to plug back zones. Most operators in the Black Warrior Basin use sand plugs and/or retrievable bridge plugs to isolate zones for fracturing. Figure 5-2 (c) shows how the middle, or Mary Lee, coal group was isolated from the lower, or Black Creek, coal group using a sand plug, and the upper, or Pratt, coal group was isolated using a retrievable bridge plug. The decision to use a sand plug or a retrievable bridge plug will depend primarily on the distance between the prospective coal zones. A sand plug may be less expensive than a bridge plug. However, if the coal zones are separated by several hundred or more feet, using a retrievable bridge plug may be more practical than placing a large volume of sand and then washing it out of the wellbore.

5-14


Multiple Zones Using the Ball and Baffle Technique

The ball and baffle technique is used to isolate coal seams by installing cast-aluminum baffle plates at pre-selected depths in the casing string when the string is run in the hole. Figure 5-2 (d) shows a baffle frac job performed on Well P3 at the Rock Creek project. To isolate a perforated interval for fracturing, a rubber ball is dropped down the casing. The ball seats in the baffle and thus isolates the interval from treated deeper intervals. By installing baffles with successively larger inside diameters (from the bottom upward), you can effectively isolate single seams or groups of seams so they can be treated individually during the fracture job. The ball and baffle technique offers two significant advantages. First, it saves time because you can fracture the zones in succession without having to trip tools in and out of the hole. Second, it allows you to flow back each fractured interval immediately after the fracture job. Though this technique was used successfully at the Rock Creek project, it is not widely used for coalbed fracturing stimulations in the Black Warrior Basin.

Using a Tubing "Dead String" to Measure Bottomhole Pressure To accurately determine bottomhole pressure during a fracture job, some operators run a tubing “dead string” in the well. This technique can be used with any of the four through-casing techniques described above. However, if you use bridge plugs or the ball and baffle technique, you must pull the tubing between treatments. Figure 5-3 illustrates a tubing dead string assembly run in a well at the Rock Creek project to determine bottomhole pressure during fracturing of the Blue Creek seam. Treatment fluids and proppant are pumped down the casing/tubing annulus. A pressure gauge or recorder installed on top of the tubing at the surface provides accurate surface pressure data free from frictional pressure losses. You can then convert the surface pressure reading to bottomhole treating pressure by using the equation below:

5-15

Chapter

5


BHTP = Pt + Ph where: BHTP = Bottomhole treating pressure Pt = Tubing pressure at surface gauge, psi Ph = Hydrostatic pressure in tubing, psi

Figure 5-3 Tubing "Dead String”

5-16

for Measuring Bottomhole Pressure


When using a tubing dead string, you should place the tubing as close to the coal interval as practical. You must also select a pressure gauge or recorder that has a pressure rating greater than the maximum anticipated injection pressure. To protect the tubing from the abrasion of the sand-laden fluid, a tubing dead string assembly requires several pieces of equipment. This equipment is described below: Blast Joint A blast joint should be installed in the tubing string through the injection spool to prevent the abrasion of the proppant-laden fluid from cutting a hole in the tubing. At the Rock Creek project, a 2-3/8 inch tubing string was used for the dead string. To eliminate the cost for a 2-3/8 inch blast joint, a 2-7/8 inch pup joint was placed over the 2-3/8 inch non-upset tubing. The pup joint was supported on the bottom by a collar on the 2-3/8 inch string and on the top by the BOP rams, as shown in Figure 5-3. Casing Spool A wellhead fixture similar to a casing spool with side outlets allows injection of fracture fluids into the tubing/casing annulus. The treatment is pumped through the side ports in the spool. The spool is installed on the casing or casing head. (You may need a threaded companion flange if the casing is fitted with a threaded nipple and the spool is flanged.) Blowout Preventer (BOP) A pipe ram BOP is installed on top of the casing spool to contain the pressure in the tubing/casing annulus during the fracture job. To provide another pressure seal for additional safety, you may also install a stripper rubber head directly on top of the BOP. Mechanical Tubing Slips Tubing slips are placed above the BOP to support the weight of the tubing.

Through-Tubing Fracturing Coal seams may be fractured with low injection rates. However, to adequately open and widen fractures, fracturing fluids must be pumped at relatively high rates to overcome high fluid leak-off rates. Therefore, fracturing coalbed methane wells through tubing is generally impractical because sufficient injection rates cannot be established.

5-17

Chapter

5


Many through-casing fracture jobs are performed at rates of 25-40 BPM. The same fracturing treatment injected through-tubing would have to be pumped at a lower rate. The actual maximum injection rate will depend on the viscosity of the fluid used. You may be able to slightly increase through-tubing injection rates by adding friction reducers to the fluid. You may justify a through-tubing stimulation in cases where through casing treatments are not possible. For example, if the wellbore contains open perforations above the coal seam to be fractured. Similarly, through-tubing fracturing may be used if prefracture testing indicates that fracturing pressure will exceed the differential burst pressure of the casing at shallow depths.

▲ Caution If you attempt to isolate perforations close to the seam you intend to fracture, you risk fracturing into the isolated perforations. If the isolated perforations break down, proppant could flow through these perforations into the wellbore and stick the packer and pipe.

Fracturing Fluids Selecting proper fracturing fluids is critical to a successful fracturing treatment. These fluids help initiate the fracture in the formation, extend the fracture once it opens, and transport the proppant into the fracture. To select the best fracturing fluid for a well, you should consider these factors:

• Fluid Viscosity • Formation Properties • Frictional Pressure • Fluid Loss Properties • Economics

5-18


Fluid Viscosity

Viscosity may be the most critical factor in selecting a fluid. An effective fluid must not only initiate and extend a fracture, but also carry the proppant deep into the fracture. High viscosity fluids are necessary to develop fracture width and to effectively transport the proppant. A fluid with insufficient viscosity will limit the fracture width and prevent the transport of proppants deep into the fracture. It is also important to select the appropriate breaker and breaker concentration. No matter how good the proppant transport characteristics of the frac fluid, they can be completely negated by using excessive breaker concentrations. When selecting fluids, make sure you obtain viscosity information from the service company for the fluids you are considering using. You will need this information not only when designing the fracture job, but also when monitoring the fluids during the fracture job. Formation Properties

To optimize the fracture treatment and prevent coal damage, the fracturing fluid must be compatible with the formation. In the Black Warrior Basin, guar gum and hydroxypropyl guar (HPG) gel fluids have been used extensively for fracturing. However, recent GRI-sponsored research has indicated that HPG gels and guar could adversely affect the permeability to both water and gas. Experience at Rock Creek has shown that guar and HPG gels can be used successfully, but they may also cause failure. For example, Wells P2 and P7 were both fractured in the Mary Lee formation with HPG gel, but Well P2’s post fracture production rate (190 MCFD) was significantly higher than that of Well P7 (40 MCFD). The poor performance of the P7 treatment was attributed to the failure of the gel to break properly, which reduced permeability. GRI research indicates that the ability of guar-based fluids to break properly is extremely important in determining the success or failure of stimulation treatments. Conversely, research also indicates that a break schedule that is too aggressive may result in a fluid that fails to form a filter cake. A high volume of fluid could then leakoff to the cleat system and significantly impair production potential. Field studies conducted by Amoco also indicate that HPG gel is damaging to coal. Further, Amoco laboratory studies suggest that all polymers (including HEC gels and other chemical additives) can irreversibly damage coals.

5-19

Chapter

5


The GRI and Amoco data suggest that you may reduce the possibility of damaging coal by using a fluid with low damage potential (such as KCl or a KCl substitute) or a fluid that contains a minimal amount of gel and that has a high fluid efficiency (such as foam). Amoco has successfully fractured wells in the Oak Grove Field (Black Warrior Basin) using water as the fracturing fluid. Similarly, GRI has successfully fractured wells at the Rock Creek project using 75 quality foam as the fracturing fluid. The greater fracture lengths that can be achieved with the foam fluid may offset any formation damage that might be caused by the HEC gel used with the foam treatment. Frictional Pressure

Because nearly all coalbed methane wells are fractured through casing, frictional pressure does not usually affect fluid selection. However, if you must fracture a well through tubing, the frictional pressure may be the limiting factor in selecting a fluid. Fluid Loss Properties

Because of the natural cleat system in coals, fluid losses during fracturing could be high. High fluid loss increases the probability of excessive deep damage to the cleat system. Economics

When selecting a fracturing fluid, you must consider the cost of the treatment relative to the results expected from it. For example, if your objective is to create a short fracture that will simply ensure communication between the wellbore and the natural fracture system of the coal, you may not need to use a high viscosity fluid. However, if you have determined that a very long fracture length is needed to generate economical production rates from the well, you should probably use a high viscosity fluid.

Types of Fracturing Fluids In the Black Warrior Basin, operators use only water-based fracturing fluids. There are four types of water-based fluids:

• Nongelled Water • Linear Gel • Crosslinked Gel • Foam

5-20


Nongelled Water

You can pump fresh water, or treated water at high rates to place low concentrations of sand (e.g., less than 1 lb/gal) into fractures. However, if you use a water-based fluid, you will likely place the proppant a relatively short distance from the wellbore. The propped fractures from a water-based stimulation will be short because of the poor transport capacity of water and because the created fractures are close to wellbore.

▲ Caution Make sure that any water used is compatible with the fracturing fluids you plan to pump. Do not use water flowed back from a previous fracture treatment unless it has been properly treated.

Recent research sponsored by GRI has shown that using 2% KCl (potassium chloride) water may help prevent formation damage. You may also consider adding a natural or synthetic friction reducer to the water, allowing you to pump at a higher rate to carry the proppant further out from the wellbore. Friction reducers may also allow you to use lower horsepower pumps. Before using a friction reducer, make sure it is compatible with the fracturing fluids you plan to use.

❈ Important Sand-water fracture treatments are relatively inexpensive, but they also require recovering large volumes of water after the treatment.

Linear Gel Fluids

You can pump hydroxyethylcellulose (HEC) gel fluids to place sand concentrations of 1 to 3 lb/gal a moderate distance from the wellbore. Because these gelling agents gel quickly, you can use them in continuous, semi-continuous, or batch processes. Linear gels cannot hold proppants in perfect suspension. As the shear rate decreases in the fracture, the sand will settle. However,

5-21

Chapter

5


you can obtain greater propped fracture length with a linear gel fluid than with a water-based system. Linear gels also help reduce friction and control fluid loss. To facilitate recovery of the gel fluid after the treatment, the gel is designed to revert or “break” to the viscosity of water. This breakdown allows the stimulation fluid to drain from the fracture into the wellbore. Each service company uses different chemical systems to break gel fluids at various formation temperatures. Because the chemistry of these gel systems is complex, a carefully designed gel system is critical to the success of the fracture job. Linear gels clean up with breakers and produced load water and can leave a highly conductive propped bed. The cost of a linear gel fracture is higher than for a water-based fracture treatment. However, the longer propped length usually created by a linear gel should provide greater production than a water fracture treatment of the same size. Typically, the higher cost of a gel fracture is offset by higher production rates.

❈ Important For several years, operators in the Black Warrior Basin commonly used hydroxypropyl guar (HPG) fluids for fracturing. However, recent research sponsored by GRI indicates that hydroxypropyl guar (HPG) fluids may adversely affect the permeability to both gas and water.

Crosslinked Gel Fluids

Crosslinked gels were developed to provide a water-based fracturing fluid with a higher viscosity than linear gels. This higher viscosity can create wider, better propped, and more conductive fractures than linear gels. The viscosity of these fluids is increased by adding special crosslinking systems and stabilizers. Crosslinked gels can carry proppants in excess of 10 lbs/gal in suspension. As with linear gels, you can tailor crosslinked gels to break to a low viscosity fluid after fracture closure. However, crosslinked gels are more difficult to break than linear gels. To ensure recovery of the fracturing fluid and to reduce the potential for formation damage after the treatment, you should add sufficient breaker to the gel.

5-22


Foam Fluids

Foam fluids are created by dispersing gas, usually nitrogen, in a liquid. To initiate the dispersion, a surfactant is normally used as a foaming agent. Because foams have high viscosity and low fluid leakoff properties, they can carry proppant further out into the formation than gel fracturing fluids. Foam quality is the volumetric ratio of the gas to the total volume of foam at downhole conditions. A 75 quality foam contains 75% gas by volume at downhole temperature and pressure. Foams used for fracturing typically range from 65-85 quality. Foam fracturing treatments at the Rock Creek project have used 75 quality foam. Higher quality foam provides greater viscosity, but also may increase pump pressure and limit maximum sand concentration. Foams with a quality less than 52 have a much lower viscosity than higher quality foams and thus do not function as effectively as high viscosity fluids. Foams with a quality less than 52 are usually unstable. Foams have several advantages over non-foam treatments: ❖

Low liquid content of foam results in a lower hydrostatic head, which enhances well cleanup.

❖

Excellent fluid loss control eliminates the need for fluid loss additives, which reduces impairment of fracture conductivity.

❖

Excellent capability to support proppants, which results in more uniform distribution of proppant throughout the fracture.

❖

Energy from the gas in the foam helps to recover treating fluids from the reservoir.

❖

Formations that have been de-watered can be treated without fear of re-saturating the formation.

5-23

Chapter

5


❈ Important Though foams offer the highest potential for minimizing damage to the coal, you still should carefully consider the polymer used for the aqueous phase as well as the foaming surfactant. Select a polymer and foamer that is least damaging to the coal. Many foamers will not work with coal because they adsorb onto the coal. Such foamers may reduce formation permeability. Select a foamer that will ensure 100% gas entrainment and maximum viscosity and proppant transport characteristics.

Fracturing Fluid Additives In addition to selecting the proper fracturing fluid, you should also carefully consider the numerous fluid additives available to maintain and enhance the properties of the fracturing fluid. Before using an additive, make sure you fully understand its purpose and limitations as well as its compatibility with other fracturing fluids and with formation fluids. Check with service company representatives for complete information on any additives you use. Fluid additives are available to perform a wide range of functions. Some of the additives commonly used in fracturing coalbed methane wells are described below: Biocides

Biocides eliminate surface degradation of the polymers in the fluid tanks and stop the growth of anaerobic bacteria in the formation. Breakers

Breakers enable viscous fracturing fluids to be controllably degraded to a thin, low viscosity fluid. The two types of breaker systems currently used are enzymes and catalyzed oxidizers. It is very important to select the appropriate breaker and breaker concentration. No matter how good the proppant transport characteristics of the fracturing fluid, they can be completely negated by using excessive breaker concentrations. Buffers

Buffers control the pH of the fracturing fluid for the crosslinker and breaker systems and also accelerate or slow down the hydration of certain polymers. Surfactants

Surfactants lower the surface tension of water in the fracturing

5-24


fluid and reduce capillary pressure. They may also act as a demulsifier. Clay Stabilizers

Clay stabilizers prevent excessive swelling of clays and reduce the migration of fines. Commonly used clay stabilizers include potassium chloride, calcium chloride, ammonium chloride, and salt substitutes. Because of the problems associated with disposing high chloride waters, a number of surface active quaternary amine compounds are now available from the service companies. However, not all of these materials are compatible with coal. They may interact adversely with the breakers used in low temperature coalbed treatments. Therefore, before using these types of additives, you should confirm their compatibility with the fracturing fluid and with the formation. Foam Stabilizers

Foam stabilizers help maintain the properties of foam fluids. Most foam stabilizers are polymers. Foams without stabilizers generally have a half-life of 3-4 minutes. By adding stabilizers, you can increase the half-life of a foam to 20-30 minutes. Friction Reducers

Friction reducers suppress fluid turbulence and thus reduce the frictional pressure associated with high injection rates. Friction reducers may prove especially useful for improving injectivity in through-tubing fracture treatments, should they be necessary. Diverting Agents

Diverting agents divert the flow of fracturing fluids to zones above or below the zone that was initially treated by plugging off perforations or the formation. Diverting agents are usually soluble in the formation fluid.

Fracturing Proppants When fracturing a coalbed, the primary purpose of including proppant (sand) in the fluid is to provide mechanical support to hold open the hydraulically created fracture in the reservoir rock. Essentially all major producers agree that commercially successful coalbed completions depend on long, well-propped fractures. Long term success from fracturing without using proppant has been minimal. In many cases, wells without propped fractures demon-

5-25

Chapter

5


strate good early production rates, but decline dramatically as they begin to produce. A few coalbed methane producers believe that the primary function of the proppant is merely to fill the fracture and prevent or minimize the production of coal chips and fines that would otherwise plug any empty fracture voids caused by incomplete closure of the fractures. Some believe that coal seams will “self prop” because of spalling and erosion of the coal during the fracturing treatment. Other producers believe that larger size sands, such as a 12/20 size, serve mainly as a scouring agent, removing sufficient coal from the fracture faces so that the fracture will not close completely. The most common proppant used in coalbed methane wells is sand. Consider the following guidelines when choosing a proppant for a fracture treatment: ■

Select a proppant for a fracturing treatment based on the anticipated closure stress in the coal seam, the cost of the proppant, and its availability in your area. Because many of the coal seams currently being completed are very shallow, the anticipated closure stress on the proppant is usually lower than for a typical sandstone gas well. Because of these lower values of closure stress, you may be able to use fracture sands often considered unacceptable for conventional completions because of their poor crush resistance.

■

Sieve a sample of the fracture sand to make sure the service company has provided the correct size. After sands are processed, they may contain a large amount of fines.

Preventing Proppant Flowback When you hydraulically fracture a coalbed well, you may encounter problems with flowback of proppant into the wellbore after the treatment. Proppant flowback can cause three problems:

5-26

❖

Fill-up of the wellbore

❖

Damage to the pump

❖

Production of coal


Proppant flowback usually occurs during the early cleanup and dewatering stages. You can usually reduce flowback of proppant by using an effective method of flowing the well back after the fracture treatment. For more information on methods to prevent flowback of proppant, refer to Pumping and Flowback Procedures later in this chapter. If you observe a history of proppant flowback in a field, you may incorporate a curable resin-coated proppant in the final stage of the fracturing treatment.. If you use a resin-coated proppant, make sure the resin will set under formation temperature and stress conditions and will not interfere with fluid clean-up properties.

Pumping Schedule After all of the design considerations previously discussed have been incorporated into the fracture design, the pumping schedule can be prepared. The pumping schedule is a table showing the volumes, concentrations, and rates for pumping the fracturing fluids. Because optimizing the pumping schedule is usually an iterative process, it is best accomplished by using fracture design software. A detailed explanation of how to design a pumping schedule is beyond the scope of this guide. For assistance in designing a schedule, you may consult a variety of resources. For example, you can contact a service company or a consulting firm with experience in fracturing coalbed methane wells. All major fracturing service companies use computer models to design fracture treatments. You may also talk with other operators in the area to learn what types of fracture designs have proven successful for them. In addition, you can utilize one of the many commercially available fracture simulation models to test various treatment designs. The type and size of fracture treatment you use will depend on the properties of the coal reservoir and your particular objectives for the treatment. To give you a sense of the type of fracture treatments typically used in the Black Warrior Basin, a gel fracture design and a foamed fracture design used successfully at the Rock Creek project are shown in Tables 5-3 and 5-4. The input data and the selected pumping schedule are shown for each of the treatment designs.

5-27

Chapter

5


Table 5-3 Pumping Schedule for a Gel Fracture Treatment on Well P2 at the Rock Creek Project

Coal seam:

Mary Lee/Blue Creek

Net thickness:

8.7 ft

Perforated interval:

2 vertical slots at 1028’ - 1036’ Cross-linked HPG gel

Selected fracturing fluid: Selected proppant:

12/20 sand

Injection tubular I.D.: Pumping rate:

4.892”

20 BPM

Total Fluid Volume:

3,000 gal fresh water 90,000 gal cross-linked gel

Total Proppant Volume:

Additives:

11,000 lbs 20/40 mesh sand 126,000 lbs 12/20 mesh sand

Biocide and breaker Pumping Schedule

5-28

Stage

Fluid Type

1 (PrePad)

Fresh water

2 (Pad)

Fluid Volume (gals)

Proppant Concentration (lb/gal)

3,000

----

Cross-linked gel

27,000

----

3

Cross-linked gel

11,000

1.0

4

Cross-linked gel

2,000

1.0

5

Cross-linked gel

20,000

2.0

6

Cross-linked gel

28,000

3.0

7 (Flush)

Cross-linked gel

2,000

----


Table 5-4 Pumping Schedule for a Foam Fracture Treatment on Well P3 at the Rock Creek Project

Coal seam:

Mary Lee/Blue Creek

Net thickness:

8.6 ft

Perforated interval: Perforation size:

1012’ - 1020’ (8 spf)

0.41”

Selected fracturing fluid: Selected proppant:

16/30 Brady sand

Injection tubular I.D.: Pumping rate:

HEC gel (nitrogen foamed)

4.892”

35 BPM

Total Fluid Volume:

2,456 gal gel 100,00 gal foam 180,000 lbs 16/30 mesh Brady sand

Total Proppant Volume: Additives:

Biocide, breaker, and foam stabilizer

Pumping Schedule

Stage

Fluid Type

(PrePad)

Gel

(Pad)

Fluid Volume (gals)

Proppant Concentration (lb/gal)

2,456

----

75 Quality Foam

40,000

----

1

75 Quality Foam

12,000

1.0

2

75 Quality Foam

12,000

2.0

3

75 Quality Foam

12,000

3.0

4

75 Quality Foam

12,000

4.0

5

75 Quality Foam

12,000

5.0

5-29

Chapter

5


Preparing for a Fracture Treatment The success of a fracture treatment depends greatly on the suitability and quality of the materials and equipment used on the job. Maintaining strict quality control is the responsibility of the operator’s representative at the well site. Because quality is largely a function of attitude, service companies usually provide the level of quality that the operator demands. Therefore, before beginning a fracture treatment, you should follow several important operational and quality control guidelines. This section provides the most important guidelines to use:

• When Drilling and Completing the Well • The Week Before the Fracturing Job • The Day of the Fracturing Job In addition to the quality control guidelines presented in this section, there are many other practices that may improve your fracture treatment. For a step-by-step quality control and job supervision checklist that you can use on the job, refer to Appendix B.

When Drilling and Completing the Well You can take several steps when drilling and completing the well that will increase the possibility of an effective fracture stimulation. Success in fracturing a single coal seam generally depends on avoiding horizontal fractures and multiple fractures. In shallow coalbeds, you cannot avoid creating horizontal fractures. Below the shallow coalbeds, you may encounter coalbeds that will fracture both horizontally and vertically. In this transition zone, you may be able to control fracture geometry with treatment pressure. High pressure treatments in the transition zone may create complex or T-shaped fractures. Lower pressure treatments tend to propagate vertical fractures. In the deepest coalbeds, fractures will normally be vertical. The depths at which horizontal, vertical, and a combination of horizontal and vertical fractures propagate depend on the mechanical characteristics of the particular coal.

5-30

Preparing for a FractureTreatment

Horizontal fractures are less effective than vertical fractures because the drainage area affected with a horizontal fracture is considerably less per gallon of fluid injected than with a vertical fracture. In addition, the probability of a screenout, or unsuccessful fracture job, is much greater with horizontal fractures. Mineback observations have shown that a well with horizontal fractures may produce at an acceptable rate early in its life, but its production rate will decline dramatically as the area penetrated by the fracture depletes. Multiple fractures in a well can cause high treating pressures and screenouts. These problems make it difficult to achieve the fracture length needed to yield adequate production rates and an effective radius of drainage in the reservoir.

▲ Caution In open hole completions, fractures tend to initiate at the bottom of the casing.

Avoiding Horizontal Fractures, Multiple Fractures, and Screenouts To minimize the possibility of multiple fractures, excessive treating pressures, and screenouts, GRI-sponsored research has shown that the guidelines below should be followed when drilling and completing the well.

▲ Caution

■

Avoid excessive wellbore diameter, whether resulting from drilled hole size, borehole washout, or wellbore caving. Minimize production tests prior to fracturing because they can cause sloughing and caving. If you are required to prove that fracturing is necessary by performing high pressure drawdown production testing, you may create borehole conditions that jeopardize your opportunity to successfully fracture the well.

■

When completing the well, consider creating vertical notches adjacent from the coal seam using a jetting tool. For open hole completions, create notches with a short jetting operation. When creating jetted notches, avoid creating an excessive wellbore diameter. Improperly using a jetting tool can eliminate the benefits of notching.

5-31

Chapter

5


■

❈ Important

Drill at least 100 to 200 feet below the deepest target coalbed to provide an adequate sump for fracturing and production operations. An adequate sump could help prevent a screenout when pumping the fracture treatment. An adequate sump can also allow the pump to be placed below the perforations, which is beneficial for production. For more information on the sump, refer to Pumping Equipment in Chapter 6.

The guidelines below are based on a GRI-sponsored statistical analysis of data from commercial fields in the Black Warrior Basin. Though these guidelines may apply to coalbed methane wells in some areas, data from the Rock Creek project (which is a controlled research site) indicates that minimizing the time between exposing the coal (by perforating or slotting) and stimulation may not be necessary. ■

Perform the fracturing treatment soon after the coal is exposed. In many coal seams, the mechanical condition of the coal exposed in the wellbore will degenerate with time.

■

If significant time (several weeks or months) will pass before the well is fractured, run casing soon after the well is drilled but do not perforate or slot the casing until ready to fracture the well. Casing will minimize degeneration of the coal.

■

If significant time has passed since a well was drilled (and casing was not set), you may attempt to use a jetting tool to remove the degenerated coal and expose fresh coal surfaces just before fracturing. When performing this procedure, avoid creating an excessive wellbore diameter. Carefully monitor surface returns while jetting to maximize cleanup of the coal face and minimize enlargement of the borehole.

The Week Before the Fracturing Job Follow these guidelines at least a week before the fracturing treatment: ■

5-32

Finalize the fracture treatment design with the service company. Discuss any specific equipment needed to connect the wellhead

Preparing for a FractureTreatment

to the fracturing equipment. Make sure the service company representatives know what type of wellhead connections they must tie into. Review your objectives for the treatment, including cost limitations and the use of standby equipment. Clarify what equipment and materials you (the operator) will provide and what things the service company will provide. Review the quality control procedures for the treatment, and determine who will be responsible for performing and documenting them. Designate a company representative who is responsible for supervising the treatment in the field. Make sure sure this person is informed of all objectives, decisions, and conditions regarding the job. Confirm that the service company representative is informed of these items, as well.

■

Estimate the total cost of the fracture treatment. In addition to the cost to pump the treatment, be sure to include any associated costs such as workover rig, frac tanks, water hauling, logging, etc.

■

Make sure you know what type of fluid, crosslinker and breaker (oxidizer or enzyme) you will use with the gel system. Service companies may keep some information about their fluid additives proprietary. However, to ensure the proper additives are used, you should at least know the answers to the questions below: ❖

What type of crosslinker will be used (i.e., titanium, zirconium, borate, etc.)?

❖

How does the crosslinker work (delayed, adjustable delayed, or instantaneous)?

❖

How does the pH of the fluid affects its performance characteristics?

5-33

Chapter

5


❖

What type of breaker will be used (i.e., enzyme or oxydizing)?

❖

What is the breaker schedule?

❖

What tests will be performed on site to ensure the correct amount of breaker is used?

■

Make sure you know any potential adverse effects of the fracturing fluid you plan to use. You can check published data on the compatibility of fracturing fluids with coal.

■

Coordinate the logistics of moving equipment to the well site.

■

Make sure the service company brings backup pumping units.

■

Make sure the service company thoroughly cleans the frac tanks before filling them with fluids.

■

Consider using a computerized fracture van at the well location to monitor the treatment and to record data. A van properly equipped with monitoring equipment provides an effective environment for making informed decisions during the fracture job.

The Day Before the Fracturing Job Several hours to one day before the fracturing treatment, follow these guidelines: ■

5-34

Sieve the fracturing sand to make sure it is properly sorted (correctly sized). If the sand is not properly sorted, the conductivity of the proppant pack will be reduced. Collect samples of the sand when the sand storage bins on location are being loaded (usually the day before the job). Obtain the samples according to API recommended procedures for collecting sand samples.

Performing a FractureTreatment

If you are using a crosslinked gel fracture fluid: ■

Test the gel fluid to make sure it will mix, crosslink, and break at reservoir temperature.

■

Measure the pH of the gel fluid. The pH must be correct for the fluid crosslinkers and breakers to work properly. If the pH is not correctly matched, the gel fluid may break too quickly or not at all.

■

Measure the viscosity of the gel fluid. The viscosity must be correct for the fluid to carry the proppant effectively into the fractures.

Several hours to one day before the fracturing job, meet with all operating personnel and service company personnel and discuss: ❖

The specific objectives of the fracturing stimulation

❖

The pumping schedule for the stimulation

❖

The type of data wanted from the service company and the form in which you want it

❖

Contingency plans in case of operational problems or emergency situations

❖

Safety and environmental precautions and procedures

❖

Any questions or concerns that the personnel may have

Performing a Fracture Treatment If you have not read the previous section, Preparing for a Fracture Treatment, you should do so before beginning the fracturing job. Once the job begins, you will not have sufficient time to stop the job and decide how to solve a pumping problem. After the service company has placed and connected the fracturing equipment and you have reviewed the fracture treatment plan with all personnel at the well site, you are ready to begin pumping the fracture treatment.

5-35

Chapter

5


Pumping the Treatment Based on experience at the Rock Creek project, the procedures below have proven effective for pumping fracture treatments: 1.

Establish an initial pump-in rate by pumping into the well at the lowest possible rate the equipment will allow (e.g., 1/ 4 BPM).

2.

While carefully monitoring the surface pressure, slowly increase the pump rate until the pressure drops sharply, indicating the formation has broken down.

3.

Record the formation breakdown pressure. Breakdown pressure can give an indication whether perforations are open. ◆

If the breakdown pressure is excessive (i.e., approaching horsepower limits of the pumps or the burst strength of the surface equipment or casing), the perforations or slots may be plugged. To correct this problem, you may try one of these options: A. If you can achieve a sustained, but low injection rate, mix 1/2 lb/gal sand slurry and pump in at a slightly increased pump-in rate to attempt to erode away any material that may be plugging perforations or slots. B. Spot 15% HCl acid across the perforations with the tubing and try again to break down the formation. If you don’t have a rig on the well and cannot spot the acid with tubing, you might use a wireline dump bailer to spot the acid. C. Re-perforate or re-slot the casing. You may consider keeping a wireline truck and crew on standby for this purpose.

▲ Caution

5-36

Pumping an acid treatment to open perforations or slots may permanently damage the permeability of the coal if the appropriate acid is not used. Recent GRI-sponsored research suggests that some acids may react with coal to cause changes in the surface tension of the coal, resulting

Performing a Fracture Treatment

in the coal retaining water. Some acids may be more damaging than others. 15% HCl has been found effective for fracture treatments. If acid is needed to clean perforations, use it sparingly.

4.

Start pumping the pad (fracturing fluid without proppant) slowly, then gradually increase the pump rate to the treating rate (e.g., 15-40 Bbl/min.) This step propagates and/or widens fractures and prepares them to accept the proppant-laden slurry. A typical pad is sized at 20-40% of the total fracture fluid volume. Most operators pump a large pad to ensure they can place all of the sand slurry they have mixed. However, pumping a large pad may not always be necessary and it could actually limit the amount of sand placed before screenout. Some operators believe that if you pump the sand slurry without first pumping a pad (i.e., before the fracture is opened sufficiently), the sand may bridge off at the entrance or tip of the fracture (referred to as “tip plugging”) and cause a screenout or cause the treating pressure to increase beyond the safe limits of the surface equipment or casing. Other operators feel that if the quality of the fluids pumped meets the design standards, little or no pad is needed.

5.

❈ Important

To record an instantaneous shut-in pressure (ISIP) for use in verifying formation fracture gradient, shut-in the well after establishing a stabilized injection rate. For more information about formation fracture gradient, refer to Planning a Fracture Treatment Design earlier in this chapter. For foam fracture treatments, shutting in to record an ISIP may be impractical because it will likely make it difficult to maintain the quality of the foam at design specifications.

6.

Slowly begin adding sand to the fracturing fluid. Start at a low concentration of about 1 lb/gal.

7.

Gradually increase proppant concentration until you reach the designed slurry concentration.

5-37

Chapter

5


By slowly increasing proppant concentration, you can determine if the fractures are conditioned enough to receive the proppant. For example, if the treating pressure increases dramatically while pumping a 1 lb/gal slurry, you will likely be unable to pump a 2 lb/gal slurry. If you observe a sharp pressure increase, slightly reducing sand concentration may allow you to continue the job.

▲ Caution

Because fluid constantly leaks off to the formation during the job, fluid viscosity tends to continuously increase. If you increase the proppant concentration too rapidly, fluid viscosity can rise quickly, causing treating pressure to increase sharply. 8.

Carefully monitor the treating pressure while pumping the treatment. A useful diagnostic tool for evaluating treatment pressure response is the Nolte Plot. Figure 5-4 shows a Nolte Plot.

Figure 5-4 Nolte Plot for Evaluating Treatment Pressure Responses

5-38


Each of the “modes” in the Nolte Plot is explained below: Mode I: Small Positive Slope

A small positive pressure increase indicates increasing fracture length with confined height growth. This response is desirable.

Mode II: Constant Pressure

A constant pressure mode is potentially the most significant portion of the curve. The constant pressure mode is almost always followed by a sharp increase or decrease in pressure and never a return to the preferable Mode I (increasing fracture length with confined height). The cause of the constant pressure region (Mode II) can usually be inferred by interpreting the pressure behavior following the constant pressure region in Modes III and IV.

Mode III: Steep Positive Slope

When Mode II is followed by a steep pressure increase, the cause could be one of the following: ❖

Tip plugging (plugging of the entrance or tip of the fracture near the wellbore)

❖

Bridging off of sand inside the fracture

❖

Leakoff of fluid to the formation

❖

Settling or “duning” of sand in the wellbore

The pressure trends indicated in the Nolte Plot are formation treating pressures (downhole pressures). If you are measuring and analyzing surface pressures only (not downhole pressures), several factors could affect the surface pressures without necessarily affecting the formation treating pressures: ❖

Changing hydrostatic pressure of the fracturing fluid as the sand concentration increases

❖

Decreasing perforation friction pressure as the sand erodes the perforations during the treatment

5-39

Chapter

5


Because both of these situations decrease the surface treating pressure, they could offset and mask increases in formation treating pressures during Mode III. These conditions might also easily be confused with decreasing formation treating pressure associated with Mode IV. To assess the effects of hydrostatic pressure, you can run downhole pressure gauges with a surface readout or a tubing “dead string.” Refer to Using a Tubing “Dead String" to Measure Bottomhole Pressure, earlier in this chapter.

Mode IV: Negative Slope

When Mode II is followed by a decrease in pressure, the most likely cause is fracture height growth. Because the goal of fracturing is to propagate a fracture out laterally from the wellbore, this response is undesirable. ◆

9.

If you observe a negative slope, you may try to reduce injection rate to minimize fracture height growth.

If the estimated formation treating pressure increases as you increase the proppant concentration, you have three options: A. Increase the pump rate by about 20% and continue pumping the slurry at the same sand concentration until screenout. Increasing the pump rate may widen the fractures enough to accept the fracture fluid. Some operators believe that you have only a certain amount of time, or “window of opportunity,” within which to pump the slurry before screenout occurs. They prefer to continue pumping to place all the proppant they can before screenout. B. Cut sand concentration, then pump a pad (fluid without sand). If the treating pressure decreases, gradually increase sand concentration and continue the job. Some operators believe that during the fracture job, sand can settle and accumulate or “dune” near the wellbore. They prefer to pump a pad to attempt to clear the dune away and thereby lower the treating pressure.

5-40


C. If the end of the job is near, increase the pump rate and continue pumping the fluid at a higher sand concentration until the entire treatment is pumped or screenout occurs. Some operators increase sand concentration while continuing to pump at increased rate to try to maximize the amount of proppant they place before screenout occurs.

▲ Caution 10. A sharp, sudden increase in treating pressure before the end of the job evidences a wellbore screenout or severe bridging and plugging of sand in the wellbore. If you encounter a wellbore screenout, you should never try to continue pumping the sand slurry away. Continuing to pump will result in excessive pump pressure and may crush the sand in the near-wellbore fracture. ◆

If you encounter a wellbore screenout while pumping a gel or foamed gel treatment, shut down the pumps and stop the treatment. You will likely have to wash the sand out of the wellbore using tubing. However, you may first try to flow back the well using one of the flowback methods described later in this chapter.

◆

If you encounter a wellbore screenout while pumping a water fracture treatment, you may try the procedure below to reestablish the treating rate: 1. Shut down pumps and free flow the well back to the surface pit until you get bottoms-up. 2. Monitor the “blooey” (return) line for dirty fluid and/or fluid with a high concentration of sand. 3. Pump clean fluid (without proppant) while gradually increasing the pump rate. 4. If you can re-establish the treating rate, start pumping sand again. 5. If you cannot re-establish the treating rate, repeat this procedure. 6. If you have pumped two-thirds or more of the treatment, and you cannot re-establish a treating rate, you may want to consider the job completed.

5-41

Chapter

5


The procedure above may not be useful for gel fracture treatments. Because water has a lower viscosity and proppant transport capability than gels, it is possible that “dunes” of sand may develop in the fracture during a water fracture treatment. These dunes may become immobile, which can cause increased treating pressures and wellbore screenout. Backflowing the well, as described above, may help to move the dune enough to allow pumping the treatment again. Because gels have greater viscosity and better proppant transport capabilities than water, sand duning is not as likely during a gel treatment. Therefore the procedure above probably would not be as effective for a gel frac treatment.

11. Do not over-flush the wellbore after pumping the fracture treatment. Over-flushing means pumping clean fluid (without proppant) in an attempt to displace into the fractures any sand-laden fluid remaining in the wellbore once pumping is completed. Some operators over-flush to try to eliminate production of sand after the fracture treatment. However, over-flushing has not been demonstrated to control sand production.

▲ Caution

Over-flushing may wash away some of the near-wellbore sand pack. When treating pressure is released, the unpropped fractures near the wellbore may close and thus severely restrict production.

12. Near the end of the job, observe and record these pressures at the surface to help in the design of future fracture treatments:

• Final treating pressure before shutting down pumps. • Initial Shut-in Pressure (ISIP) at surface as soon as the pumps shut down.

• Pressure fall-off after shut-in. Look for an inflection point, or sharp change, in the rate of pressure decline. This inflection indicates the “closure pressure,” or pressure at which the fracture closes on the proppant.

5-42


As fracture fluid leaks off into the formation, pressure in the fracture decreases. Eventually, the pressure declines enough to allow the fracture to close on the proppant. When the fracture closes, the fluid can only flow through the proppant pack, which creates increased frictional pressure loss. Therefore, the decreased rate of pressure decline you observe at the surface reflects the closure of the propped fracture.

Flowing Back the Well After the Treatment As with most aspects of fracturing coalbed methane wells, the selection of a method for flowing the well back is generally controversial. There are many divergent opinions about the most effective flowback technique. Three of the most common opinions are listed below: ❖

Fractured wells should be flowed back at a slow rate immediately after the treatment to force the formation to close on the proppant before the gel breaks. This method is called “forced closure.” If the fracture does not close on the proppant before the gel breaks, the sand may settle to the bottom of the fracture. If the fracture extended below the coal seam, such sand settling could result in an unpropped fracture in the coal. “New Techniques and Quality Control Find Success in Enhancing Productivity and Minimizing Proppant Flowback, ” J.W. Ely et al, SPE Paper 20708, SPE Annual Technical Conference and Exhibition, 1990.

❖

Flowing back wells immediately after the fracture treatment will not prevent sand from settling in the fracture. Because flowing back the well only affects a small region near the wellbore, it will not prevent sand from settling in a fracture away from the wellbore. Moreover, as the treating pressure of the shut-in well leaks off to the formation naturally, the fluid flows through the proppant pack at a rate greater than could be achieved by flowing back the well.

5-43

Chapter

5


Fractured wells should not be flowed back before the fracture closes on the proppant (fracture closure) so that pressures can be monitored. Monitoring pressures after the well is shut-in will help you to determine how quickly the fracture closes on the proppant and the pressure at which closure occurs. (Closure pressure is the fluid pressure required to initiate the opening of an existing fracture. This pressure is equal to and counteracts the stress in the rock perpendicular to the fracture plane. This stress, often called closure stress, is the minimum principal in-situ stress. Closure pressure is indicated by an inflection point, or sharp change, in the rate of pressure decline after the well is shut-in.) “Experimental and Modeling Evidence for Major Changes in Hydraulic Fracturing Design and Field Procedures,” M.P. Cleary et al, SPE Paper 21494, SPE Gas Technology Symposium, 1991.

❖

Fractured wells should not be flowed back until the fracturing gel breaks. Prematurely flowing back unbroken gel may flush proppant out of the fracture at the wellbore and result in poor conductivity near the wellbore, where it is most needed. “Recent Advances in Hydraulic Fracturing,” SPE Monograph Vol. 12, J.L. Gidley et al, 1989.

A theoretical discussion of these varying opinions is beyond the scope of this guide. However, you may want to investigate each of them further to help you determine the best flowback method for your particular application. Most operators in the Black Warrior Basin generally use one of three methods (or a variation of these methods) to flow back wells after a fracture stimulation. These methods are:

• Shut-In with Slow Flowback • Forced Closure Through Flowback • High Rate Flowback • Foam Treatment Flowback

5-44


Shut-In with Slow Flowback In this method, you shut in the well for a period of time following the treatment and then flow back the well at a slow rate. Some operators believe this method is effective because it allows greater recovery of the gel fracturing fluid. The shut-in period gives the gel sufficient time to break. As the gel degrades with time, it flows more easily through the sand pack and into the wellbore. Other operators like this method because they believe it allows time for the fracture to close on the proppant, thus providing a well propped fracture. Some operators dislike the slow flowback method because they believe it allows time for the proppant to settle in the fracture and thus allows the top portion of fracture to close without proppant in it. The length of the shut-in period depends on your purpose for shutting in the well. If you use the shut-in period to allow the gel time to break, you can estimate the time for gel breakdown by consulting with the service company pumping the treatment. You should also watch the gel samples that were collected throughout the job and make sure at least the gel pumped during the later stages of the job did break. If there is a significant temperature difference between the surface and bottomhole (i.e., the coal seam is deep), the gel in the formation may break before the gel sample on the surface. In some cases, the gel sample may not break at all. If the gel samples do not break, you can accept the service company’s estimated break time and then monitor the fluid that is flowed back to see if it appears to be gel or broken gel. If you use this flowback method to allow time for the fracture to close on the proppant, you should closely monitor well pressures after the fracture treatment and try to identify fracture closure as it occurs. It is not possible to accurately predict closure pressure in advance of the treatment. Moreover, the closure pressure for coalbed methane wells cannot be estimated accurately from closure pressure data from offset wells. At the Rock Creek project, the shut-in with slow flowback method has been used successfully for gel fracture treatments. Experience has demonstrated that this method produces the most effective fracture treatment with the fewest production problems. Because slow flowback effectively reduces the amount of coal fines and

5-45

Chapter

5


fracture proppant that enters the wellbore and surface production equipment, it reduces costly wellbore cleanouts and downhole pump replacements. The procedures used to flow back a well and place it on production at Rock Creek are listed below:

1.

After pumping the fracture treatment, shut-in the well until the gel breaks (usually 1/2 day to 1 day).

2.

If there is still pressure on the wellhead at the end of the shut-in period, flow the well back at a slow rate.

3.

Continually monitor the fluid for proppant or coal fines. If you observe proppant or fines, decrease the flow rate as needed to stop the flowback of proppant or fines.

4.

After the well has been flowed back long enough to bleed off wellhead pressure, remove the frac valve and re-install the wellhead.

5.

Run a string of production tubing to the bottom of the well to wash out the wellbore. You must wash any sand and debris out of the sump so you can place the production pump at or below the perforations to minimize bottomhole pressure and maximize flowrate.

▲ Caution

5-46

6.

Pump clean fluid down the tubing-casing annulus and take returns up the tubing string.

7.

Lower the tubing string and wash the wellbore down to the bottom of the sump. Pumping down the tubing and taking returns up the tubingcasing annulus may cause any debris in the well to flow into perforations or slots and plug them. You may avoid this problem by washing the wellbore with air instead of water.


8.

Install the production pump and begin pumping the well down. For information on pumping the well down, refer to Chapter 7.

❈ Important The decision to use the Shut-In with Slow Flowback method may depend on the type of fracture fluid used. If using a fluid with poor proppant-carrying capacity (i.e., water), sand in the fracture could quickly settle below the pay zone causing the fracture through the pay zone to close. Thus, when using a fluid with poor proppant carrying capacity, you may consider using the Forced Closure method.

Forced Closure Through Flowback Flow the well back at a restricted rate within seconds or minutes after you finish pumping the treatment. Procedures and an equipment schematic for this method are shown in Appendix C. Some operators believe this method allows the fracture to close more quickly, thereby preventing proppant from settling to the bottom of the fracture and leaving the top portion unpropped. However, because of the generally poor elastic properties of most shallow coals (as compared to sandstones), fracture closure will likely be slow and/or incomplete. Evidence suggests this method may work best in deep, low-permeability coalbeds, which exhibit greater elastic properties.

▲ Caution The forced closure method may cause sand to flow into the wellbore if you flow the well back at an excessive rate. This proppant flowback may leave near-wellbore fractures unpropped and thus restrict production.

High Rate Flowback Flow the well back at a very high rate (i.e., little or no flow restriction) a few minutes after you finish pumping the treatment. A few operators believe this method flows back sand that would otherwise flow into the wellbore when the well is produced. They believe any near-wellbore voids in the proppant pack caused by flowback are filled by other sand from deeper in the fracture.

5-47

Chapter

5


▲ Caution The high rate flowback method may damage the fracture treatment by pulling sand out of the fracture. This proppant flowback may leave near-wellbore fractures unpropped and thus restrict production. This method is not recommended.

Foam Treatment Flowback One of the advantages of using a foamed fluid is quick clean-up. Because foamed fracturing fluids contain 65-85% gas (usually nitrogen), less liquid must be flowed back after a foam fracturing treatment. Therefore, most operators start flowing back the foam treatment as soon as possible after the end of the treatment. At the Rock Creek project, as soon as the service company equipment is rigged down from the wellhead, a flowline to the production pit or frac tank is rigged up and flowback begins. As with gel fracture treatments, the flowback rate is restricted to prevent proppant flowback into the wellbore.

Evaluating a Fracture Treatment Fracturing is usually required to create a productive coalbed methane well, and it can represent the single greatest cost on the well. Therefore, it is prudent to evaluate the effectiveness of each fracture treatment so the design and implementation of future treatments can be improved. The evaluation of a fracture treatment is usually performed by a reservoir engineer. For information on the reservoir engineering aspects of fracture evaluation, refer to Additional Resources at the end of this chapter. This section provides an overview of the field aspects of fracture evaluation. The techniques that have been used at the Rock Creek project to evaluate the success of hydraulic fracture treatments are

• Production Comparison • Pressure Transient Well Tests

5-48

Evaluating a FractureTreatment

• Response in Offset Wells • Radioactive Tracers/Gamma Ray Log • Tiltmeters

Production Comparison In some conventional gas fields, the simplest and most conclusive way to evaluate a fracture treatment is to test the well before fracturing and then compare the pre-frac production rate to the rate after treatment. However, such production comparisons can be misleading for coalbed methane wells. In newly completed coalbed methane wells, pre-fracture production tests are often unreliable indicators of the true reservoir properties of the coal because of poor communication with the natural fracture system of the coal. Even though perforating or slotting may penetrate through the casing and cement, it is possible the penetration into the coal might be insufficient to penetrate the coal’s natural fractures. Comparisons with post-fracture production tests in offset wells can also be misleading because of heterogeneities in the coals and the overlying rock. The reservoir and rock properties of the coal and the overlying rock can vary considerably over short distances. Some of the variables that may contribute to this heterogeneity are the presence or absence of fractures in the overlying rock, stress regimes in the rock, cleat development within the coal, and the presence of mineral filling in the cleat system. Production comparisons may be helpful in evaluating fracture treatments, but you should not rely greatly on them and you should never use them as the only evaluation tool. If you do compare production from individual wells in a field, you should probably exclude the upper and lower 5-10% of the wells (based on production rate) in order to make realistic comparisons. At the Rock Creek project, production data is generally used as support information in evaluating fracture treatments. Fracture treatment evaluations are based primarily on well tests and data from monitor wells.

5-49

Chapter

5


Pressure Transient Well Tests Post-fracture pressure transient well tests can help you to evaluate the success of fracture treatments by helping you determine the effective length and conductivity of the created fracture. To estimate the effective fracture length, you usually must know the average permeability of the formation before the fracture job. To determine the permeability, you must conduct a pre-fracture pressure transient well test. The procedures used to conduct post-fracture pressure transient tests are the same as those used on non-fractured wells. For information on performing pressure transient well tests, refer to Chapter 9. The techniques for analyzing well tests of fractured wells is different than those used for non-fractured wells. Analysis of pressure transient tests is beyond the scope of this guide; however, you can find information on this topic in Additional Resources at the end of Chapter 9.

Response in Offset Wells By monitoring the production and pressure responses in nearby offset wells, you may gain information useful in determining the direction of the induced fracture. Responses in offset wells may also be incorporated into a reservoir simulation to estimate fracture height and length. In some coalbed methane fields, the distance between wells may be too great to detect pressure responses to a fracture treatment in offset wells. However, you may be able to gain useful information by monitoring the closest offset wells for changes in reservoir pressures and produced fluid characteristics. Such changes may help you determine communication with fractured coal intervals and the orientation of the induced fracture. The least expensive way to measure pressure responses in offset wells is by shooting acoustic fluid levels. However, the accuracy of measuring the fluid level is only approximately the length of a joint of tubing, or about 30 feet. Thus, you can not detect small pressure responses with this method.

5-50


To detect pressure changes with greater accuracy, you can run downhole pressure sensors in offset wells. Pressure sensors may provide accurate and useful data, but their rental cost may be difficult to justify. If you do use pressure sensors, try to take full advantage of them. For example, you can schedule a well test while the sensor is installed in the well to gain additional use from the pressure data.

Radioactive Tracers/Gamma Ray Log Radioactive tracers can be used with the gamma ray log to help determine the height of the induced fracture and the placement of the fracture treatment. However, some service companies no longer provide the radioactive tracer service because of the potential health risks to their workers. Because you might have difficulty in locating a company to provide the service, you should check with service companies well in advance of the fracture job. In this technique, radioactive tracers are placed in the fracturing sand and/or fluid while it is pumped. Then after the stimulated well has been flowed back, a gamma ray log is run in the well. By comparing the post-fracture gamma ray log to a base log (a gamma ray log run before the fracture treatment), the effects of the injected fracturing fluids may be determined. The gamma ray log usually run in combination with the cased hole cement evaluation log is often used as the base gamma ray log. If a cased hole gamma ray log was not run before the treatment, you need not run make a special logging run. You can use the open hole gamma ray log as the base log. To help you correctly distinguish fracture height from fluid leakoff, you can place different radioactive isotopes in the different stages of the fracture treatment. For example, you can run different isotopes in the pad, the first proppant stage, and the last proppant stage. A special gamma ray detector can be run that will differentiate between the different isotopes. This technique will allow you to distinguish between propped fracture height and fluid channeling behind pipe. It may also help you determine whether the near wellbore fracture is propped with the first stage sand, the last stage sand, or a mixture of the two. You should wait until the well has been flowed back and produced for a while before running the gamma ray log. This period of time

5-51

Chapter

5


will help to eliminate traces of the radioactive isotopes in the wellbore and thus reduce the possibility of making erroneous log interpretations. However, each isotope has a specific half-life. You must run the log before the shortest half-life of any of the isotopes expires so the gamma ray log will still detect the radioactivity.

❈ Important

Using radioactive tracers may not always help you determine actual fracture height because tracers have a limited detection depth and because the fracture may not be in line with the wellbore. When planning to use radioactive tracers to evaluate a fracture treatment, consider the guidelines below: ■

Determine the types of information you want to obtain by using tracers. Discuss the evaluation with the reservoir engineer for the project. For example, will it be helpful to know where the fluids went or which proppant stage propped the near wellbore fracture?

■

Consult with a service company that will perform the fracture treatment to determine its capabilities and to obtain its recommendation for using radioactive tracers.

■

Make sure that either a cased hole or open hole gamma ray log has been run on the well before the fracture treatment.

■

Check with local regulatory agencies to learn about their policies for using radioactive tracers. More than one agency may regulate radioactive substances. Agencies in some states will not allow the use of radioactive tracers in shallow seams.

Tiltmeters Tiltmeters are sensitive geophysical instruments that are used to measure slight displacements in the earth’s surface from horizontal. A tiltmeter is essentially a bubble level. The primary component in the tiltmeter is the tilt sensor, shown in Figure 5-5. The tilt sensor contains a receptacle filled with two fluids. Each fluid has a

5-52


different electrical resistivity. As the sensor is tilted, the bubble moves, and the resistance between the electrical contacts at AC and BD changes. These resistance changes are electronically converted into a voltage which is proportional to the tilt of the instrument. The voltage is then converted to a digital number and stored for analysis.

Figure 5-5 Tiltmeter Sensor

If you are developing a new field, knowing the expected azimuth, or orientation, of the created fracture can help you to determine the optimum well spacing. In fracture stimulations of shallow coalbeds, several tiltmeters can be placed around the well to help determine fracture azimuth and shape. After a fracture treatment, all of the data recorded and stored in the tiltmeter is collected. This data is then analyzed using computer models to help determine the shape and orientation of the fracture.

5-53

Chapter

5


To work properly, tiltmeters must be isolated from the large fluctuations of the earth’s surface. To achieve this isolation, tiltmeters should be placed in holes 15-20 feet deep. These holes are drilled and then cased with PVC pipe. The tiltmeters are lowered into these holes, sand is placed around the instruments, and a rod is used to pack the sand around the tiltmeters to hold them in place. Figure 5-6 shows a typical tiltmeter installation.

Figure 5-6 Tiltmeter Installation

Tiltmeters should be installed at a distance of 0.4 times the depth of the seam to be fractured. This distance is estimated to be the location where maximum tilt will occur. For example, if the seam to be fractured is 1000 feet deep, the the tiltmeters should be installed 400 feet (1000 X 0.4) away from the well.

5-54


Tiltmeters should be installed at least a couple of days to a week before the fracture treatment to record and model the background tilt which is caused by the combined effects of the earth’s tides, thermal stresses and other environmental factors. These environmental factors are then removed from the data recorded during the fracture treatment so that only the tilt caused by the treatment can be modelled. After the fracture treatment, the tilt vectors can be displayed on a map showing the direction of the tilt from the tiltmeter site. Figure 5-7 shows a typical tilt vector display for a vertical fracture and for a horizontal fracture. Most actual displays may appear as some combination of the vertical and horizontal displays because of other effects such as fluid leakoff during the fracture treatment.

Figure 5-7 Tiltmeter Displays for Vertical and Horizontal Fractures

At the Rock Creek project, tiltmeters have been used successfully to determine fracture orientation and shape. Tiltmeters were used

5-55

Chapter

5


to record data when Wells P1A, P1B, P1C, and P4 were fractured. Analysis of the data for Well P1A indicated the Pratt coalseam (at 478 feet) was fractured horizontally. Analysis of data for Wells P1B and P1A indicated the Mary Lee/Blue Creek coalseams (1039 feet) and the Black Creek coalseam (1418 feet), respectively, were fractured vertically. The fracture of the Mary Lee in Well P4 also was found to be vertical.

Running tiltmeters is a sensitive and expensive operation. To obtain useful data you must carefully coordinate the fracture treatment with the service company providing the tiltmeters. To help ensure a successful job, consider the guidelines below:

5-56

■

Discuss the fracture stimulation plan and the tiltmeter installation requirements with the tiltmeter service representative in advance of the job.

■

Drill holes for tiltmeters at least one week before the fracture treatment.

■

Make sure the tiltmeters are calibrated and installed at least two days before the fracture treatment to record background trends, which are needed for the analysis.

■

Inform the tiltmeter service representative of the starting time for the fracture treatment.

■

Avoid scheduling the fracture treatment during stormy weather. Such weather conditions can adversely affect the data.

■

Drill the tiltmeter holes as straight as possible.

■

Make sure to include the cost of drilling tiltmeter holes in the cost estimate for running tiltmeters.


For more information on tiltmeters, you may consult with companies that provide specialized geophysical services. ❖

❖

❖

5-57

Chapter

5



Cleary, M.P., C.A. Wright, and T.B. Wright, “Experimental and Modeling Evidence for Major Changes in Hydraulic Fracturing Design and Field Procedures,” SPE Paper 21494, presented at the 1991 SPE Gas Technology Symposium, Houston (January 22-24).

Ely, J.W., W.T. Arnold, and S.A. Holditch, “New Techniques and Quality Control Find Success in Enhancing Productivity and Minimizing Proppant Flowback,” SPE Paper 20708 presented at the 1990 Annual Technical Conference and Exhibition, New Orleans (September 23-25).

Gazonas, G.A., C.A. Wright, and M.D. Wood, “Tiltmeter Mapping and Monitoring of Hydraulic Fracture Propagation in Coal: A Case Study in the Warrior Basin, Alabama,” Geology and Coalbed Methane Resources of the Northern San Juan Basin, Colorado, New Mexico, Rocky Mountain Association of Geologists, Denver, 1988.

Gidley, J.L., S.A. Holditch, D.E. Nierode, and R.W. Veatch Jr., “Recent Advances in Hydraulic Fracturing,” SPE Monograph 12, 1989.

Holditch, S.A. et al, “Enhanced Recovery of Coalbed Methane Through Hydraulic Fracturing,” SPE Paper 18250 presented at the 1988 SPE Annual Technical Conference and Exhibition, Houston (October 2-5).

Holditch, S.A. and Associates, Inc., “Hydraulic Fracturing of Coal Seams,” a short course presented at the 1991 Coalbed Methane Symposium, Tuscaloosa, Alabama (May 13-16). Khodaverdian M., J.D. McLennan, A.H. Jones et al, “Examination of Near-Wellbore Effects of Hydraulic Fracturing of Coal,” in Rock Mechanics as a Multidisciplinary Science, Norman, Oklahoma, 1992.

5-58


Lee, W.S., “New Method of Minifrac Analysis Offers Greater Accuracy and Enhanced Applicability,” SPE Paper 15041 presented at the 1986 Eastern Regional Meeting, Columbus, Ohio (November 12-14).

McDaniel, B.W., “Benefits and Problems of Minifrac Applications in Coalbed Methane Wells,” CIM/SPE Paper 90-103 presented a the the 1990 CIM/SPE International Technical Meeting, Calgary (June 10-13).

Nierode, D.E., “Comparison of Hydraulic Fracture Design Methods to Observed Field Results,” SPE Paper 12059 presented at the 1983 Annual Technical Conference and Exhibition, San Francisco (October 5-8).

Nolte, K.G., “Determination of Fracture Parameters from Fracturing Pressure Decline,” SPE Paper 8341 presented at the 1979 Annual Technical Conference and Exhibition, Las Vegas (September 23-26).

Nolte, K.G., “A General Analysis of Fracturing Pressure Decline Analysis with Application to Three Models,” SPE Formation Evaluation, December 1986.

Nolte, K.G. and Smith, M.G., “Interpretation of Fracturing Pressures,” Journal of Petroleum Technology, 1981.

Palmer, I.D., R.T. Fryar, K.A. Tumino, and R. Puri, “Comparison Between Gel-Fracture and Water-Fracture Stimulations in the Black Warrior Basin,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama, (May 13-16).

Puri, R., G.E. King, and I.D. Palmer, “Damage to Coal Permeability During Hydraulic Fracturing,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (May 13-16).

5-59

Chapter

5


Shelley, R.F. and McGowen, J.M., “Pump-in Test Correlation Predicts Proppant Placement,” SPE Paper 15151 presented at the 1986 Rocky Mountain Regional Meeting, Billings (May 19-21).

Soliman, M.Y., R.D. Kuhlman, and D.K. Poulsen, “Minifrac Analysis for a Heterogeneous Formation,” CIM/SPE Paper 90-5 presented at the 1990 CIM/SPE International Technical Meeting, Calgary (June 10-13).

5-60

6

Selecting Production Equipment and Facilities

M

uch of the well equipment and production facilities for producing a coalbed methane field is the same as that used in a conventional oil or gas field. However, operating experience in the Black Warrior Basin has provided many useful adaptations and improvements you may find particularly effective for operating a coalbed methane project. This chapter provides practical guidelines to help you select proper equipment and facilities for your coalbed methane field. The chapter will guide you through:

• Estimating the Volume of Water to be Produced • Pumping Equipment • Power Supply for Pumping Equipment • Surface Production Facilities • Gas Compressors • Gas Dehydration Equipment

Chapter

6


Estimating the Volume of Water to be Produced To initiate and maintain gas flow from low-pressure coal formations, you must continuously remove water from the well. This co-produced water is one of the biggest differences between producing conventional natural gas and producing coalbed methane. Operators often have to pump water from wells for six months or longer before methane is produced. When multiple coal seams are produced, water production can be high. The volume of produced water will depend on the properties of the coal seam, which can vary greatly from one area to another. Before you can begin planning the equipment and facilities for a field, you must estimate the volume of water you will need to produce, treat and dispose. The volume of produced water is often one of the most important factors in determining equipment and facility requirements and overall project economics. Though you may find it difficult to estimate produced water volume in a undeveloped area, you should use the best information you can obtain. Keep in mind that water production rates observed before fracturing a well may be substantially less than water rates after the well is fractured. The guidelines below may help you in estimating water production data.

6-2

■

When drilling exploratory wells or development wells, you can estimate water flow from formations by closely monitoring the drilling pits.

■

When a well has been drilled to total depth (TD), trip to TD with drillstring (or coiled tubing), inject compressed air, air mist, or nitrogen for several hours to clean out the wellbore, and observe water production rates at the surface.

■

Obtain data from other producers in the area if it is available. Seek data about formation permeability, initial and peak water rates,and cumulative water volumes to-date for specific coal formations in the area. If producers are reluctant to share production data, you may find this data available as public information at your state or regional oil and gas agencies or environmental agencies.

Pumping Equipment

■

Perform hydrologic (slug) tests in exploratory wells or core holes to estimate the permeability of the coal seam. You can make a general approximation of the water influx rate based on this permeability estimate. For information on performing slug tests, refer to Chapter 9.

Pumping Equipment To maximize gas production from a coalbed methane well, you must keep the water level in the wellbore below the lowest producing coalbed. Because coalbeds are usually relatively shallow, lowpressure formations, you must pump water from coalbed wells continuously (or intermittently) to minimize bottomhole pressure and allow gas to flow into the wellbore. This section will explain the benefits and limitations of the most common methods used to pump water from coalbed wells. These methods are:

• Beam Pumps • Progressing Cavity Pumps • Gas Lift • Electric Submersible Pumps Table 6-1 shows a summary of the benefits and limitations of using these artifical lift methods for coalbed methane wells.

6-3

Chapter

6


Table 6-1 Artificial Lift Methods for Coalbed Methane Production Artificial Lift Method

Beam Pumps (Sucker Rod Pumps)

Benefits

Operate over a wide range of depths & volumes

Require only minor routine maintenance Can be rebuilt completely if worn or damaged

Increased wear in crooked holes

Can lift high rates of water

Can burn up if water level falls below the pump

Contain only one moving internal part, the rotor Require little space at surface because wellhead-mounted Surface equipment is unobtrusive visually

Gas Lift

Handles solids well Can accommodate a wide range of fluid rates

Electric Submersible Pumps

6-4

Rod string can fail Can become stuck if well produces large amounts of coal fines or sand, especially with bottom hold-down installation

Do not have to be submerged to operate

Progressing Cavity Pumps

Limitations

Stator & rotor can be rebuilt when worn out Setting depths are limited Rods may part if excessive torque is applied

Requires gas source for initial production May require training of field personnel

Can lift large volumes of water

High initial cost and maintenance cost

Operate quietly and efficiently

Can easily burn up if they run dry

Pumping Equipment

Beam Pumps Beam pumps, also called sucker rod pumps, have served as an effective, reliable, and relatively inexpensive method for removing liquids from wells since the early days of the oil industry. The beam pumping system consists of a downhole plunger pump, a sucker rod string, a surface pumping unit (pump jack), a gearbox/ speed reducer and a prime mover (motor). Figure 6-1 shows a typical beam pumping system.

Figure 6-1 Beam Pump

6-5

Chapter

6


For a beam pumping to operate effectively and with minimal maintenance, all components of the pumping system must be designed and sized properly. The system must accommodate the well depth, and the volume, viscosity, and abrasiveness of fluids to be produced (water and gas). Beam pumps are relatively simple and durable. They require only minor routine maintenance. Special subsurface designs may be required in extremely gassy wells or wells with large amounts of sand and fines. Properly sized units can pump up to 2,500 BWPD; however, pumping units pumping less than 600 BWPD are more common. Because of the relatively shallow producing depths in the Black Warrior Basin, operators in this area use beam pumping units with peak torque ratings ranging from 40,000 inch-pounds to 228,000 inch-pounds and stroke lengths ranging from 36 inches to 120 inches.

Selecting a Sucker Rod Pump and Equipment Most operators in the Black Warrior Basin use a thin-wall (low pressure) insert type of sucker rod pump, or plunger pump. This pump sits in a seating nipple at the bottom of the tubing string, and the entire pump can be retrieved by simply pulling the sucker rod string. Because solids production requires frequent pump repairs in coalbed methane wells, this easy retrievability is a significant advantage. Some operators use a tubing pump to pump large volumes of water, especially during initial production. The tubing pump has a barrel that is installed in the tubing string. The plunger is lowered on the sucker rod string and is latched into the barrel. You can retrieve the plunger by pulling the rods; however, you must pull the tubing string to retrieve the barrel. To select the best type of pump system for your operation, consult a trained, experienced pump specialist. A competent pump specialist will discuss the particular requirements of your field, simulate various producing scenarios, and provide detailed computer analyses for a variety of possible pump designs. For example, pump specialists can explain the benefits and limitations of combining various types and sizes of plungers, tubing, rod strings, pump jacks, and motors. For more information on beam pumping systems, refer to Additional Resources the end of this chapter.

6-6

Pumping Equipment

Operating experience in the Black Warrior Basin has produced these general guidelines, which should help you in selecting downhole equipment for beam pumping units:

■

Install a tubing anchor at the bottom of the tubing string to eliminate tubing stretch. If the tubing is not anchored, the pump can pick up the weight of the tubing string on the upstroke. This weight can greatly reduce the efficiency of the pump. Tubing stretch is more pronounced in deep wells.

■

In new wells, install a ring-type plunger pump initially. After the well cleans up and stops producing appreciable amounts of sand or coal fines, replace the ring-type pump with a metal plunger pump. Ring-type pumps contain non-metal parts which will not cut out as easily as metal pump parts.

■

Install double standing valves and double travelling valves in each pump. Installing two valves provides a backup in case the primary valve fails. This step can reduce the cost of pulling pumps by extending the time between pulling jobs.

■

In shallow, low-pressure wells, install the pump with a topseating hold-down assembly. Figure 6-2 shows a pump installed with a top-seating hold-down assembly. The top-seating hold-down assembly provides these distinct advantages: ❖ Prevents the pump from becoming stuck because it does not

allow sand and coal fines to settle between the pump barrel and the inside of tubing. ❖ The pump barrel cannot wear by rubbing against the tubing

because the body of the pump pivots from its top and aligns in crooked holes more readily than other types of pumps.

6-7

Chapter

6


Figure 6-2 Top-Seating Pump Hold-Down

In deep, higher pressure wells, install the pump with a bottom-seating hold-down assembly. Figure 6-3 shows a pump installed with a bottom-seating hold-down assembly. The bottom-seating hold-down assembly has these advantages and disadvantages: ❖ Using the bottom hold-down assembly reduces the possibility

of the pump barrel swelling. Both the inside and the outside of the barrel are exposed to the hydrostatic tubing pressure, which eliminates pressure differential across the wall of the barrel. ❖ Using the bottom hold-down assembly increases the danger of

the pump sticking in the well because solid particles can settle between the pump barrel and the inside of the tubing.

6-8

Pumping Equipment

Figure 6-3 Bottom-Seating Pump Hold-Down

■

▲ Caution

Install a mud anchor and a strainer nipple or stainless steel screen at the pump inlet (bottom end of the pump) to prevent large solids from entering the pump. If a well produces scale, a mud anchor, strainer nipple, or screen may quickly plug with scale and cause the pump to fail. You may need to chemically treat the well to reduce severe scaling problems.

■

In wells that produce a significant amount of gas, install a gas anchor at the pump inlet (bottom end of the pump) to minimize gas from entering the pump. The gas anchor is a device that acts as a separation chamber to direct gas up the casing/tubing annulus instead of into the pump inlet. Figure 6-4 shows a typical gas anchor.

6-9

Chapter

6


Figure 6-4 Gas Anchor

■

Order at least one set of “pony rods” (sucker rods in 2, 4, 6, and 8 ft lengths) to allow you to properly fit the length of the rod string to the tubing string.

■

Select a pumping tee and stuffing box assembly based on the operating pressure of the separator. For most low-pressure coalbed methane applications, a simple type stuffing box works well. For higher pressure applications, you may need to use a grease-packed type of stuffing box. The stuffing box provides a seal around the polished rod to contain water and gas in the tubing. The stuffing box also wipes the polished rod with water to keep it lubricated.

Installing the Sucker Rod Pump and Rods These general guidelines will help you install the pump and rods in the wellbore: ■

6-10

Install a latching assembly, or “on/off tool”, between the top of the pump and the first sucker rod.

Pumping Equipment

This tool allows you to release the sucker rod string from the pump and pull the rods if the pump becomes stuck in the tubing. You can then retrieve the pump by pulling the tubing.

■

Install a spray metal rod guide in the sucker rod string just above the top of the pump. This guide centers the valve rod in the pump and centers the pump in the tubing. Centering these components helps eliminate sucker rod whip, which can cause the pump plunger and barrel to wear excessively.

■

Install one or more joints of weight bar in the sucker rod string directly above the pump. Weight bar will help prevent the rods from whipping and allow the pump to operate more smoothly.

■

Install rod guides (nylon or plastic) at regular intervals in the sucker rod string to prevent rod whipping and excessive rod and tubing wear. Spacing of guides depends on the deviation of the well. More exotic rod guides are available for crooked wells.

■

Set the pump below the deepest producing coal seam to draw the fluid level below the lowermost perforations (or slots). Because shallow coal seams have very low reservoir pressures, you must decrease the hydrostatic pressure of the fluid column in the wellbore as much as possible to maximize the gas flow rate into the wellbore.

■

Submerge the pump as deeply as possible in the fluid to reduce the amount of gas that enters the pump.

■

Some operators in the Black Warrior Basin set the polished rod clamp so that the plunger bumps the bottom of the pump on the downstroke. “Bumping bottom” can help ensure the travelling valve and standing valve operate properly by keeping valve seats free of debris. However, “bumping bottom” can also subject the rod string to additional stress, which can cause premature rod failure.

6-11

Chapter

6


■

Some operators in the Black Warrior Basin run “no lock” sucker rod pumps to prevent gas locking.

Progressing Cavity Pumps Progressing cavity pumps are relatively new to the oil and gas industry. They have been used extensively for coalbed methane wells in a a number of areas of the Black Warrior Basin. In contrast to the beam pump, which is driven by a reciprocating rod, the progressing cavity pump is driven by a rotating rod. Figure 6-5 shows a progressing cavity pump installed in a well. The progressing cavity pump system consists of a surface drive unit, a sucker rod string, and a subsurface pump. The surface drive unit has an electric motor and sheaves which rotate the rod string and the pump. The key components of the subsurface pump are the rotor and the stator. The rotor is a single external helix with a circular cross-section, precision machined from high-strength steel. The stator is a double internal helix molded of an abrasion-resistant elastomer bonded within an alloy steel tube. As the rotor turns within the stator, cavities progress from the bottom suction end of the pump to the top discharge end, conveying the formation fluid up through the pump and into the tubing. A continuous seal between the rotor and the stator helices keeps the fluid moving at a fixed rate directly proportional to the rotational speed of the pump and the volume of the cavity. Progressing cavity pumps can operate at a wide range of speeds and lift varying amounts of fluids. In addition, progressing cavity pumps usually cost less to install, occupy less space on the surface, and are less visually prominent (a consideration in urban areas) than beam pumps. Both progressing cavity pumps and beam pumps offer distinct advantages and disadvantages. In many cases, the decision to use one system over the other is based on the specific application and the preference of the operator.

Selecting a Progressing Cavity Pump System To select the best type of progressing cavity pump system for your operation, consult a pump specialist who is trained and experienced with progressing cavity pumps. A competent pump specialist will discuss the particular requirements of your field, simulate various producing scenarios, and provide detailed computer analyses of a variety of possible pump designs.

6-12

Pumping Equipment

Figure 6-5 Progressing Cavity Pump

In general, selecting a progressing cavity pump system involves: ❖

Determining the pumping depth, flowline pressure and the desired well production rate

❖

Evaluating the API gravity and pumping characteristics of the formation fluid

❖

Checking pump speed guidelines against formation fluid abrasiveness

6-13

Chapter

6


❖

Evaluating pump compatibility with any chemical additives to be used

❖

Determining the appropriate pump size and operating speed

❖

Determining the proper sucker rod size

❖

Selecting the proper surface drive head

❖

Selecting the appropriate prime mover and drive system

❈ Important Operating experience in the Black Warrior Basin has shown that you should size the pump to run continuously instead of intermittently. Intermittent operation may allow sand or coal fines to settle and plug the pump when you shut in the well. Continuous operation keeps the sand moving up the wellbore. For more information on progressing cavity pumping systems, refer to Additional Resources at the end of this chapter.

Installing a Progressing Cavity Pump These general guidelines will help you to install a progressing cavity pump in the wellbore:

6-14

1.

Attach the pump’s stator to the first joint of production tubing and insert the tubing string into the well.

2.

Run and set the production tubing.

3.

Attach the pump’s rotor to the first sucker rod and insert the sucker rod string into the production tubing.

4.

Install rod guides at regular intervals in the sucker rod string to prevent excessive rod and tubing wear.

Pumping Equipment

5.

Run the sucker rods and gently tag the pin at the bottom of the stator.

6.

Calculate the rod stretch in the rod string.

7.

Position the rotor above the bottom of the stator pin a distance equal to the calculated rod stretch.

8.

Attach the surface drive head to the rod string and the pumping tee.

9.

Attach the prime mover drive system.

10. Connect the power supply.

❈ Important Some operators in the Black Warrior Basin initially install progressing cavity pumps above the perforations to reduce the potential for plugging with coal fines or sand during early production. This method also helps maintains a hydrostatic head on the formation to help prevent surging when pumping the well down after the fracture treatment. As the well gradually cleans up, the pump is lowered closer to the perforations. When the well has completely cleaned up, the pump is lowered below the perforations to minimize the bottomhole pressure and maximize gas flow.

Gas Lift Gas lift is a method of artificial lift that uses an external source of gas to lift formation water from the wellbore. Gas is injected into the wellbore either continuously or intermittently. The injection gas mixes with the water and decreases the flowing pressure gradient of the mixture from the point of injection to the surface. The lower flowing pressure gradient reduces the flowing bottomhole pressure to establish the drawdown required to initiate and maintain gas production.

6-15

Chapter

6


The gas lift system consists of a series of gas lift valves housed in mandrels which are spaced at intervals in the tubing string. Two gas lift injection methods have been used to produce coalbed methane wells. The least common method is to inject gas down the tubing string and produce water and gas up the annulus. The method used more often is to inject gas down the casing and produce water and gas up the tubing string. In either case, aerating the water reduces its density and allows it to flow to the surface where the gas and water are separated. The produced water is then sent to the water disposal system and the methane gas is either recycled to continue gas lifting or sent to the gathering system. Figure 6-6 shows a typical gas lift installation.

Figure 6-6 Gas Lift Installation

6-16

Pumping Equipment

Though not as popular as beam pumps or progressing cavity pumps, gas lift has been used in the Black Warrior Basin with some success. Gas lift can be a particularly attractive method of artificial lift in areas where electric power is unavailable or its cost makes it uneconomical. The main advantages of gas lift are the ability to handle production of solids with little or no mechanical problems and the ability to accommodate a wide range of initial production rates. A major limitation of a gas lift system is the need for a source of compressed gas for initial operation. An additional disadvantage is the need to train field people to operate the system properly. If you install a gas lift system, you can run wireline-retrievable gas lift valves to optimize performance and eliminate the cost of pulling tubing when valve replacement is needed. In 1985, GRI conducted a study to determine the applicability of gas lift to coalbed methane production in the Black Warrior Basin. The study concluded that initiating production of coalbed methane fields using gas lift is more cost effective than using conventional pumping units. The study also showed that as water production declines with time, smaller conventional pumping units may be more economical. For more information on this study, refer to “A Field Evaluation of Gas Lift and Progressive Cavity Pumps as Effective Dewatering Methods for Coalbed Methane Wells.” See Additional Resources at the end of this chapter.

Electric Submersible Pumps Operators in the Black Warrior Basin have successfully used electric submersible pumps to produce coalbed methane wells. However, these pumps have not gained widespread use in this basin because of problems with coal fines and scales. In the Deerlick Creek Field in the Black Warrior Basin, electric submersible pumps have been used successfully in bounding wells to de-water the field. These wells pumped high rates of water but little gas. When these dewatering wells were temporarily shut-in, overall production from the field declined significantly. Continued pumping with electric submersible pumps has increased dewatering of the reservoir and increased gas production from the field.

6-17

Chapter

6


An electric submersible pumping system consists of a downhole electric-powered motor and centrifugal pump assembly. Electricity is supplied to the motor via a cable clamped to the production tubing as it is run in the well. The pump and motor are run on the end of the tubing string. If desired, the speed of the downhole motor and pump assembly can be regulated with a surface control unit. Figure 6-7 shows an electric submersible pumping system.

Figure 6-7 Electric Submersible Pump

6-18

Power Supply for Pumping Equipment

❈ Important Because the motor is cooled by fluid passing down the annulus to the intake of the pump, the pump is normally placed above the producing zone. Alternatively, a shroud can be installed with the pump to direct fluid past the motor if the pump is placed below the producing zone. In any case, the well should never be pumped dry. The main advantages of electric submersible pumps are their ability to lift large volumes of water and their quiet, efficient operation. Two significant limitations of electric submersible pumps are their high cost (both purchase cost and installation/maintenance costs) and their susceptibility to burnout if they run dry. Because electric submersible pumps can effectively lift large volumes of water, they may be especially attractive in wells with high water production. For example, the water level may be high in a wellbore because of additional water influx from a non-coal zone. Similarly, a coal zone with a large permeability may produce water rates that preclude dewatering an extended area with conventional pumping units.

❈ Important

The heat generated by electric submersible pumps can cause severe deposition of scale on the downhole pump. This scale can eventually plug the pump and cause it to burn up. Because scale deposition presents serious problems in some parts of the Black Warrior Basin, electric submersible pumps may not be practical in these areas. If an electric submersible pump becomes stuck in a well because of sand or coal fines, it is usually difficult to retrieve because the O.D. of the housing on the pump is larger than the O.D. of the production tubing above it.

Power Supply for Pumping Equipment Regardless of the type of pumps you select to produce your coalbed wells, you will need to decide how to power the pumps. You have two basic choices of power supply:

• Natural Gas Power • Electric Power

6-19

Chapter

6


You should base your decision of power supply on both the economic and the operational benefits and limitations of each method.

Natural Gas Power Natural gas may provide the most efficient and cost-effective power source if your field is in a remote area without nearby electric power. Natural gas power can provide these benefits: ❖ May have lower initial cost ❖ Can use low-cost natural gas produced on location ❖ Eliminates lengthy and costly negotiations with power companies

When compared to electric-powered pumps, natural gas-powered pumps also have several disadvantages: ❖ Require higher maintenance ❖ Require a backup gas supply ❖ More susceptible to vandalism and theft ❖ Cold weather may interrupt gas supply

Electric Power Electric power may provide the most efficient and cost-effective power source if your field has ready access to existing power lines. In the Black Warrior Basin, most operators use electric power because it requires relatively little maintenance and its cost can be amortized over several years with the power company. In most cases, electric power can provide these benefits: ❖ Requires low initial capital cost ❖ Provides a more reliable power supply

6-20

Power Supply for Pumping Equipment

❖ Requires lower maintenance ❖ Produces no air pollution ❖ Provides quieter operation ❖ Contains few parts that can be stolen

When compared to natural gas power, electric power also has several disadvantages: ❖ May require a higher initial cost if you install your own distribution system ❖ May require access rights-of-way for power lines

Methods for Installing Electric Power In general, you can supply electric power to your field by either:

• Installing Your Own Power Lines • Utility Company Installation Installing Your Own Power Lines

If electric power is available nearby, you may choose to install your own power distribution network in the field and then connect it to the local utility system. The operator of the Rock Creek project in the Black Warrior Basin elected to install such a field network. The operator estimates the total cost to clear right-of-ways and install the network at approximately $35,000 per mile of power line. If the field contains several wells grouped fairly closely together, you may consider taking delivery of the electricity from the power company at a single point and then installing your own secondary lines to the individual wells. This may be the most economical method because you have only one meter and therefore incur only one demand charge from the power company. The primary factors you should consider in installing your own lines are:

6-21

Chapter

6


❖ Initial cost for equipment and installation ❖ Cost to obtain and clear rights-of-way ❖ Ongoing cost to maintain the network ❖ Requirements for inspection by local government agencies and the utility company ❖ Taking delivery of electricity at a single point (i.e., one meter) to lower the demand charge

Utility Company Installation

The alternative to installing your own field power network is to to have a local utility company supply service to the field. The utility company could either provide individual power lines to each well site based on a well’s estimated power needs or it could provide service connect/disconnect boxes on poles placed at selected points throughout the field. The primary factors you should consider when having a utility company install a power network are: ❖ Total cost for equipment and installation, and how payment will be structured ❖ Rates for usage of electricity, including any minimum charge ❖ Responsibility for maintenance of lines ❖ Scheduling of installation to meet production needs ❖ Inspection requirements of the utility company before beginning or expanding service ❖ Union requirements of the utility company for connecting or disconnecting equipment (e.g., Are electrical specialists required?)

6-22

Surface Production Facilities

Surface Production Facilities Most of the surface facilities and equipment used to produce coalbed methane wells is the same as that used in conventional oil and gas wells. However, coalbed methane fields present some unique problems such as very low reservoir pressures and gas saturated with water. Operating experience in the Black Warrior Basin has provided many practical guidelines to help you select equipment that can eliminate problems inherent in producing a coalbed methane field. This section explains common production operations problems and how to select the proper equipment to overcome these problems. The section discusses the equipment you will need for:

• Collecting and Measuring Water • Collecting and Measuring Gas

Collecting and Measuring Water To produce coalbed methane wells, you must continuously lift water from them and collect, measure, and dispose the water at the surface. The success of a coalbed methane project depends largely on the effectiveness of the water treating and disposal system. For information on treating and disposing produced water, refer to Chapter 8. The flow path of water in a coalbed methane field is similar to that in most conventional oil fields. Figure 6-8 shows a typical water flow path for coalbed methane fields in the Black Warrior Basin.

The Water Flow Path Water drains from exposed formations into the wellbore and collects in the sump at the bottom of the well. Then the water enters a downhole pump (usually a plunger pump or a progressing cavity pump) and is lifted through production tubing to the surface. Next, the water passes through a flowline to a two-phase separator, which removes entrained gas in the water. The gas vapors vent at the top of the separator and the water exits at the bottom and flows through polyethylene or polyvinyl chloride (PVC) underground lines to water treatment pits.

6-23

Chapter

6


Figure 6-8 Typical Water Flow Path for Fields in the Black Warrior Basin

Equipment for Solving Water Production Problems You will likely encounter several problems when producing water. Solids in water lines can cause significant inaccuracies in meters and malfunctions in pumps. Freezing temperatures can prevent you from obtaining water production data and cause permanent damage to wellhead equipment, pipes, and meters. Gas or air in the water line can impede water flow and cause inaccurate meter readings. Such water-related problems can greatly increase the costs for meter and pump repair, rig time, and maintenance labor. You can avoid many of these problems by selecting the proper equipment. Solids in Water Lines

Water produced from coalbed wells, especially during early production, usually contains some coal, sand, or other rock fines. The water may also contain scale from oxidation of casing and tubing.

6-24


In addition, if formation water contains a large amount of salts, precipitates may form in surface flow lines and further increase the total solids in the water. Except for very large particles, most solids pass through the water production and metering system without difficulty. The solids remaining in the system usually accumulate in the housing chamber of the water meter, which can eventually impair and finally stop the measuring mechanism. Some meters may, however, repeatedly malfunction within several days after installation. Rock material can lodge in valve openings in the downhole pumping mechanism. Usually this material is coal or shale that has sloughed off formations exposed in the wellbore. This material is most likely to plug and stop the downhole pump during the first few days of production, especially after the well has been stimulated.

Solution To prevent large solids from plugging and damaging the surface equipment and meters, install a wire-wrapped screen (the type used in water wells) on the bottom of the pump. Most large pieces of solid debris carried through the tubing settle in the separator. You can remove the remaining solids suspended in the flow system by installing a strainer downstream of the separator and upstream of the water meter. Freezing of Water Lines

Produced water sometimes freezes inside surface lines, restricting flow and causing leaks. Extended freezing weather conditions can permanently damage wellhead equipment, pipes, and meters. Gas-producing coals are normally several hundred feet deep, and the water produced is usually warmer than winter surface temperatures. However, if you control pumping with a timer, there are times when no water is moving through surface lines. Water remaining in the lines during these periods cools rapidly and may freeze.

Solution To prevent freezing, wrap surface lines with electric heat tape and then cover them with waterproof insulation. In areas where severe and prolonged freezing temperatures are common, bury water lines below the frostline. In addition, place meters, water filters, and separators inside small, insulated houses. Further, you can install heat lamps inside the buildings as a simple, effec

6-25

Chapter

6


tive, and inexpensive prevention against freezing. Ventilate all houses, especially those using heat lamps.

▲ Caution Use only fixtures and wiring approved and appropriate for such equipment enclosures.

Gas in Water Lines

Gas passing through positive-displacement water meters or turbine meters is measured as water and may account for significant errors in production records. Gas enters water flow lines either dissolved in the water or as free gas drawn directly into the tubing by the downhole pump. Improper pump cycle settings or continuous pump operations which lower water level in the wellbore to the bottom of the pump cause gas to be drawn directly into the tubing and pumped to the surface. This gas in the water can cause large errors in metered water measurements. Tests conducted at wells where fluid levels were known to be at or near the base of the downhole pump show meter readings from 20 to 75 percent greater than the actual volume of water produced.

Solution You can remove gas from the water line and improve water meter accuracy by installing a separator in the surface water flow system. Alternatively, you can install a simple 30 to 50 gallon vented separation tank.

Air Trapped in Water Collection Lines

Air can enter water collection lines at high points in the line. This problem may be more severe when wells are pumped intermittently because of long periods of no water movement through the lines. When pockets of air or entrained gas are trapped in the water line, they compress much like a spring, preventing the water from moving through the line.

Solution Install a vacuum breaker device at high points in the water line. A vacuum breaker prevents a vacuum lock from stopping water flow in the line and releases air trapped at high points in the line.

6-26


Measuring Water Flow Rates You can use several different methods to measure the flow rate of produced water. Operators in the Black Warrior Basin commonly use these methods:

Bucket Test The simplest test involves measuring the amount of time a well takes to fill a five-gallon bucket. You then convert the 5-gallon rate to a barrels per day rate by using this formula:

Barrels Per Day = 0.119 x

(

24 Minutes to fill 6 0

)

By recording bucket tests over a period of time, you can determine the efficiency of the downhole pump and tell whether or not a well is being pumped off effectively. At the Rock Creek project, an automatic bucket test system was installed at each well site. In this system, the “bucket” consists of half a standard 55-gallon drum. The drum collects water from the outlet of the water dump on the separator. A liquid level controller is connected to a small pump, which pumps the water from the drum into the water gathering system. A counter is connected to the liquid level controller to record the number of times the drum is drained each day. The equation below can be used to determine the daily water production based on the number of times the drum is drained each day. Barrels Per Day = h x D2 x N 7.15 Where: h = height between the dump line on the bucket and the float, ft D = diameter of the bucket, ft N = number of dumps per day

Positive-Displacement Meter A positive-displacement type meter can be installed in the flow line. This type of meter is inexpensive and can be used when no power is available in the field. However, water meters are generally ineffective in coalbed meth-

6-27

Chapter

6


ane fields because small amounts of coal fines, sand grains, or fracturing gel can easily plug the meter.

Turbine Meter This meter is essentially a water meter with turbine blades that is installed in line. Turbine meters can be sized for the rate and volume of flow expected. Like the positivedisplacement meter, the accuracy of the turbine meter is severely impaired by debris and flow rates outside the operating range of the meter.

Selecting Other Equipment for Water Production These guidelines will help you to properly select other equipment for producing water in a coalbed methane field: ■

When practical, install separators at each well site instead of piping all produced water directly to a central separation facility. Water carries fines and sludge that can cause plugging. The more water you can remove at the well site, the less plugging problems you will have downstream.

■

Select water pipelines with a large enough diameter to carry the estimated volume of produced water and to minimize frictional pressure losses, which increase backpressure at the wellhead.

▲ Caution Flow lines that are too large in diameter can cause solids to drop out of the water and create plugging problems. A pipe partially full of water will tend to plug more easily than a pipe full of moving water. To prevent solids from settling in the flow lines, the flow velocity should be a minimum of 3 ft/second.

■

6-28

If the frictional pressure losses from flow lines creates excessive backpressure on the surface water facilities, you can install booster pumps at the well sites to move the water through the lines and reduce wellhead pressure.


Collecting and Measuring Gas Collecting and measuring gas in a coalbed methane field is much the same as in a low-pressure oil field. You will find many similarities in the flow path of the fluids, the production equipment, and the operational problems.

The Gas Flow Path Coalbed methane wells usually produce gas through the casing/ production tubing annulus. The wells normally produce under minimum back-pressure to optimize gas desorption from the coal and drainage of the water. Once gas reaches the surface, it is normally piped to a two-phase separator, which removes remove water from the gas. (Alternatively, the gas can be piped directly into the gas gathering system to reduce backpressure on the casinghead.) Then the gas flows through an orifice meter with a 3-pen chart recorder where it is measured. Next, the gas is piped through a field collection line to a gas scrubber, which removes any remaining water before the gas enters the compressor. Finally, the gas exits the compressor, flows through a dehydrator and sales gas meter, and finally, into the sales gas pipeline. Figure 6-9 shows a typical gas flow path for fields in the Black Warrior Basin.

Equipment For Solving Gas Production Problems You will likely experience several problems when producing coalbed methane gas. Gas produced from coalbeds contains water vapor that condenses and collects along various points in the gas line, including the meter. Water build-up decreases meter accuracy and can damage working components. The effects of even small amounts of water in gas lines are most pronounced during periods of freezing weather. In addition, rock fines accumulate within the gas meter over time, causing measurement inaccuracy and possibly damage to the meter. Water in Gas Lines

The moisture content of coalbed gas has to be sufficiently low to assure accurate measurement of gas flow. In addition, coalbed gas sold commercially must meet requirements of purchase agreements, which usually limit the water content to approximately 7 pounds of water per million cubic feet of gas measured at standard temperature and pressure. As warm coalbed gas cools at the surface, it loses some of its ability to carry water and the water therefore condenses. The water con-

6-29

Chapter

6


Figure 6-9 Typical Gas Flow Path for Fields in the Black Warrior Basin

densate accumulates at low points along the pipeline and in gas meters. You will encounter this problem most frequently during winter months when differences between gas temperature and surface temperature are greatest. Water also separates from gas when the gas passes from a smaller to a larger diameter pipe, which reduces gas flow velocity. Therefore, water often accumulates in areas where pipe diameter changes. Finally, water condenses from the gas stream at angled sections along flow lines and at meter locations where there is turbulent flow.

Solution Install a separator at the well site to remove entrained liquid from the gas stream. The closer you place the separator to the well, the less is the potential for water and solids to disturb gas flow and measurement further downstream.

6-30


Also, install drips at low points in the gas lines to remove liquid from the gas stream or liquid that has accumulated in the pipeline. A drip is simply a 10-15 foot length of pipe tied into the line. The drip collects water in the line and allows drainage of the water through a valve in the pipe. Drips are available in two styles: manual or automatic. You must periodically open a valve and drain a manual drip. Automatic drips operate with a float system that automatically dumps the collected water when it reaches a pre-set level. Freezing of Gas Lines and Meters

Problems with water in gas lines increase during periods of low temperature because conditions for condensation are intensified. The problem becomes severe when temperatures drop below freezing. Even small amounts of ice in gas flow lines increase backpressure and reduce gas production. Ice can also form in gas meters and severely damage the instruments.

Solution To prevent ice formation in gas lines near the wellhead, wrap the lines with electric heat tape and then cover them with waterproof fiberglass insulation. In addition, equip well sites with small insulated meters houses that contain heat lamps. Be sure to adequately ventilate the meter houses. Finally, increase the number of routine field inspections during especially cold weather to assure minimum condensate build up. Solids in Gas Lines

Under normal flowing conditions, particles of rock or other solid material accumulate in most gas meters over time. If you do not correct this problem, solids will eventually cause any type of meter to malfunction. Rotary meters are the most susceptible to malfunction because of close tolerance between components of the rotating cartridge. Diaphragm meters usually continue to operate with small amounts of solids build-up, but meter accuracy diminishes as portions of the meter’s measuring reservoir fill with solids. Turbine meters normally allow very small material (less than one millimeter in diameter) to pass through its inner mechanisms.

Solution To prevent solids from plugging meters, install a cartridge-type filter with a fiberglass filtering element or a linestrainer (a steel cartridge containing numerous 3/64-inch holes).

6-31

Chapter

6


These commercially available filters are designed to remove fine solid particles with very little pressure drop (0.5 psig or less). Install the filter as close to the wellhead as possible using a “Y” connection. Put a small ball valve on one leg of the “Y” so you can periodically blow the filter to atmosphere to clean it. Pressure Fluctuation in Gas Lines

Because coalbed methane wells usually produce at low pressures, the flowline pressure can fluctuate considerably when downstream pipeline conditions change (e.g., compressor shut-down, or slugs of water in the collection line). These pressure fluctuations can cause severe inaccuracies in gas meter readings.

Solution To maintain a steady line pressure at the gas meter, install a backpressure regulator just downstream of the meter. Set the regulator at a pressure just slightly higher than the line pressure.

Selecting a Gas Flow Meter Most coalbed methane operators use orifice meters or turbine meters to measure gas flow rates. Table 6-2 lists the benefits and limitations of these meters.

Table 6-2 Comparison of Gas Flow Meters Type of Meter

Benefits

Limitations

Orifice Meter

Continuous chart provides record of well events

Requires person to change chart

Requires less maintenance AGPA standard for gas sales

Turbine Meter

6-32

Provides quick, easy readout

Does not provide record of well events

Provides highly accurate instantaneous readings

Highly sensitive to liquids, fines, and sludge


Measuring Sales Gas

After gas exits the compressor discharge scrubber, it flows through a dehydrator and a sales gas meter, and then enters the gas purchaser’s pipeline. Typically, the gas sales contract bases measurement of gas volume and temperature on the primary sales meter at the point of sale into the pipeline. Gas contracts sometimes require the producer to maintain a duplicate meter downstream of the compressor. The duplicate meter is used as a check against the primary meter and in case the primary meter fails. To ensure consistent measurements, both meters are usually maintained and calibrated regularly by one independent gas measurement company. The gas purchaser pays the producer based on the BTU content of the sales gas, which the purchaser calculates from measured properties of the gas. The gas sales contract specifies precise ranges for the gas properties and measurement conditions. Table 6-3 shows specifications for a typical gas sales contract in the Black Warrior Basin.

Table 6-3 Typical Sales Gas Specifications Specification

Value

Pressure Basis

14.73 psia

Temperature Basis

40 - 120°F

Maximum CO2 Concentration

3.0%

Maximum O2 Concentration

1.0%

❈ Maximum Sulphur Concentration

200 grams/MMSCF

❈ Maximum H2S Concentration

10 grams/MMSCF

Maximum Water Content

7 lbs/MMSCF

Minimum BTU Content (Dry Basis)

950 BTU

Solids Content

Free of dirt, sludge, etc.

❈ = Extremely Important specification

6-33

Chapter

6


Selecting Other Equipment for Gas Production The guidelines below will help you to properly select other important equipment for producing gas from a coalbed methane field:

■

If the compressor discharge scrubber cannot dry the gas to the required sales gas specifications, you can install a glycol dehydrator to further dry the gas. A glycol dehydrator circulates gas up through liquid glycol, which has an affinity for water. The water in the gas adheres to the glycol, which is then heated to evaporate the water. The de-watered glycol then recirculates back through a tower to remove more water.

■

Install a manual globe-type valve on the wellhead to regulate gas flow rate and to control well surging.

❈ Important

Do not install a plate-type valve on the wellhead. Production of any solids can quickly erode the seat on a plate valve.

■

When practical, avoid installing gas flow lines across low areas. Attempt to place lines on level or only slightly sloping ground to prevent water from accumulating in the lines.

■

Install a gas flare stack on the well site to vent gas during a pilot test program or during an emergency in a producing field.

▲ Caution

6-34

Never vent gas without the approval of the oil and gas agencies and environmental agencies in your area.

■

Install a gas scrubber (small separator) upstream of the inlet to the gas compressor to prevent water from entering and damaging the compressor.

■

If the gas scrubber will not drain quickly enough by gravity, you can install a small pneumatic pump and water level

Gas Compressors

controller on the scrubber to prevent water from filling it and then entering the compressor. This type of pump is especially effective in handling slugs of water, which are common in coalbed methane production.

■

When installing the separator, install a bypass line around the separator. This bypass will allow you to re-route gas when you need to work on the separator. More importantly, it will enable you to bypass the separator later in a well’s life when the water contains little entrained gas. By bypassing the separator, you can lower wellhead pressure and reduce leaking on the stuffing box.

Gas Compressors Because methane gas produced from coal seams has little natural pressure, you must compress it to a higher pressure before it can be delivered to a pipeline for transportation and sale. Compression equipment used for conventional natural gas production can be easily adapted to the requirements of coalbed methane production. Selecting an efficient, reliable compressor package requires a basic understanding of the various types of compressors and the unique characteristics of coalbed methane production. This section explains the design, benefits, and limitations of the types of compressors and drivers (compressor engines) commonly used to compress coalbed methane gas. It also presents important guidelines for selecting auxiliary compressor equipment.

Types of Compressors The two basic types of compressors commonly used for coalbed methane production are rotary compressors and reciprocating compressors. Both types are positive displacement compressors that increase the pressure of gas by reducing its volume. Each type has its own advantages and disadvantages .

Rotary Compressors The rotary design uses either vanes, lobes, or screws which rotate within a casing to compress and displace gas. The principal advantage of this design is its ability to compress large quantities of low pressure gas. The rotary compressor is particularly suitable for

6-35

Chapter

6


coalbed methane production as the first stage compressor in a gathering system. These units are compact, have a lower initial cost than a reciprocating unit, and are simple to maintain. The rotary compressor is at a disadvantage, however, when you need a higher discharge pressure or when you encounter large pressure differentials or pressure fluctuations in the gas line. Because of its valve-less design, the rotary compressor always compresses gas to its designed discharge pressure, regardless of the line pressure. Therefore, the rotary compressor is less efficient than a reciprocating unit when you operate at pressure conditions other than those for which it was designed.

Reciprocating Compressors The reciprocating compressor consists of a piston moving back and forth within a cylinder. Each stroke displaces a positive volume. Spring-loaded valves open whenever a pressure differential exists across the valve. When the valve opens, suction gas automatically enters the cylinder and discharge gas exits. The reciprocating compressor is the most widely used of all compression equipment. Although it is more complex than a rotary unit, the reciprocating compressor operates more efficiently and can accommodate higher discharge pressures, greater pressure differentials, and fluctuations in pressure and capacity. You can use a multi-stage reciprocating compressor on coalbed methane projects to meet the entire compression need -- gathering the wellhead gas at low pressure and increasing its pressure up to the pipeline pressure. You can also use it as a first-stage compressor in a gathering system and as a booster to the sales line. Each compressor is designed to handle a specific range of volume, pressure and pressure differential. The cylinder’s piston displacement and and clearance volume determine the compressor’s capacity. By adding clearance volume to the cylinder, you will reduce the compressor’s volumetric efficiency and its capacity. When you need to change the compressor’s capacity or operating pressure, you can adjust the cylinder clearance by setting the variable volume pocket. Because of this adjustment, you can operate a reciprocating compressor more efficiently than a rotary compressor at other than design conditions.

6-36

Gas Compressors

Types of Drivers In addition to selecting a compressor, you must also select the driver, or engine, to power the compressor. For field applications, you have two alternatives for drivers: electric motors or natural gas engines. Although electric motors are simple, reliable, and easy to operate and maintain, the cost of electric power usually dictates using natural gas engines for the savings in fuel cost. Natural gas engines also allow you to adjust capacity by varying engine speed, but regular A.C. motors do not. You can choose from two basic types of engines: high-speed engines and integral engines. High speed engines operate at speeds from 900 to 1800 rpm. You can connect them directly to the compressor with a coupling or by using V-belts (depending on compressor operating speed). Integral engines operate at speeds of 400 rpm and less. The power and compressor cylinders share a common frame and crankshaft. Although they cost more initially than high-speed engines, integral engines are more efficient, more reliable, and cost less to maintain. Some integral engines can be built as a skid-mounted package, but the high-speed design provides more horsepower in less space with less weight than does an integral engine.

Selecting Gas Compressors When selecting a gas compressor, consult a compressor specialist who has experience with low pressure coalbed methane fields. Sizing a compressor for a particular application requires precise calculation of several factors. Compression equipment suppliers can perform computer analyses to determine the best equipment to use for your application. When you meet with a compressor specialist, be prepared to discuss the volumes of gas you expect to produce and compress. Preparing a forecast of gas production for the life of the field will help the specialist assess compression requirements and suggest a variety of options.

Selecting Auxiliary Compressor Equipment In addition to the two primary components -compressor and driver - you may need other accessories to complete the compressor package. These items may include:

6-37

Chapter

6


• Gas scrubbers and pumps • High level shut-down controls • Fuel filters • Solids filters • Pilot devices • Catalytic converters The design of the auxiliary equipment should accommodate your particular operating environment and the characteristics of methane produced from coalbeds. The guidelines below have proven effective in the Black Warrior Basin:

6-38

■

To prevent water from entering and damaging the compressor, you should install a gas scrubber (small water separation unit) on the compressor skid. Because coalbed methane is saturated with water vapor, a production separator may not remove all the water.

■

If the gas scrubber will not drain quickly enough by gravity, install a small pneumatic pump and water level controller on the scrubber to prevent water from filling it and then entering the compressor. This type of pump is especially effective in handling slugs of water, which are common in coalbed methane production.

■

To protect the compressor from damaging slugs of water that might get through the scrubber, install an accurate high level shut-down control on the compressor control panel.

■

If you operate the compressor with a vacuum at the inlet, install a pneumatic pump on the scrubber. If the scrubber has a vacuum on the inside, opening a dump valve will not dump the water, but it could suck air into the system, causing further problems.

Gas Compressors

■

Make sure fuel gas is taken downstream of the compressor discharge, after the gas has been dehydrated. Water can cause significant problems if it enters the engine’s fuel gas system.

■

Install a fuel filtering unit to further protect the fuel from water.

■

To prevent solids from entering the compressor, install a filter screen in front of the gas scrubber. Sometimes particles of coal or sand are carried in the gas stream. If these contaminants enter the compressor, they will wear its internal parts.

■

To prevent excessive loading of the compressor, install a pilot device that can control the suction pressure. A pilot device is a flow regulator that is controlled by pressure. As the pressure in the line to the compressor increases above the suction pressure limit, the regulator restricts gas flow and thus the inlet pressure as well. The loading or required hydraulic horsepower of a given compressor is a function of the volume of gas compressed and the suction and discharge pressures. Because coalbed methane fields produce at such low pressures, a small change in suction pressure can greatly affect the operating performance of the compressor. An increase in the suction pressure can increase the hydraulic horsepower requirements, which can overload the compressor and result in engine failure. Though every compressor is equipped with emergency shut-down devices to prevent high suction pressures, installing a pilot device to regulate suction pressures to the compressor may help eliminate compressor shut-downs due to high suction pressures.

■

If temporary changes in field operating conditions require additional compression, you may consider leasing or purchasing satellite compressors instead of making costly modifications to the main compressor. You can easily move a small, skid-mounted compressor around the field to effectively meet temporary compression demands.

6-39

Chapter

6


■

Check with the state and federal environmental agencies for requirements on gas compressors. Environmental agencies may require that you include catalytic converters on compressors to meet emissions standards for air quality. You may be able to avoid installing catalytic converters by spacing compressors so that their combined emissions do not exceed the regulation limit for a given area. Depending on the size of the compressor, you may also have to obtain a permit from the state environmental regulatory agency before the compressor is installed.

Selecting the proper gas compression equipment for your field is critical to successful coalbed methane production. Once the equipment is installed, you must practice effective maintenance to help ensure consistent compressor operation. For information on maintaining gas compressors and equipment, refer to Chapter 7.

Gas Dehydration Equipment Because coalbed methane gas is produced at relatively low pressures, the gas can contain large amounts of water. This water must be removed to prevent formation of hydrates in the transmission lines and to meet gas contract specifications. The most common method of removing water from gas is by adsorption using liquid dessicants such as glycols. You can use triethylene glycol (TEG), diethylene glycol (DEG), monoethylene glycol (MEG), or ethylene glycol (EG). TEG is used most often because it can withstand higher temperatures without degradation than DEG, MEG, or EG. A glycol dehydrator system is composed of the equipment below:

6-40

❖

Inlet gas scrubber

❖

Glycol-gas contact tower

❖

Glycol heat exchanger

❖

Glycol regenerator

❖

Filter

❖

Glycol pump

Gas Dehydration Equipment

In coalbed methane applications, gas dehydrators are usually installed downstream of the compressor and upstream of the tie-in to the gas purchaser's metering point and transmission line. The gas from the compressor usually flows into an inlet gas scrubber that is installed with the glycol dehydrator system. The purpose of the inlet gas scrubber is to prevent slugs of free water from entering the glycol-gas contact tower. After flowing through the inlet gas scrubber, the gas stream enters the bottom of the glycol-gas contact tower. The inside of the contact tower contains trays or packing which facilitate contact between the glycol and the gas. When the gas contacts the glycol, the glycol absorbs the water in the gas. The dry gas then exits through the top of the contact tower and the water-rich glycol exits through the bottom of the tower. Before the glycol can be re-circulated, the water must be removed from it. Therefore, the water-rich glycol flows from the contact tower into the regenerator, where the glycol is heated (at atmospheric pressure) to evaporate the water. The de-watered glycol is then cooled by flowing it through the heat exchanger. The cooled glycol then flows back into the top of the contact tower to repeat the dehydration process. Glycol circulation rates vary from about 2 to 5 gallons of glycol per pound of water to be removed. You can determine the amount of water that must be removed by subtracting the contract water limit (usually about 7 lbs/MMSCF) from the amount of water present in the gas. The amount of water in the gas can be measured in the field using either a hand-held moisture analyzer or an electronic moisture analyzer. Alternatively, you can estimate water content from dew point correlations for natural gas. The maximum amount of water that may be present in the gas is a function of the temperature and pressure. At a constant temperature, the water content of gas is higher at lower pressures and is lower at higher pressures. Consequently, dehydrating gas at low pressures is both difficult and expensive. To alleviate this problem, you should install dehydrators downstream of the compressor.

Glycol dehydrators are relatively easy to operate and maintain. To ensure efficient operation of the dehydrator, you should periodically check the water content of the outlet gas to verify that it is at or below the maximum allowable value.

6-41

Chapter

6


If gas flow through the dehydrator increases as production from the field increases, you may need to adjust the glycol circulation rate. You should also check the volume of glycol in the system to ensure that excessive amounts of glycol are not being lost. Glycol absorbs a trace amount of gas at relatively low pressures. This gas is burned off in the regenerator. A small amount of glycol may be lost when the gas is burned. In addition, you should periodically check the pH of the glycol. You should maintain the pH of the glycol between 6.0 and 7.5. At lower pH levels, the glycol may decompose. For more information on dehydrating gas, refer to “Engineering Data Book,” listed in Additional Resources at the end of this chapter.

❖

6-42

❖

❖



“API Recommended Practice for Design Calculations for Sucker Rod Pumping Systems (Conventional Units)”, API RP 11L, Third Edition, Dallas (February 1977).

“API Specification for Subsurface Pumps and Fittings, " API Spec 11AX, Seventh Edition, Dallas (June 1979).

“Engineering Data Book,” Natural Gas Processers Suppliers Association (NGPSA), Tulsa, Oklahoma.

Graves, S.L., “A Field Evaluation of Gas Lift and Progressive Cavity Pumps as Effective Dewatering Methods for Coalbed Methane Wells,” Quarterly Review of Methane from Coal Seams Technology, Vol. 3 no. 2 (September 1985).

Klein, S.T., “The Progressing Cavity Pump in Coalbed Methane Extraction,” 1991 SPE Eastern Regional Meeting, Lexington, Kentucky (October 22-25).

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).

“Petroleum Engineering Handbook,” Society of Petroleum Engineers, Richardson, Texas (1987).

Sykes, W.W., “Gathering Systems Concepts-Planning, Design, and Construction,” Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (April 17-20).

6-43

7

Operating Wells and Production Equipment

O

perating coalbed methane wells and production equipment requires some specialized production techniques. These techniques have been learned primarily through trial and error and observation in the field. For example, field experience at the Rock Creek project has shown that the manner in which you flow back a well after stimulation may significantly affect its recovery. Similarly, the procedure you use to pump a well down may influence the productivity of the well. Experience has also shown that you can greatly reduce production downtime by learning to diagnose and correct common production problems. As you gain operating experience in a particular coalbed methane field, you will undoubtedly develop techniques that work effectively in your area. This chapter will help you begin developing effective production strategies. It will guide you through:

• Preparing Surface Facilities for Production • Unloading the Well • Bringing the Well on Line • Troubleshooting Well and Equipment Problems

Chapter

7


Preparing Surface Facilities for Production After the well has been fractured and flowed back, and the pumping unit has been installed, you should check the surface facilities and gathering system to make sure they are ready to receive production from the well. Performing this check before you bring the well on line will help prevent unsafe operating conditions, environmental incidents, and unnecessary downtime to correct facilities problems. The various equipment you need to check may vary slightly from field to field. Regardless of the type of equipment used, this pre-production check should include not only equipment at the wellhead, but also all downstream lines and facilities such as separators, meter runs, gathering lines, drips, water treatment facilities and compressors. Before bringing wells on line, check the guidelines below:

❈ Important

7-2

■

Make sure you have complied with all applicable federal, state, and local safety and environmental regulations. You also may be required to notify certain regulatory agencies in your area of your intent to begin production from the field.

■

Notify the gas purchaser of the date you will begin delivery of gas so they have time to make any necessary preparations or adjustments. In addition, you should make sure the gas composition will meet the contract specifications with the gas purchaser.

■

Make sure flowlines and pipelines have been completed and are properly tied into the appropriate equipment.

■

If separation vessels are used, make sure that the drain valve is closed and that the liquid dump valve has been installed and is working properly.

■

If gas from the separator is to be vented, make sure you install the proper equipment for venting according to regulatory

Unloading the Well

requirements. The type of gas venting equipment needed may depend on where you are operating. Some state oil and gas regulatory agencies require you to vent gas through a flare stack. Contact your local regulatory agencies to find out about equipment requirements such as height and minimum distance from the wellhead.

■

Open all flow valves between the wellhead and separation equipment.

■

Check all gas metering equipment to make sure it is ready to measure gas flow. Though gas flow will likely be small initially, you should pressure test the meter run or metering assembly to make sure no connections are leaking.

■

Check orifice meters to make sure they are fitted with the proper size orifice plate for the volume of gas expected.

■

Check chart recorders or turbine flow meters to make sure they are properly calibrated.

■

Before significant gas flow begins, check the gas compressor to ensure that it has sufficient capacity for the gas. Since the compressor was first installed, loading conditions may have changed because of additional gas production from other wells or variations in suction and discharge pressures.

Unloading the Well After verifying that the surface facilities are prepared for production, you are ready to unload the well fluid to a pit or holding tank and initiate gas production. Operators in the Black Warrior Basin generally use one of two methods to unload coalbed methane wells:

• Injecting Compressed Air or Nitrogen • Pumping the Well Down

7-3

Chapter

7


Injecting Compressed Air or Nitrogen To unload wells and place them on production as quickly as possible after flowing back the fracture treatment, some coalbed methane operators inject compressed air or nitrogen into the wellbore. By injecting air or nitrogen for a day or more, operators can lift all the water out of a well, clean out any solid debris, and initiate gas flow rapidly. Though this method is quicker than pumping a well down, it could possibly damage the coal formation. To prevent damage, you should unload the well slowly. Lifting the fluids with air or nitrogen can subject the formation to a large pressure drawdown. This drawdown could cause migration of coal fines into the created fractures and significantly reduce the permeability of the fractures.

Pumping the Well Down After flowing the well back following a fracture treatment and cleaning out the well to bottom, you can install the production tubing and downhole pump and begin pumping the well down. (For information on downhole pumps, see Chapter 6.) As you pump water out of the well, the reservoir pressure drops and methane starts to desorb, or detach itself, from the surfaces of the coal and flow into the wellbore. Unlike most conventional gas wells, when you shut in a coalbed methane well, you may lose significant gas producing potential. When the well is shut in, water could encroach into the reservoir and raise the reservoir pressure. Before gas production will resume, this pressure must be reduced by once again pumping the well down. When you pump a well down, you create a pressure drop near the wellbore which causes water and gas to flow to the wellbore. The gas saturation near the wellbore may be high initially. Thus, if you bleed off gas from the annulus (thus drawing down the gas pressure) too rapidly, gas and water will surge into the wellbore. The surging water usually carries damaging coal fines through the perforations and into the wellbore.

▲ Caution Bringing a well on production at an excessive flow rate can cause surging in the wellbore, which can plug perforations, pumps and surface equipment. Surging the well may also damage formation

7-4

Unloading the Well

permeability and reduce gas production by plugging fractures with coal fines. Experience at the Rock Creek project has shown that wells can plug with coal fines and sand in as little as 15 to 20 minutes when they are brought on stream too rapidly. Because each coalbed methane well has unique flow characteristics, you should base the rate at which you pump a well down on experience in the field or nearby offset fields. Operating experience at the Rock Creek project and at other fields in the Black Warrior Basin has produced a technique for pumping down wells that minimizes the potential for producing coal fines and sand. You may find this technique useful in your area as well.

Technique for Pumping Wells Down Production experience at the Rock Creek project suggests that bringing new coalbed methane wells on stream slowly offers several benefits: ❖

Fewer well cleanouts

❖

Fewer problems with downhole and surface equipment

❖

Increased gas production over the life of the well

The procedures used at the Rock Creek project to pump wells down are described below: 1.

Keep the annular valve at the surface closed. Make sure the valve on the casing-tubing annulus is a globe valve. You will use this valve to control gas flow while pumping the well.

2.

Begin pumping the well at a rate that begins to reduce the water level in the well.

3.

Closely monitor the water production rate while pumping at a rate near the design capacity of the pump.

7-5

Chapter

7


▲ Caution

❖

If you observe a sharp decrease in the water rate, check the pump to make sure it is operating properly. For information on troubleshooting pumps, refer to Chapter 7.

❖

If the pump is operating properly, run an echometer survey to determine the fluid level in the well.

If you are using a progressing cavity pump, maintain a fluid level above the pump at all times. Allowing the fluid level to drop below the pump could possibly burn up the motor.

4.

Carefully monitor the fluid level by running echometer surveys in the well.

5.

When the water level is at or near the pump intake, crack the globe valve and begin flowing gas at a rate that maintains a fairly constant or only slightly decreasing wellhead pressure. Your goal is to maintain sufficient backpressure on the casing to prevent surging of gas and water into the wellbore. ❖

6.

If the annular pressure decreases sharply when you crack the annular valve, shut the valve and continue pumping the well. After several hours or a day, repeat step 4.

Continue pumping the well at a rate near the design capacity of the pump. Continue to monitor casinghead pressure and adjust the gas flow with the globe valve to maintain a relatively constant (or slowly decreasing) annular pressure.

▲ Caution Do not open the annular valve rapidly. Releasing the gas too rapidly can cause surging of gas and water into the wellbore and plugging with coal fines and sand.

7.

7-6

Continue to pump the well to decrease the fluid level in the well. As annular gas pressure decreases, you may observe an increasing fluid level in the well if water influx from the coal seam is greater than the pump rate.

Unloading the Well

The flow characteristics of each coalbed methane well are different. However, as you gain experience with a particular field or producing area, you will be better able to determine the most effective pumping rates for your wells.

Pumping a Well Down after a Foam Fracturing Treatment If you have fractured a well using a foam fracturing fluid, you may experience problems with foam in separation equipment and flowlines. Most formations can support a column of foam in the annulus. As the pressure in the annulus decreases, the foam bubbles burst, allowing water and any entrained solids to drop out of the foam. As long as the foam degrades in the wellbore, it causes no problem. However, if foam moves up the annulus at a high enough velocity, it can flow from the wellbore into surface production facilities and cause water to accumulate in gas flowlines. If you flow an excessive amount of foam, the foam can fill the water separation equipment and overflow into the gas flowline. Experience at the Rock Creek project has shown that reducing the velocity of the foam by maintaining backpressure on the annulus may help prevent foam from flowing into surface equipment. To pump a well down after treating it with a foam fracturing fluid, follow the same steps explained in Technique for Pumping Wells Down, earlier in this chapter.

❈ Important Foam usually causes greater problems in cold weather because water condenses more readily at lower temperatures. When pumping the well down in cold weather, bleed off annular pressure very slowly to prevent foam from entering the flowline. During warm weather, foam tends to vaporize in surface flow lines, but it still can condense in the field collection lines.

Monitoring Gas Specifications After a Foam Fracturing Treatment If you fracture a well using nitrogen-based foam, you should analyze the produced gas for nitrogen concentration before flowing gas into the sales pipeline. If the nitrogen concentration is greater than the sales gas contract specifications, you will likely need to vent the early gas production at the well site until the nitrogen concentration drops to an acceptable level. If the produced gas is commingled with other gas

7-7

Chapter

7


from the field, the nitrogen concentration may be diluted sufficiently to avoid venting gas.

❈ Important Before venting any gas, you should obtain authorization from the local oil and gas agency and environmental agencies. If the gas contains a high concentration of nitrogen, the BTU content of the gas may not be sufficient to run gas compressors or natural gas-powered pumping units. Therefore, if the nitrogencontaminated gas is the only gas available, you should order a tank of propane gas to power the compressor or pumping units until the nitrogen concentration declines sufficiently.

Bringing the Well On Line After you begin pumping the well and fluids reach the surface, you are ready to flow the well into the production facilities. The procedures below will help bring the well on line: 1.

Adjust the rod linkage between the separator’s float arm and float valve to ensure the outlet valve closes at the bottom of float travel.

2.

Open the valve on the dump line.

3.

Flow the produced water and gas into the separator.

4.

Monitor the liquid level in the separator to ensure that the size of the dump valve is sufficient to discharge flow at maximum expected water flow rate.

5.

Continue to monitor the separator and well frequently during the early production time.

Troubleshooting Well and Equipment Problems Because of the tight economic constraints of coalbed methane production, your ability to quickly diagnose and correct operational problems is essential to success. Though some of the problems may

7-8

Troubleshooting Well and Equipment Problems

be unique to coalbed methane, others are common to most oilfield operations. This section will show you how to recognize and correct common problems with:

• Artificial Lift • Production Tubing • Separation Equipment • Surface Piping • Gas Compressors

Troubleshooting Artificial Lift Problems Producing gas from coal seams requires continuously removing water from the reservoir. Therefore, the artificial lift equipment used to remove water must operate effectively and reliably. This section explains how to diagnose and correct the most common operational problems with the artificial lift methods listed below:

• Beam Pumps • Progressing Cavity Pumps • Electric Submersible Pumps • Gas Lift For a description of each of these methods and their use in coalbed methane wells, refer to Chapter 6.

Troubleshooting Beam Pumps The beam pump, or sucker rod, is the artificial lift method most widely used to dewater coalbed methane wells. The beam pumping system consists of a downhole plunger pump, a sucker rod string, a surface pumping unit (pump jack), and a prime mover (motor). Figure 7-1 shows a typical beam pumping unit.

7-9

Chapter

7


Figure 7-1 Beam Pumping System

You can usually detect most well problems by a significant decrease in gas and/or liquid production. Figures 7-2 and 7-3 will help you to troubleshoot potential problems with beam pumps when production has decreased.

7-10


The guidelines below will help you further diagnose and correct problems with the pump jack, prime mover, and rod string:

■

Make sure the pumping unit is balanced. You can check the balance two ways: • Observe the difference in tension on the drive belt. If the tension on the upstroke is significantly different than the tension on the downstroke, then the unit is probably unbalanced. • Check the amperage on one leg of the pump motor using amperage gauge. If the amperage on the upstroke is significantly different than the amperage on the downstroke, the unit is probably unbalanced.

■

If the pumping unit is out of balance: • Make sure the pumping unit is properly aligned with the wellhead. • Make sure the rod guide is aligned vertically and laterally with the tubing head. • Adjust the counterbalance weights on the pumping unit until the unit operates smoothly. During early production, the water level in the annulus is usually high. Thus, the counter weights should be fairly close to the pivot of the beam. As the water in the annulus falls, you may need to periodically adjust the counter weights away from the pivot to compensate for the increased weight of water on the upstroke of the pump.

■

Reduce wear on the sucker rod string by: • Periodically rotating the string 1/4 turn using a wrench or by installing an automatic rotator. This procedure will allow the rods to wear more evenly. • Running a short sucker rod, or “pony rod,” in the string. Then, whenever the string is pulled, re-run the string placing the pony rod in a different location in the string. This procedure will prevent the string from continuing to wear in the same places.

7-13

Chapter

7


• Running nylon rod guides on the rod string. You may run the guides on every rod joint or on every other joint, depending on the amount of rod wear expected. Because the bottom portion of the hole is usually the most crooked, rods in this area usually wear the most.

■

To determine if the sucker rod string has parted, check the needle valve on the pumping tee (wellhead assembly). If there is no fluid production and the needle valve alternates blowing and sucking air, then the rod string is likely parted.

■

Reverse the rotation of the motor every year by reversing the electrical leads to the motor. This procedure will help the gears to wear more evenly.

■

Lubricate the pumping unit every 30-60 days or as specified by the manufacturer.

■

Change oil in the gearbox once a year. When you change the oil, check for water in the bottom of the gearbox, and remove any water.

Troubleshooting Progressing Cavity Pumps The progressing cavity pump is probably the second most widely used method of artificial lift for coalbed methane wells. The progressing cavity pump is used extensively in a number of areas in the Black Warrior Basin. The progressing cavity pump system consists of a surface drive unit, a sucker rod string, and a subsurface pump. The surface drive unit has an electric motor and sheaves which rotate the rod string and the pump. The key components of the subsurface pump are the rotor and the stator. The rotor is a single external helix with a circular cross-section, precision machined from high-strength steel. The stator is a double internal helix molded of an abrasion-resistant elastomer bonded within an alloy steel tube. As the rotor turns within the stator, cavities are formed which progress from the bottom, suction end of the pump to the top, discharge end, conveying the formation fluid up through the pump and into the tubing. A

7-14


continuous seal between the rotor and the stator helices keeps the fluid moving steadily, at a fixed rate directly proportional to the rotational speed of the pump.

❈ Important Progressing cavity pumps will burn up if they are not submerged in fluid. Therefore, you must periodically check the fluid level in the well using an echometer device. You can then adjust the speed of the pump or change the size of the pump to ensure that the pump remains submerged in fluid. Figure 7-4 will help you to troubleshoot potential problems with progressing cavity pumps when you notice production has declined below expected levels. For more information on progressing cavity pumps, see Additional Resources at the end of this chapter.

Troubleshooting Electric Submersible Pumps Many specialized techniques have been developed for troubleshooting electric submersible pumps. For information on these techniques, refer to Petroleum Engineering Handbook and The Technology of Artificial Lift Methods, Vol. 2a . See Additional Resources at the end of this chapter.

❈ Important The heat generated by electric submersible pumps can cause severe deposition of scale on the downhole pump. This scale can eventually plug the pump and cause it to burn up. Because scale deposition presents serious problems in some parts of the Black Warrior Basin, electric submersible pumps may not be practical in these areas.

Troubleshooting Gas Lift Installations Many specialized techniques have been developed for troubleshooting gas lift installations. For information on these techniques, refer to Petroleum Engineering Handbook andThe Technology of Artificial Lift Methods, Vol. 2a . See Additional Resources at the end of this chapter.

7-15


Planning for Pump Repairs Regardless of the type of pump you select, the pump will eventually require repairs. The guidelines below will help you minimize production downtime when a pump does go down.

■

Keep spare pumps on hand to avoid production downtime and workover rig time. Rebuilding pumps in the field is not as effective as installing a pump rebuilt in the shop.

■

When selecting people to service your pumps, call only on those with experience in repairing your particular type of pump.

■

For a plunger pump that is relatively new, you may be able to clean the check valves, replace rings or cups, and re-run the pump. However, you should send older pumps to the shop to make sure internal parts are not excessively worn. The shop will check the tolerances of internal parts with a micrometer to make sure seals are good and the pump is operating efficiently.

■

Be prepared to repair pumps more frequently during the early production period of new wells. As production of solids decreases with time, pump repairs will likely become fewer.

Production Tubing Leaks in the production tubing string can reduce pumping efficiency and decrease gas flow up the tubing/casing annulus. One of the most common problems is connections that leak while under external or internal pressure. You can alleviate this problem by avoiding the following actions: ❖ Failing to sufficiently inspect each length of tubing and its connections ❖ Applying improper torque to the connections

7-17

Chapter

7


❖ Failing to clean the threads properly before making up a connection ❖ Galling the threads by carelessly stabbing, making up too rapidly, using a damaged connection, over-torquing, or wobbling pipe during makeup ❖ Dropping a string, even a very short distance ❖ Excessively making up and breaking out connections ❖ Mishandling tubing during transportation or at the well site To extend the life of tubing strings at the Rock Creek project, whenever a string is pulled, it is run back in the well in the reverse order. Thus, joints that were located near the top of the string end up near the bottom. This procedure prevents the sucker rod string from wearing excessively in the same locations. You can achieve the same goal by running a pup joint of tubing in the string, and changing the location of the pup joint whenever you pull the tubing string.

Detecting Tubing Leaks If you suspect a leak in the tubing string, you can use the simple procedure below to detect with reasonable certainty whether the tubing has a major leak. 1.

Check the pressure on the annulus.

2.

Check the pressure on the needle valve on the pumping T.

3.

If the pressure on the annulus and on the pumping T are the same, or if both are on vacuum, the tubing likely has a leak.

To distinguish a tubing leak from other possible well problems, refer to Figures 7-2 and 7-3. To detect tubing leaks when you pull the tubing string, check for obvious cuts or holes, but also look for telltale water stains on the

7-18


outside of the tubing. Such stains often evidence small leaks that are otherwise difficult to detect. At the Rock Creek project most tubing leaks have been observed in the lower portion of the tubing string because the wellbore is usually more deviated near the bottom. Wellbore deviation problems, and thus the number of tubing leaks, generally increase with depth.

Separation Equipment Most problems with separation equipment are caused by deposition of solids in vessels or their components. The guidelines below may help you prevent many of the plugging problems caused by solids: ■

Periodically clean out the separator. If you observe sludge in the bottom of the separator, clean out the vessel immediately.

■

Make sure check valves on separators are working properly. When a check valve is working properly, you should hear a clicking sound as fluid passes through the valve.

■

Periodically flush out dump valves and check the valve seats to make sure they seal properly. Also check the float mechanism to make sure it operates properly. If the float is not cleaned regularly, it can stick and cause the separator to overflow liquid into the gas line.

Surface Piping To ensure trouble-free operation of instruments and meters used to measure flow, you should prevent fines from entering the gathering system. If gas carries even a small amount of fines, the velocity of the gas will quickly abrade or plug turbine meters and orifice plates. Operating experience at the Rock Creek project has shown that you can significantly reduce maintenance costs by removing fines at the wellhead before they can move into the collection system. You can effectively control fines by installing a very fine mesh in-line filter at the wellhead. A screen will protect downstream equipment, such as orifice meters, turbine meters, etc.

7-19

Chapter

7


These additional guidelines below will help you to maintain the surface piping system: ■

▲ Caution

Periodically flush out surface flowlines and collection lines with water to prevent buildup of sludge in the lines. You can often detect buildup of sludge by a pressure increase at the wellsite pump used to move water through the collection line. Be prepared to flush flowlines and collection lines with water if you flow back a well that has been acidized. The acid can loosen accumulated sludge in lines and cause plugging of downstream equipment.

■

Periodically check vacuum breakers in water lines to make sure the seat is clean so it will operate properly. If the seat is not clean, you may see water flowing out of the orifice in the vacuum breaker.

■

Periodically check drips to make sure they are not plugged. Check the float mechanism in automatic drips to make sure it is not stuck. During colder weather or after well stimulations, you may need to check drips more frequently because of the greater amount of water in the gas stream.

Gas Compressors The gas compressor is perhaps the single most important equipment in a coalbed methane field. Because coalbed methane is produced at such low pressures (1/2 - 30 psi in the Black Warrior Basin), it will not flow naturally into the pipeline. Thus, without an effectively operating compressor, you simply are unable to sell coalbed methane gas. Compared to gas compression in conventional gas fields, coalbed methane gas compression is simpler in some ways. Because coalbed gas is approximately 98% methane, it contains no heavy hydrocarbons, which can damage compressor valves.

7-20

Gas Compressors

The greatest challenge in compressing coalbed methane is effectively removing water from the gas before compressing it. You can solve this problem by selecting proper gas dehydration equipment. For information on selecting compressors and compressor equipment, refer to Chapter 6. To ensure your compressor operates efficiently and continuously, you must practice a consistent maintenance program. The best maintenance program is probably the one recommended by the compressor manufacturer. However, as you gain experience with your field, you will likely learn additional maintenance practices that prove useful as well. Compressor operators in the Black Warrior Basin generally follow two separate maintenance schedules - an engine maintenance schedule and a compressor maintenance schedule. They have found the maintenance guidelines below especially effective in preventing compressor problems:

Maintaining the Compressor Engine ■

Change the engine oil and filter every 1000 hours of operation (approximately every 42 days).

■

Check the tolerance of engine valves to detect wear. By monitoring valve wear, you can estimate when downtime will be required for engine repair. This forecasting will help you to coordinate other necessary field repairs.

■

Torque the bolts which anchor the engine to its pad to maintain proper alignment of the engine and the compressor.

■

Plan maintenance work so that all necessary work can be performed at the same time to reduce downtime and well shut-ins.

Maintaining the Compressor ■

Change the compressor oil about every 6 months. Change oil filter every 1000 hours of operation.

7-21

Chapter

7


■

Send a sample of the used compressor oil to a testing laboratory to have it analyzed for contaminants. Contaminants in the oil, such as metal particles, may indicate the wearing and potential failure of internal components or leaking seals or gaskets.

■

Check the tightness of all external bolts on the compressor every 1000 hours of operation. Tighten any loose bolts to their proper torque. The constant vibration of the unit during operation can cause bolts to loosen.

■

Check the tolerance of compressor valves to detect wear about every 3 months. At the same time, check the tolerance of the rider bands on the pistons to detect wear.

■

Inspect the operation of relief valves monthly for safety.

The first step in preventing compressor failure is to install proper equipment. For information on selecting compressors and compressor equipment for coalbed methane production, refer to Chapter 6.

❖

7-22

❖

❖



Brown, K.E., "The Technology of Artificial Lift Methods, Volume 2a,” Penwell Publishing Company, Tulsa (1977).

American Petroleum Institute, “Recommended Practice for Care and Use of Subsurface Pumps,” API RP 11AR, Third Edition, Washington, DC (June 1989).

American Petroleum Institute, “API Specification for Subsurface Pumps and Fittings, ” API Spec 11AX, Seventh Edition, Dallas (June 1979).

Klein, S.T., Robbins & Myers, Inc. “The Progressing Cavity Pump in Coalbed Methane Extraction,” SPE Paper 23454, presented at the 1991 SPE Eastern Regional Meeting, Lexington, Kentucky (October 22-25).

Society of Petroleum Engineers, “Petroleum Engineering Handbook,” Richardson, Texas (1987).

7-23

8

Treating and Disposing Produced Water

M

anaging produced water is critical to the successful development of a coalbed methane project. Some operators have initiated projects and invested great time and money in drilling and completing wells, but initially failed to sell any gas because of problems in disposing produced water. Because water treatment and disposal can represent a large portion of daily operating costs, improper planning of this operation may result in unexpected costs which can impair the economics of an otherwise profitable project. Water disposal problems often stem from not carefully investigating the character of the produced water, treatment and disposal options available, the costs of the various options, and the regulatory requirements that govern those options. A geological and engineering evaluation at the outset of the project can help prevent many waterrelated problems. This chapter provides an overview of the main issues you should consider in developing a plan to manage produced water.

• Characteristics of Coalbed Methane Produced Water • Regulations and Permitting for Water Disposal • Considerations for Designing a Water Disposal System • Methods for Treating and Disposing Produced Water

Chapter

8


Characteristics of Coalbed Methane Produced Water In the Black Warrior Basin, gas usually begins to flow from a well 1-30 days after dewatering has begun. Some wells, though, may require pumping for several weeks or months to initiate methane flow. Within the first month of a well’s life, water production usually decreases by as much as 70%-90% of initial rate before stabilizing to a slow decline. At some point, this decline normally reaches a plateau for the rest of the well’s life. The time required to reach a steady water rate depends on the size of the reservoir and the well spacing. The larger the reservoir and the greater the well spacing, the longer will be the dewatering period . The rate of water removal from a coalbed methane well usually depends on geologic features, formation permeability, completion methods, and the size of the pumps used. Water production from a typical degasification well is usually greater at the start of pumping and decreases gradually as the seam is dewatered. This water production scenario appears to apply to wells that produce both initial high and low volumes of water (Kuuskraa and Brandenburg, 1989; Simpson, 1989). Varying qualities and quantities of water are co-produced with methane gas. Many factors affect the quality of produced waters; however, the type and depth of coal seams have the greatest influence. In general, waters produced from deeper coals appear to be more mineralized than waters from shallow coals, which are more likely to have hydraulic connections with less mineralized shallow groundwaters (Burkett, Hall, and McDaniel, 1991). The quality of water produced from coalbed reservoirs varies widely from region to region. In some areas, the quality of the produced water is comparable to that of drinking water. The principal constituent influencing the quality of coalbed methane waters is the concentration of total dissolved solids (TDS), which includes the concentration of chlorides. Total dissolved solids concentrations range from 500 to 27,000 mg/l in waters generated in the eastern United States, and from 200 to 4,000 mg/l in the western United States (Lee-Ryan et al., 1991).

8-2

Characteristics of Coalbed Methane Produced Water

Scale from Coalbed Methane Water Scale is the product of precipitation and crystallization of minerals from produced water. The formation of scale in the wellbore and in production facilities can restrict flow and damage equipment. The factors that affect deposition of scale are: ❖

Mingling of incompatible waters

❖

Contact time

❖

Temperature change

❖

Pressure drop

❖

Evaporation

❖

Agitation

❖

pH

One or more of these factors can cause scale deposition in the formation matrix, fractures, perforations, wellbore, downhole pumps, tubing, casing, flowlines, and water disposal systems. In the Black Warrior Basin, scale is frequently found in downhole pumps and it has been observed on perforations by downhole camera. In most cases, this scale is caused by pressure drop and agitation. Scaling can cause serious production declines; however, the calcium carbonate scaling in the Black Warrior Basin has been removed by pumping an HCL acid treatment with an iron sequestering agent. In some cases, scale may also form outside casing and in the induced fractures. Scale inside fractures can severely restrict gas flow, and is difficult to remove. The composition of scale depends on the composition of the waters that produce them. The most common scale deposits found in conventional oil fields are calcium carbonate, gypsum, barium sulfate, and sodium chloride. In the Black Warrior Basin, you are most likely to encounter calcium carbonate scale. Calcium Carbonate Scale

Calcium carbonate scale is usually caused by a change in pressure which releases CO2 from bicarbonate ions(HCO3-1). When the CO2 is released from solution, the pH increases, the solubility of dissolved

8-3

Chapter

8


carbonates decreases, and the more soluble bicarbonates are converted to less soluble carbonates. Calcium carbonate scale exhibits these characteristics: ❖

Scaling increases with increased temperature

❖

Scaling increases with increased pH

❖

Scaling increases with increased contact time

❖

Scaling increases with increased turbulence

❖

Scaling increases with water agitation

Calcium carbonate scaling will decrease as the total salt content of water (excluding Ca+ ions) increases to a concentration of 120 g of NaCl per 1000 g of water. Further increases in NaCl concentration will decrease CaCO3 solubility and thus cause scaling to increase. Gypsum Scale

Gypsum scale is composed of calcium sulfate. Gypsum scale exhibits these characteristics: ❖

Scaling increases with a pressure decrease

❖

Scaling increases with water agitation

❖

Scaling is not affected by a pH of 6-8

Barium Sulfate Scale

Barium sulfate scaling is usually caused by the mingling of two unlike waters, one containing soluble salts of barium and the other containing sulfate ions. Barium sulfate scale exhibits these characteristics: ❖

Scaling increases with a temperature decrease

❖

Scaling increases with a pressure decrease

❖

Scaling increases as hydrates evaporate

Iron Scales

Iron scales are often caused by corrosion products such as various iron oxides and iron sulfide. Sulfate-reducing bacteria can produce

8-4

Characteristics of Coalbed Methane Produced Water

hydrogen sulfide, which reacts with iron in solution or with steel surfaces to form iron sulfide. If oxygen is introduced to a system, it can react with iron to form a precipitate or with steel surfaces to form an oxide coating.

Predicting the Scaling Tendency of Water The tendency of coalbed methane produced water to cause scale is usually discovered through experience in an area. Though downhole water samples (recovered at reservoir conditions) can be analyzed to predict downhole scaling characteristics, this type of analysis is rarely performed in coalbed methane operations because of the cost involved in obtaining samples at reservoir pressure and temperature. The analysis of water samples taken at the surface does not allow accurate prediction of downhole scaling. However, you may have a surface sample analyzed to approximate the tendency of a produced water to create calcium carbonate scale. In general, produced water will have a tendency to create scale if the calcium carbonate supersaturation of the water is greater than 10 percent of the bicarbonate alkalinity content.

Identifying Scale You can identify the various types of scale by using these methods: X-Ray Diffraction

The most common method for identifying scale, X-ray diffraction, involves directing a beam of X-rays onto a powdered sample of scale crystals. Because each crystalline chemical compound in the scale diffracts X-rays in a characteristic manner, the scale can be identified. This method requires the least amount of sample. Chemical Analysis

In this method, samples of scale are crushed and then dissolved in chemical solution. The elements are then analyzed by standard titration and precipitation techniques. Effervescence

This method is used to identify calcium carbonate (CaCO3) scale. If a sample is CaCO3, it will bubble when you drop hydrochloric acid (HCl) on it. However, this test may not work if the sample contains iron sulfide or iron carbonate. The odor of sulphur indicates the presence of sulfide scale.

8-5

Chapter

8


Removing Scale Operators in the Black Warrior Basin have used both mechanical and chemical methods to remove scale. The most common mechanical method is reperforating and/or running a bit and scraper through the perforations. The most successful chemical treatment method is pumping HCL acid with an iron sequestering agent.

Preventing Scale In the Black Warrior Basin, an effective method for preventing scale is to pump scale inhibitors in fracturing treatments. Fracturing service companies can recommend an inhibitor for your application. If you encounter a serious scale problem, you may consider continuously treating for scale down the annulus.

▲ Caution Before pumping any chemical into a well, make sure the chemical is tested to ensure it is compatible with the formation water and that it is non-damaging to the coal. Make sure also that the chemical can be handled under the project’s regulatory discharge permit (i.e., NPDES, etc.) For more information on the chemistry of coalbed methane waters, refer to Additional Resources at the end of this chapter.

Regulations and Permitting for Water Disposal In the Black Warrior Basin of Alabama, the operation of coalbed methane fields is regulated by the State of Alabama Oil and Gas Board (OGB). The OGB issues permits for drilling of all coalbed methane wells, and regulates site maintenance, wellbore configuration and production procedures. Production waters are generally regulated and managed according to the specific disposal method used. For example, disposal of waters into wells, often practiced in the conventional gas industry, is regulated under the Safe Drinking Water Act via the Underground Injection Control Program. In contrast, waters produced in the coalbed methane industry, which usually are discharged to surface waters because of the shallow coal horizons and the relatively fresh waters, require a NPDES (National Pollution Discharge Elimination System) permit under the Clean Water Act. This permit is issued by the

8-6

Regulations and Permitting for Water Disposal

environmental agency for the state in which the surface water is located. Because almost all coalbed methane production water in the Warrior Basin is discharged to surface water, the Alabama Department of Environmental Management (ADEM) has the responsibility for permitting and monitoring the discharge of water produced by most coalbed methane wells. Table 8-1 shows the current surface discharge limitations and monitoring requirements for a NPDES permit for the Black Warrior Basin.

Table 8-1 NPDES Discharge Limitations for the Black Warrior Basin

Water Characteristics

Discharge Limitations Daily Daily Monthly Minimum Maximum Average

Flow (MGD)

N/A

Monitor

N/A

pH

6.0 s.u.

9.0 s.u.

N/A

Iron (total)

N/A

6.0 mg/l

3.0 mg/l

Manganese (total)

N/A

4.0 mg/l

2.0 mg/l

Chlorides (effluent)

N/A

Monitor

Monitor

Conductivity (instream)

N/A

Continuous Monitoring

Continuous Monitoring

Chlorides (instream) Well shut-in limit: Black Warrior River Tributaries

N/A

230 mg/l

N/A

210 mg/l 190 mg/l

210 mg/l 190 mg/l

N/A N/A

Dissolved Oxygen

5.0 mg/l

N/A

N/A

BOD-5

N/A

45 mg/l 30 mg/l

Effluent Toxicity Testing

Quarterly acute or chronic

8-7

Chapter

8


For information on discharge regulations and permitting requirements in your area, contact the state oil and gas agency and environmental agency in the area.

Considerations for Designing a Water Disposal System To design an effective and economical water disposal system, you first must consider the environmental regulations and permitting requirements for water disposal in your area. Once you understand these restrictions, you can begin evaluating the field criteria that will influence your selection of a treatment and disposal system. To design the system, you will need to know or estimate these five parameters:

• Production start-up schedule • Water flow rates from each well • Variations in flow rates over the life of the project • Water quality • Assimilative capacity of the discharge stream or river

Production Start-Up Schedule The first step in determining field disposal requirements is to prepare a schedule of estimated production start-up dates for each of the planned wells. This schedule, which is based on drilling and completion schedules, will help you in estimating the total water rate over the life of the field. The timing of initial well production can significantly influence the amount of water that must be treated and disposed at any given time.

Water Flow Rates From Each Well Coalbed methane wells can produce large amounts of water as the initial reservoir pressure is reduced. They then typically show fairly rapid decline in water rates and produce for an extended period at a constant low water rate.

8-8

Considerations for Designing a Water Disposal System

You can estimate water flow rates using a variety of techniques. You can incorporate permeability values from wells into a hydrologic model. You can also predict rates using a reservoir model designed for coalbed methane reservoirs. Some operators in the Black Warrior Basin use a more field-oriented approach to estimate water flow rates from wells that have been drilled but not yet produced. While drilling the well, they closely monitor the drilling pits to gauge the rate of water influx from each water zone penetrated. After drilling to total depth (TD), they clean out the wellbore by injecting compressed air at TD for several hours while monitoring water returns at the surface. Though this technique is used primarily to determine the size of pump needed for the well, you may also use it to approximate water disposal requirements for individual wells. You cannot use this method if there are any water bearing sands open to the wellbore.

Variations in Flow Rates Over the Life of the Project Just as important as initial flow rates and the timing of new wells is the variation in water flow rates over the life of the project. You can use reservoir simulations or flow rate histories from nearby offset wells to estimate water production profiles for individual wells.

Water Quality The principal constituent influencing the quality of coalbed methane waters is the concentration of total dissolved solids (TDS), which includes the concentration of chlorides. Total dissolved solids concentrations range from 500 to 27,000 mg/l in waters generated in the eastern United States, and from 200 to 4,000 mg/l in the western United States (Lee-Ryan et al., 1991). Other constituents in coalbed methane waters likely to require treatment include biochemical oxygen demand (BOD) and total iron. Typically, the concentration of dissolved oxygen must be increased before disposal. The quality of the total produced water stream will determine the type of discharge method you can use (these methods are explained later in this chapter). For example, in Alabama, water produced from coalbed methane wells can be treated like any other industrial or municipal waste stream. Thus, if the water meets permit standards, surface discharge of the water is allowed. To discharge into a surface water, you must apply for and receive an NPDES permit.

8-9

Chapter

8


This permit will allow discharge into streams as long as the discharge is monitored and remains within permit requirements.

Assimilative Capacity of the Discharge Stream or River Assimilative capacity is the maximum concentration of chlorides that the state regulatory agency allows an operator to discharge into a stream. Assimilative capacity is determined based on historical stream flow during drought conditions. Currently, the state of Alabama defines the maximum assimilative capacity for chlorides as 230 mg/l. However, when the in-stream chlorides concentration reaches 190 mg/l, the wells must be shut in.

For a detailed discussion of how these five parameters can be incorporated into a comprehensive water management model, refer to the paper by Burkett, McDaniel, and Hall (See Additional Resources at the end of this chapter).

Methods for Treating and Disposing Produced Water Developing a plan to manage produced waters requires an understanding of the character of the produced water, the working range of available processes, the cost of the various options, and a knowledge of treatment constraints for existing environmental regulations. You should also contact the appropriate regulatory agency in your area before finalizing plans for water treatment to ensure the plans satisfy the current regulations. Economic development of coalbed methane requires an effective production water management strategy. To ensure that field development proceeds in an environmentally sound manner and on schedule, you should develop a comprehensive plan to manage the treatment and disposal of produced water. Such a plan for a field in the Black Warrior Basin is described by Burkett, Hall, and McDaniel (See Additional Resources at the end of this chapter). Treatment and disposal options for coalbed methane produced waters in the Black Warrior Basin can generally be divided into three categories:

• Treating Water and Disposing on the Surface • Disposing Water in Disposal Wells • Disposing Water after Well Stimulations

8-10

Methods for Treating and Disposing Produced Water

Treating Water and Disposing on the Surface In areas where regulations allow its use, treatment of produced waters and surface disposal is the lowest cost water disposal option. This method requires an NPDES permit, which can be obtained from the state or federal Environmental Protection Agency (EPA). Surface disposal has become the method most widely used for disposing coalbed methane produced waters in the Black Warrior Basin of Alabama because of the water chemistry, sustained seasonal stream flow, and porous soil. Though regulations on surface disposal may be tightened in the future, this method currently provides an environmentally acceptable and cost-effective option where applicable. Currently, NPDES permitting approves two types of surface disposal: direct land application and controlled discharge into streams.

Direct Land Application Applying produced water directly to the land typically involves moving water from the well to a nearby area of vegetation via a buried flowline, and dispersing the water on the ground with a common lawn sprinkler head. Though direct land application is probably the least costly disposal method, the requirements for this option are relatively strict. For example, the State of Alabama requires that the total dissolved solids (TDS) concentration does not exceed 2000 mg/l, and the water must be applied in such a way that there is no soil erosion runoff into nearby streams. Land application was used initially in the Brookwood and Oak Grove coalbed methane fields in Alabama. As deeper coal seams were drilled and produced, waters with higher concentrations of TDS were encountered. Because the higher TDS levels precluded continuing land application, the operators switched to controlled stream disposal. Recent environmental regulations in Alabama require that a two-part technical evaluation be performed before any new water discharge permit will be issued. Phase one of this evaluation covers current soil and hydrology conditions in the area of operation. Phase two covers engineering aspects of the field operation, including field equipment and production facilities.

8-11

Chapter

8


Other states may or may not have similar permitting requirements. For current regulations in your area of operation, contact the state environmental agency.

Controlled Discharge into Streams Currently, surface stream dilution for water disposal requires that the instream chloride concentration remains below 230 mg/l and that the iron concentration in the discharge water has a monthly average no greater than 3 mg/l. The operator is required to monitor the water upstream and downstream of the discharge point and to comply with daily limits for various effluent characteristics. Most operators in the Black Warrior Basin treat coalbed methane produced water by pooling the water into a treatment pond, aerating the water to remove iron, allowing solids to settle out, and then discharging the water into a stream through an EPA-approved diffuser nozzle. These water systems also contain a storage pond to hold water during periods of low stream flow when discharge volumes must be reduced. Figure 8-1 shows the flow of water in a typical water disposal system in the Black Warrior Basin. Because the aeration treatment oxidizes the water and separates suspended solids, it increases dissolved oxygen levels and reduces dissolved iron (and other trace metals, if present), biochemical oxygen demand (BOD), volatile organic compounds, if present, and total suspended solids (TSS).

8-12


Figure 8-1 Typical Water Disposal System in the Black Warrior Basin

❈ Important

In cases where stream flows are much greater than the flow of discharged fluids, relatively high amounts of chlorides can be discharged with little increase in the chloride concentration in the stream. In streams with low flow or with seasonal flow variations, produced water discharge may be limited. Unlike TDS concentration and other permit parameters that are determined by instream concentrations, the limit of iron or manganese in the water is based on its discharge (effluent) concentration. At the Rock Creek Project, two lined ponds with capacities of 34,000 gal and 400,000 gal provide treatment and holding capacity in case the produced water exceeds regulatory limits. These ponds also allow aeration of the water to precipitate iron. This technique

8-13

Chapter

8


has successfully reduced iron concentrations to meet the disposal permit requirements. This type of system may require some extra storage capacity in case of occasional upsets in the system. Some of the highest iron measurements in treatment ponds may be caused by algae growth. Algae accumulations on the bottom of the pond can collect settling iron precipitates. Often this algae floats to the surface, bringing the precipitated iron with it. When water samples are collected, this algae may be collected inadvertently, skewing iron measurements far above true levels. Experience has also shown that agitating the water by aeration can inhibit growth of floating algae accumulations. Algae growth is a function of the pH of the water. During hot summer weather, accelerated growth of algae in smaller settling ponds may elevate the pH level of water in the pond. You can usually reduce the pH to permit levels by shading the pond from the sun. When stream disposal is used, provisions must be made to allow year-round operation of the field even during periods of low stream flow. For example, many streams in the Black Warrior Basin approach near-zero flow during the summer and fall months. In most cases, storage of produced water is the only alternative to shutting-in wells. Storage, however, can be impractical for fields with high water rates unless the technical and economic constraints of large-scale temporary storage can be overcome. Toward this objective, Luckianow and Hall present an informative review of selected storage alternatives, design requirements, construction constraints, regulatory requirements, and cost data (see Additional Resources at the end of this chapter). Safety of In-Stream Disposal

Because many producers in the Black Warrior Basin have obtained permits to discharge into streams, several studies have been performed to assure environmental safety. A key conclusion of these studies was that stream discharges could safely occur at levels specified by permits without adversely affecting biota (O'Neill et al, 1989; Drottar et al, 1989; O'Neill et al, 1991a; O'Neill et al, 1991b). In these studies, in-stream chlorides levels were increased until significant changes in biota were observed. These changes did not occur until chlorides exceeded 593 mg/l, a value more than 200% greater than the current maximum permitted concentration (O'Neill et al, 1989).

8-14


Disposing Water in Disposal Wells Few injection wells are currently in use in the Black Warrior Basin because most formations in this area are of low permeability and are not suitable for injection. Most attempts to complete water disposal wells in the Black Warrior Basin have been unsuccessful and significantly more expensive than surface disposal methods. Injection wells are more commonly used for water disposal in states where coalbed methane produced water is treated like a conventional oil and gas waste stream, where surface stream flow is not sufficient year round to assimilate produced waters, and where there are formations that will accept the necessary disposal volumes.

Disposing Water After Well Stimulations After fracturing a well, you will need to dispose the water produced back. The method you use to treat and dispose the water will depend primarily on the regulations in the state where you operate. For example, in the Black Warrior Basin of Alabama, if the quality of the frac water meets state specifications for land application, you may dispose it by spraying it directly on vegetated land. To facilitate treatment of frac water, you should keep drilling pits open to receive the initial production from fractured wells. You can use the lined pit at the well site for aeration and/or mixing water treatment chemicals. You should check with the state regulatory agencies to obtain approval to keep the pits open for initial production. If you cannot treat the water to meet permit discharge criteria, you may need to transport the water via a permitted truck to commercial injection wells for disposal. The primary constituents you should check in produced fracture water are listed below: ❖

Chlorides concentration

❖

pH

❖

Dissolved oxygen concentration

❖

Biochemical oxygen demand (BOD)

8-15

Chapter

8


Occasionally, after a well is stimulated the concentration of total organic carbon, or BOD, can be higher than specifications allow. If the well was shut-in for an extended period of time before production, any bacteriacide included with the fracture treatment may have lost its effectiveness. Such fracture waters are often most effectively treated separately, rather than mixing them with the entire water process stream.

❈ Important As environmental issues continue to gain prominence, the treatment and disposal of produced water will become an increasingly sensitive operation. To ensure that your water treatment and disposal practices satisfy state regulations, make sure you review and understand all relevant regulations . ❖

8-16

❖

❖



Burkett, W.C., R. McDaniel, and W.L. Hall, “The Evaluation and Implementation of a Comprehensive Production Water Management Plan,” Proceedings of the 1991 Coalbed Methane Symposium, Tuscaloosa, Alabama (May 13-17).

Drottar, K.R., D.R. Mount, and S.J. Patti, 1989, “Biomonitoring of Coalbed Methane Produced Water from the Cedar Cove, Alabama Degasification Field,” Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (April 17-20).

Kuuskraa, V.A. and C.F. Brandenburg, “Coalbed Methane Sparks a New Energy Industry,” Oil & Gas Journal, October 9, 1989.

Lee-Ryan, P.B., J.P. Fillo, J.T.Tallon, and J.M. Evans, “Evaluation of Management Options for Coalbed Methane Produced Water,” Proceedings of the 1991 Coalbed Methane Symposium, Tuscaloosa, Alabama (May 13-17).

Luckianow, B.J., “Economics of Production Water Storage,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (May 13-17).

Luckianow, B.J., and W.L. Hall, “Water Storage Key Factor in Coalbed Methane Production,” Oil & Gas Journal, Mar 11, 1991.

O’Neill, P.E., S.C. Harris, and M.F. Mattee, 1989, "Stream Monitoring of Coalbed Methane Produced Water from the Cedar Cove Degasification Field, Alabama,” Proceedings of the 1989 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (April 17-20).

8-17

Chapter

8


O’Neill, P.E. et al, 1991a, “Long Term Biomonitoring of a Produced Water Discharge from the Cedar Cove Degasification Field, Alabama,” GRI Topical Report, GRI-90/0233, (January).

O’Neill, P.E. et al, 1991b, “Long Term Biomonitoring of a Produced Water Discharge from the Cedar Cove Degasification Field, Alabama,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (May 13-17).

Schraufnagel, R.A., “Coalbed Methane Production,” in “Hydrocarbons from Coal,” American Association of Petroleum Geologists (AAPG), Tulsa, Oklahoma, not yet published.

Schraufnagel, R.A., and S.D. Spafford, “Multiple Coal Seams Project Progress Report,” Quarterly Review of Methane From Multiple Coal Seam Technology, V 7 N 3 (March).

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

8-18

9

Testing the Well

T

o determine the economic feasibility of a coalbed methane well, you must evaluate the production potential of the coal seams before fracturing and producing the well. You can obtain the reservoir data for this evaluation from open hole logs, cores, and pressure transient tests. (For a list of information you can obtain from log and core analysis, refer to Chapter 3.) If the evaluation indicates the coal seam has potential for economical production, the well should be fractured and placed on production. After placing the well on production, you should check the gas and water rates periodically using well tests to ensure the well is producing at an optimum level. This chapter explains methods for obtaining the reservoir data needed to assess the productive potential of coalbed methane wells. You will find information to help you in:

• Performing Pressure Transient Tests • Evaluating Production from Multiple-Seam Wells

Chapter

9

Testing the Well

Performing Pressure Transient Tests Pressure transient well tests can provide important information for assessing the production potential and economic feasibility of coalbed methane wells. This information includes estimates of reservoir pressure, permeability, wellbore damage, wellbore storage, porositycompressibility product, as well as fracture length and conductivity in hydraulically fractured wells. Pressure transient tests can also be used to estimate the distance to a reservoir discontinuity. The two most important properties for predicting the performance of a coalbed methane reservoir are permeability and reservoir pressure with respect to desorption pressure. You can obtain both of these parameters from well tests. To be productive, coal seams must have sufficient permeability to allow withdrawal of enough water to lower the reservoir pressure below the desorption pressure of the coal. When reservoir pressure drops below the desorption pressure, gas will begin to flow from the coal to the wellbore. Well tests may be performed on either single wells or multiple wells. Single-well tests are more commonly used and are usually less expensive than multiple-well tests. Multiple-well tests are used to determine communication between wells, porosity-compressibility products, and the orientation of permeability. The slug test is particularly suited to coalbed methane wells because no surface flow-control or downhole pumping is required. Most other single well and multiple-well test methods require pumping from or injecting into the well at a constant rate. This section explains the most commonly used well tests for obtaining coal reservoir properties and the procedures used at the Rock Creek project to perform them. These tests are:

• Slug Tests • Injection/Fall-off Tests • Interference Tests • Pressure Buildup Tests

9-2

Performing Pressure Transient Tests

Slug Tests Slug tests are the simplest and least expensive tests. They are commonly used on coalbed methane wells because they can be performed with a minimal amount of manpower and equipment. A slug test involves the instantaneous injection or withdrawal of a specific slug, or volume of water into or from the wellbore. The increase or decrease in wellbore pressure is then measured versus time until the pressure approaches the pressure measured before the slug was initiated. The results of the slug test can be matched with typecurves developed by Ramey and others (1975) to determine permeability with respect to both wellbore storage and skin effects. Most slug tests used on coalbed methane wells are run by injecting a slug of fresh water into the wellbore rather than withdrawing a slug of fluid from the wellbore. The main advantages of the slug test are: ❖ Low cost ❖ Simple to design and perform ❖ Simple to analyze using type curve analysis The main disadvantages of the slug test are: ❖ Not valid for two-phase flow ❖ Reservoir must be under-pressured ❖ Limited radius of investigation ❖ Duration of test is long ❖ Difficult to interpret reservoir heterogeneities

The only equipment needed to run a slug test is listed below: ❖ Workover rig to prepare the well for test (if required) ❖ Equipment to slug water into the wellbore (buckets of water, a small pump, or a vacuum truck)

9-3

Chapter

9

Testing the Well

❖ A pressure transducer to install in the wellbore ❖ A pressure data recorder at the surface ❖ Tools to analyze data (software, such as STEP Match)

The equipment used at the Rock Creek project consists of a strain gauge pressure transducer connected by cable to a “Hermit” data logger at the surface. A typical slug test equipment configuration is shown in Figure 9-1.

Figure 9-1 Slug Test Equipment Configuration

9-4


Designing a Slug Test The three main considerations in designing a slug test are: ❖ Tubular Size ❖ Tubular Configuration ❖ Method of Slugging

Tubular Size

The most important consideration is the diameter of the tubing or casing through which the well will be slugged. The duration of the test is directly proportional to the square of the radius of the tubing or casing used. The duration of the test increases with increasing diameters because as the tubing size increases, the volume of water that must flow into the coal seam increases. Consequently, the permeability of the coal seam directly affects the duration of the test. To minimize the time required to test the well, you can use the smallest tubing size that is economically and operationally feasible. However, decreasing the test time also decreases the radius of investigation for the test. You can estimate the minimum test duration for a unique type curve match by using the equation below:

t = 43,700 µ re2 , hrs kh where: t = minimum duration of the test, hrs k = permeability of the formation, md h = thickness of the zone, ft µ = viscosity of the slugged fluid, cp re = internal radius of the tubing or casing through which the well is slugged, ft

9-5

Chapter

9

Testing the Well

Tubular Configuration

If you conduct the slug test down the casing, you will not need any additional equipment. However, if you conduct the test down the tubing string, you must run a packer on the tubing to isolate the annulus. If you do not seal off the annulus, the benefit of using a small tubing string (shorter test duration) will be negated.

Method of Slugging

To perform a slug test, you must load a volume of water into the tubing or casing. The methods most commonly used to load the slug of water into the tubing or casing are: ❖

Dumping pails of water into the tubing

❖

Pumping the water with a chemical pump

❖

Pumping the water with the small pump on a vacuum truck

The method you use to load the well depends on the permeability of the coal and on the volume of water needed for the slug. The higher the coal permeability, the more rapidly you can load the water slug. You can estimate the volume of water needed for the slug if you know the static fluid level for the coal seam you are testing. The maximum volume of water required for the slug is the volume needed to fill the tubing or casing from the static fluid level to the surface.

Performing a Slug Test The procedures used at the Rock Creek project to perform a slug test are explained below:

9-6

1.

Isolate the zone of interest. If more than one zone is open to the wellbore during a slug test, you may not obtain any useful data about either zone. The zone of interest should be isolated using bridge plugs and packers if necessary.

2.

If the well is slugged through a tubing/packer assembly, test the tubing/casing annulus to make sure the packer is not leaking.


Fluid leaking into the well from the annulus would require using multiple storage coefficients, which would make the test difficult to analyze. If perforated intervals are above the zone of interest, you may not be able to test the packer unless those zones will support a minimal amount of pressure. An alternative method of determining that the packer is providing isolation is by pumping water into the annulus and monitoring the downhole data recorder for a pressure response.

3.

After installing the tubing/packer assembly, lower the pressure transducer into the wellbore. Place the transducer deep enough in the wellbore so that it remains below the fluid level throughout the test, but not so deep that the hydrostatic pressure of the fluid above the transducer exceeds the tool’s maximum pressure rating at any time during the test.

4.

Allow the well time to equilibrate before beginning the slug test. At the Rock Creek Project, Saulsberry et al have developed a spreadsheet program which can help you estimate the time required for the well to equilibrate and the equilibration pressure. If you cannot wait the required time before beginning the slug test, you can begin the test and use the estimated equilibration pressure as the initial pressure before the slugged volume.

5.

Inject a slug of water into the formation. At the Rock Creek project, it was learned that the best way to inject water depends on the permeability and/or skin of the zone being tested. For wells that do not take fluid rapidly, you can inject the slug by pouring buckets of water into the tubing. If a well is fairly permeable, you may need to use a pump or a vacuum truck to load the tubing with the slug of water.

6.

Start the data recording equipment at the instant the slug of water is injected into the wellbore. The early time data of a slug test is important to the interpretation of the pressure responses. To ensure that the early time data is recorded, you may need two people to initiate the test.

9-7

Chapter

9

Testing the Well

You should set the data recorder to record data at the frequencies shown in Table 9-1.

Table 9-1 Data Recording Frequency for Slug Tests

Time Interval (Minutes)

Recording Frequency

0-1

Tenths of a minute

1 - 10

One minute

10 - 100

Five minutes

100 - 1,000

Ten minutes

1,000 - 10,000

One hundred minutes

When you use a data recorder at the surface, you can analyze data as the test progresses and determine when you have collected a sufficient amount of data and when to conclude the test. As mentioned earlier, the minimum length of a slug test depends on the permeability of the coal seam being tested. Lower permeability seams require longer test periods.

Injection/Fall-Off Tests An injection/fall-off test is a single-well pressure transient test which you can also use to estimate permeability. To conduct an injection/fall-off test, you inject water into the well at a constant rate for a period of time and then you shut in the well. During both injection and the shut-in periods, the bottomhole pressure is measured using a downhole pressure gauge. You can analyze pressure data from both the injection period and the fall-off period independently to estimate permeability. The most critical consideration in performing an injection/fall-off test is the fracture pressure of the formation. If the fracture pressure

9-8


is exceeded during the injection period, the injection pressure data is meaningless. The late-time data from the shut-in period could possibly be useful if the induced fracture closes soon enough for some of the pressure fall-off to measure the natural coal seam response. However, a permeability estimate derived from the late time data should be considered the upper bound for permeability. The main advantages of the injection/fall-off test are: ❖ Can provide a larger radius of investigation ❖ Relatively quick to perform ❖ May be used for post-fracture analysis

The disadvantages of this type of test are: ❖ Relatively expensive ❖ Difficult to perform in low permeability coal seams because very low injection rates must be maintained (sometimes as low as 0.04 GPM).

The equipment needed to perform a slug test are: ❖ Workover rig to install the tubular equipment downhole ❖ Low rate pump ❖ Low rate water meter ❖ Supply of water ❖ Slickline (wireline) unit to install pressure gauges and downhole shut-in tool ❖ Pressure gauges ❖ Downhole shut-in tool

9-9

Chapter

9

Testing the Well

Designing an Injection/Fall-Off Test Based on experience at the Rock Creek project, the most critical factors in designing an injection/fall-off test are injection pressure and rate. To reduce the effects of stress-dependent permeability, you should keep the injection pressure as low as practical. The maximum injection pressure should be much less than the fracture pressure. If the fracture pressure is not known, you should estimate it based on offset data from stress tests or stimulation treatments. If you do not know the permeability of the zone, you can design the test based on an estimated minimum permeability. Alternatively, you can run a slug test first to get an estimate of the permeability. You can then use that permeability value to calculate the maximum injection rate for the test using the equation below:

q =

Pinj - Pr 162.6 Bwµ

[ log ø kµ t c

k h Where:

t

rw2

]

- 3.23 + 0.869 S

q = Maximum injection rate, BPD Pinj = Maximum injection pressure, psi Pr = Formation pressure, psi Bw = Water formation volume factor, Bbl/STB (Use 1.0) k = Estimated minimum permeability, md t = time period for injection, hrs ø = porosity, % µ = viscosity of the water, cp ct = Total compressibility of the formation, psi-1 rw2 = Radius of the wellbore, ft2 h = Thickness of the coal, ft S = Skin factor (Use S = 0 if perforations are broken down.)

Notes:

9-10

(1) The maximum injection pressure should be less than 75% of the fracture pressure.


(2) The time period should be based on the injection period (e.g., 24 hours for a 24-hour injection period).

The fall-off portion of the test normally yields the most useful information. To increase the amount and quality of information obtained during this period, you can install a downhole shut-in plug after injection to reduce the wellbore storage effects.

Preparing for an Injection/Fall-Off Test Before beginning an injection/fall-off test, you should make the following preparations: 1.

Contact the service company who will perform the test and find out what equipment they will provide and what equipment you need to provide. The service company will usually supply water, pumps, and all metering equipment for the job.

2.

Prepare the well for the test. This step includes installing the appropriate bottomhole assembly that will hold the pressure gauges and the downhole shut-in plug (if one is to be used). A typical bottomhole assembly would include: ❖ Joint of tubing with bull plug on bottom ❖ Perforated sub ❖ Packer ❖ Seating nipple for the downhole shut-in plug ❖ Tubing to the surface

As an alternative to the joint of tubing on bottom, you can install the perforated sub with a bull plug on bottom and the joint of pipe in between the perforated sub and the packer. This configuration is a matter of preference.

9-11

Chapter

9

Testing the Well

▲ Caution

3.

To install the pressure gauges, there must be sufficient distance between the end of the tubing (bull-plugged joint) and the seat nipple. To ensure you have sufficient clearance to set the shut-in plug after the injection period, find out the length of the tandem pressure gauges from the service company representative .

Make sure the surface connections include: ❖ Full opening ball valve large enough to allow the downhole shut-in plug to pass through. This valve will allow the well to be shut-in after the injection is concluded. This valve may be needed because the plug might need pressure above it to hold it in place (depending on the pressure below the plug). The plug is designed to withstand a certain differential pressure. ❖ Tapped nipple with pressure gauge. This gauge will be used to monitor pressure on the tubing during the shut-in period.

4.

❈ Important

Check and record the volume and quality of water on location. You must keep an accurate record of volume of water pumped into the well during the test. Water containing debris can prevent the plug from properly seating in the nipple.

5.

Pressure test the injection lines to the maximum allowable surface pressure. ◆

If no valve is installed between the injection line and the connection to the tubing, you should observe the injection lines for leaks during the job.

◆

If you observe a leak during the job, attempt to fix the leak while continuing to inject, if possible. Once you begin injection, you should not discontinue injecting unless safety or environmental regulations are threatened. Water that is not fresh should never be allowed to drain onto the ground.

◆

If you continue injecting with a leaking line, collect and

❈ Important

9-12


measure the volume of leaked water so you can determine the actual injection volume.

Performing an Injection/Fall-Off Test The procedures used at the Rock Creek project to perform a slug test are explained below: 1.

Run the tools in the hole. ◆

If the tubing is not new, you should make a dummy run into the hole with sinker bars (sized as close to the O.D. of the tools as necessary) on slickline.

2.

Allow the gauges to sit in the well for a least one hour to measure the current pressure trend (if any) in the reservoir.

3.

Fill the tubing with water as quickly as possible, unless you are testing the well at a pressure below the hydrostatic pressure. Make sure the needle valve on the lubricator is open to allow air and/or gas to escape as the tubing is filled.

4.

After the tubing is filled, fill the lubricator with water. Loosen the top nut on the lubricator so pressure will bleed off the lubricator while it fills with water. As the lubricator is filled with water, the injection pressure will increase due to the increasing hydrostatic column in the lubricator. The maximum pressure increase due to the height of the lubricator depends on the height of the lubricator above the injection point. This pressure can be calculated using the equation below.

ÐP = h x ð x 0.052 , psi where: h = height of the lubricator above the tubing, ft ð = density of the water, lb/gal

9-13

Chapter

9

Testing the Well

5.

Measure and record the volume of water left on location when injection is completed.

6.

Calculate the average injection rate during the test using the equations below:

Injection Volume = Initial Volume - Final Volume - Tubing Volume - Lubricator Volume

Average Injection Rate = Injection Volume Injection Time

Remember to take into account the volume of water used to fill the tubing and the lubricator. The calculated average injection volume should be close to the value measured by the water meters on location.

7.

After concluding the injection period, set a tubing plug in the seating nipple.

8.

Pressure up the tubing above the plug to make sure the plug is set. Because most plugs will withstand a limited amount of differential pressure, the pressure that is left on the tubing while the well is shut-in should exceed the final injection pressure before the plug was set.

9.

Wait for the well pressure to fall off.

10. After the pressure has fallen off completely, retrieve the downhole shut-in tool with a wireline retrieving tool and retrieve the downhole pressure gauges.

9-14


11. Analyze the pressure data. The bottomhole pressure data recorded during the injection portion of the test is often erratic (even though injection rates may have been stable) and is therefore difficult to analyze. The data obtained during the fall-off portion of the test usually provides the most useful information.

Interference Tests An interference test is a multiple-well test with an active well and one or more observation wells. In an interference test, a pressure transient is applied to the formation to be tested by either injecting fluid into or withdrawing fluid from the active well. The pressure response to the applied stress is then monitored continuously in the active well and all of the observation wells. In designing an interference test, it is important to select an injection rate low enough not to fracture the formation. Multiple-well tests generally yield more information about a coalbed methane reservoir than single-well tests. In addition to static reservoir pressure and intrinsic permeability, multiple-well tests can also provide directional permeability, porosity-compressibility product, leakage from an adjacent aquifer through a semi-permeable barrier, or the location of a no-flow or constant-head boundary within the coal seam. Multiple-well tests are most useful for determining directional permeability. Interference tests can be analyzed using either type curves or the straight-line method. The main advantages of interference tests over other tests methods are: ❖ Generally tests a larger portion of the coalbed reservoir ❖ Provides more information about the reservoir

The main disadvantages of interference tests over other tests methods are: ❖ Expensive ❖ Lengthy test period ❖ Sometimes difficult to analyze

9-15

Chapter

9

Testing the Well

The equipment needed to run an interference test are listed below: ❖ Workover rig to prepare the well for the test ❖ Low rate pump (as low as 0.04 GPM) ❖ Low rate water meter ❖ Supply of water ❖ Slick-line (wireline) unit to install pressure gauges in the test well and observation well(s), if necessary ❖ Downhole pressure gauges

Designing an Interference Test Based on experience at the Rock Creek project, the most critical factors in designing an interference test are injection pressure and rate. The maximum injection pressure should be less than the fracture pressure. If the fracture pressure is not known, you should estimate it based on offset data from stress tests or stimulation treatments. If offset fracture data is not available, determine a reasonable range of fracture pressure values and use the lower end of the range. If the permeability of the zone is not known, you can run a slug test first to estimate the permeability of the active well. You can then use that permeability value to calculate the maximum injection rate for the test using the equation below:

q =

9-16

Pinj - Pr 162.6 B w µ k h

[ log ø kµ t c

t

]

- 3.23 + 0.869 S rw2


Where:

q = Maximum injection rate, BPD Pinj = Maximum injection pressure, psi Pr = Formation pressure, psi Bw = Water formation volume factor, Bbl/STB (Use 1.0) k = Estimated minimum permeability, md t = time period for injection, hrs ø = porosity, % µ = viscosity of the water, cp c t = Total compressibility of the formation, psi -1 r w 2 = Radius of the wellbore, ft 2 h = Thickness of the coal, ft S = Skin factor (Use S = 0 if perforations are broken down.)

Notes:

(1) The maximum injection pressure should be less than 75% of the fracture pressure. (2) The time period should be based on the injection period (e.g., 24 hours for a 24-hour injection period).

Preparing for an Interference Test Before beginning an interference test, you should make the following preparations: 1.

Contact the service company who will perform the test and find out what equipment they will provide and what you need to provide. The service company will usually supply water, pumps, and all metering equipment for the job.

2.

Prepare the well for the test. This step includes installing the appropriate bottomhole assembly that will hold the pressure gauges and the downhole shut-in plug (if one is to be used).

9-17

Chapter

9

Testing the Well

A typical bottomhole assembly would include: ❖ Joint of tubing with bull plug on bottom ❖ Perforated sub ❖ Packer ❖ Seating nipple for the downhole shut-in plug ❖ Tubing to the surface

The surface connections should include: ❖ A ball valve on the injection tubing so that the well can shut-in after the injection is concluded ❖ A tapped nipple with a pressure gauge so that pressure on the tubing can be monitored during the shut-in period

Performing an Interference Test The procedures used at the Rock Creek project to perform an interference test are explained below:

9-18

1.

Run the tools in the hole. If the tubing is not new, you should make a dummy run into the hole with sinker bars (sized as close to the O.D. of the tools as necessary) on slickline.

2.

Fill the tubing with water as quickly as possible. Make sure the needle valve on the lubricator is open to allow air and/or gas to escape as the tubing is filled.

3.

Measure and record the volume of water left on location when injection is completed.

4.

Calculate the average injection rate during the test using the equations below: Remember to take into account the volume of water used to fill the tubing and the lubricator.


The calculated average injection volume should be close to the value measured by the water meters on location.

Injection Volume = Initial Volume - Final Volume - Tubing Volume - Lubricator Volume

Average Injection Rate = Injection Volume Injection Time

5.

Continue injecting until you observe a pressure response in offsets wells.

6.

After concluding the injection period, continue to monitor the pressures in the test well and in each observation well until all pressures have stabilized.

7.

After all pressures have stabilized, run in the hole and retrieve the pressure gauges.

8.

Analyze the pressure data.

Pressure Buildup Tests Pressure buildup testing of coalbed methane wells is difficult to perform because almost all coalbed methane wells are on artificial lift. Artificial lift equipment prevents installation of downhole pressure gauges while the well is flowing. To install gauges on a lift well, you would first have to shut-in the well and remove the lift equipment from the wellbore. This procedure would cause the loss of valuable early time data. To perform a successful buildup test, two alternative methods have been tried.

9-19

Chapter

9

Testing the Well

Using a Well Sounder The first method is the use of an automatic well sounder (AWS). This method has been used on pumping oil wells for many years. It simply involves connecting an AWS machine to the annulus of the well to be tested. After the sounder is installed, it is set to record some data points under stabilized pumping conditions. Then the well is shut in. The sounder continues to record the fluid levels and converts them to pressures until the pre-programmed time ends or the sounder is stopped manually. The advantages to this method are: ❖ Easy to operate ❖ Relatively inexpensive (no rig work required)

The disadvantages to this method are: ❖ The accuracy of pressure measurement is no greater than the fluid column weight across the length of one joint of tubing ❖ Two-phase flow may complicate the analysis ❖ Wellbore storage effects are usually significant ❖ Pressure readings may be inaccurate if the fluid level is below a set of perforations

Using the Rock Creek Technique The other technique for performing a buildup test was developed at the Rock Creek project. This method involves measuring the pressure at the surface rather than downhole. You can use this method only on wells that have a working fluid level below the perforations of the interval to be tested. This technique is based on the premise that surface pressure can be accurately extrapolated to the bottomhole pressure as long as the fluid level remains below the perforations. Thus, the bottomhole pressure can be estimated during the shut-in period until the fluid level rises above the perforations.

9-20

Evaluating Production from Multiple-Seam Wells

The only equipment required for this technique is an “In-Situ” pressure transducer, “Bowen” wiper and a “Hermit” data recorder. The pressure transducer is installed in the piping from the side outlet of the casing head. The cable for the pressure transducer is run through a “Bowen” wiper rubber that can hold the low pressures observed during this type of test. The cable is then connected to the “Hermit” recorder. The “Hermit” pressure recorder should be programmed to record frequent early time data. After all the equipment is connected, the “Hermit” is started and within 10 seconds, the pumping unit is stopped, the flowline valve on the annulus is closed, and the pressure buildup test begins. The main advantages to this method are: ❖ Inexpensive ❖ Easy to run (no outside services required) ❖ Can be performed frequently The limitations of this method are: ❖ Can only be used on wells with a working fluid level below the perforations ❖ Two-phase flow may occur in the formation, which complicates the analysis

Evaluating Production from Multiple-Seam Wells To optimize production from any well, you should have procedures in place for predicting and identifying production trends. When production deviates from these trends, you must then determine if your expectations of well performance were valid. If they are valid, then you must determine if the well has any mechanical problems. For information on identifying and correcting mechanical problems with wells, refer to Chapter 6. This section explains ways to evaluate the production from multiple seams. It will introduce you to:

• Typical Coalbed Methane Production Decline Curves

9-21

Chapter

9

Testing the Well

• Determining Production from Individual Seams in a Multiple-Seam Well

• Recognizing Reservoir Problems

Typical Coalbed Methane Production Decline Curves The production decline curves of coalbed methane wells are quite different than those from conventional wells. This difference is related to the unique characteristics of coalbed methane reservoirs. Coal seams contain natural fractures, or cleats, that are usually saturated with water. The methane gas in the seams is adsorbed onto the coal. To produce the gas, it must first be desorbed from the coal. This desorption occurs after enough water has been produced from the seam to reduce the pressure in the seam to the desorption pressure of the coal. When the pressure in the seam is at or below the desorption pressure, the gas will desorb from the coal and flow through the cleats to the induced fracture and through the fracture to the wellbore. You can determine the desorption pressure from core tests. Because water must be removed from the coal seam to lower the pressure, the initial production from a coalbed methane well is water. After enough water has been produced to lower the pressure, gas production will begin. At this point water, production will often begin to decline. Figure 9-2 shows a typical production decline for coalbed methane wells in the Black Warrior Basin. During the production of a well, you should monitor fluid levels and production rates to make sure the well is producing at an optimum level. You should also attempt to keep the fluid level below the coal seam and minimize backpressure on the wellhead.

Determining Production from Individual Seams in a Multiple-Seam Well Monitoring the production performance of a single-seam coalbed methane well is much easier than monitoring a multiple-seam well. When production is commingled from several zones, it is difficult to accurately determine production rates and pressures for individual seams. Many of the coalbed methane wells in the Black Warrior Basin produce from three or more seams.

9-22


Figure 9-2 Typical Coalbed Methane Production Decline Curve

The GRI Zone Isolation Packer (ZIP) To provide an accurate way to test production from individual seams in a multiple-seam well, GRI developed a special tool for isolating coal seams. GRI’s Zone Isolation Packer (ZIP) is a modified surface inflatable packer that enables you to effectively isolate an upper coal seam from lower coal seams. After isolating the lower seams, you can accurately measure production and pressures in the upper seam. To use the specially-built ZIP tool, you install it between two joints of tubing and then position it in the well below the uppermost coal seams you wish to test. You inflate the packer with nitrogen from the surface through a stainless steel control line attached to the tubing string. Inflating the ZIP seals the annulus between the production tubing and the casing, preventing production of gas from the seams below the tool. This zone isolation enables you to accurately measure the gas rate from the upper coal group. You can then determine the production rate of the lower coal seams by subtracting the gas rate of the upper group from the well’s total gas production rate before the ZIP tool was installed.

9-23

Chapter

9

Testing the Well

If you are testing more than one coal seam, you can equip the ZIP tool with a “pass-through,” which enables you to run a control line through the ZIP to another packer installed deeper in the well. This configuration allows you to determine the gas rate of three separate zones. Figures 9-3 and 9-4 illustrate the ZIP tool used for a two-seam test and a three-seam test, respectively.

Figure 9-3 Two-Seam Well Test Using the ZIP Tool

At the Rock Creek project, the ZIP tool is installed in several wells which are tested frequently to determine production rates from the Mary Lee and Black Creek coal seams. One such test provided information which led to the successful re-stimulation of the Mary Lee interval in Well P3. For more information on the ZIP tool, refer to “Determining Production from Individual Coal Groups in Multi-Zone Wells with a Zone Isolation Packer.” See Additional Resources at the end of this chapter.

9-24


Figure 9-4 Three-Seam Well Test Using the ZIP Tool

The advantages of using the ZIP tool to test coal seams are: ❖

Individual seams may be tested without the expense of using a workover rig and retrievable bridge plugs

❖

The tool can remain installed in the tubing string for use in frequent tests

❖

The test can be completed quickly because the well does not have to be shut down to install test equipment

Other Methods for Measuring Production Rates Several other methods have been used with varying degrees of success to measure production rates from individual seams. These methods are:

• Isolating Seams with Bridge Plugs • Analyzing Gas Composition

9-25

Chapter

9

Testing the Well

• Analyzing Water Composition • Production Logging and Camera Surveys Isolating Seams with Bridge Plugs

This method is expensive and time consuming. To use this method, a workover rig is needed to install the retrievable bridge plugs and to retrieve them later. Before beginning the test, the well must be shut in to install the plugs, and the well must be pumped down to stabilize production rates.

Analyzing Gas Composition

This method involves analyzing the composition of the total gas stream and then comparing it with the composition of gas produced from individual coal seams. A study was conducted to determine if gas production rates could be estimated accurately using gas composition analysis. This method was not successful because of the relatively small variations in the compositions of the coal seams.

Analyzing Water Composition

This method involves analyzing the composition of the total produced water stream and then comparing it with the composition of water produced from individual coal seams. This method has been used with some success to estimate the water production from individual coal seams. As with comparing gas compositions, this method can be successful only if there are distinct differences in water chemistry between the coal seams. Even if the differences are great, you can only estimate the water production from the individual seams. You would have to infer the gas production based on the premise that there is a reliable and consistent correlation between gas and water production in each coal group.

Production Logging and Camera Surveys

You can use flowmeters, gradiomanometers, and temperature surveys to approximate the flow rates of individual perforated intervals in the wellbore. Though this method has been improved

9-26


over the years, you may still find it difficult to estimate production rates from individual seams because many seams produce at extremely low rates. Camera surveys cannot be used to obtain quantitative production estimates. However, you can use camera surveys to see whether fluid is flowing into the wellbore, and if so, which intervals are producing that fluid. For more information on production logging tools and camera surveys, refer to Chapter 3.

Recognizing Reservoir Problems The key to evaluating production performance is understanding why some wells in your coalbed methane field are good producers and why others are poor producers. Is it because of geological or reservoir conditions? Is it because of completion or stimulation technique? Or is it because of operational procedures? Most likely, some combination of these factors influences overall production performance. Production tests may help you determine that each seam in the well is not producing at optimum rates. If you have eliminated the possibility of mechanical problems with the artificial lift equipment or surface equipment, then you must conclude the problem is associated with the reservoir. Some of the most common coalbed methane reservoir problems are:

• Scale Deposition in the Formation • Insufficient Fracture Stimulation • Depletion of the Coal Seam Some of the coal seams in the Black Warrior Basin contain waters with a high tendency for scaling. Scaling can occur in surface equipment and downhole equipment as well as in perforations and in the formation. Though you can easily observe scaling in equipment and in perforations (with a camera survey), you cannot observe scaling in the formation. To determine if scaling has occurred in the formation, you must use pressure transient tests to assess formation damage. If formation damage exists, it could have been caused by scale. For information on the scaling tendency of coalbed methane produced water, refer to Chapter 8.

9-27

Chapter

9

Testing the Well

Poor production performance could also be caused by insufficient fracture stimulation of the coal seams or by depletion of the seams. You can diagnose these reservoir problems by analyzing pressure transient tests and by simulating reservoir performance using one of the commercially available computer models for coalbed methane reservoirs. To make well-informed production management decisions, you should attempt to gather and analyze quality data from a variety of independent sources. This practice will help ensure the operational as well as economic success of your coalbed methane project.

❖

9-28

❖

❖



Koenig, R.A., and R.A. Schraufnagel, “Application of the Slug Test in Coalbed Methane Testing,” Proceedings of the 1987 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (November 16-19).

Koenig, R.A. and P.B. Stubbs, ”Interference Testing of a Coalbed Methane Reservoir,” Proceedings of the 1986 Unconventional Gas Technology Symposium, Louisville, Kentucky (May 18-21).

McKee, C.R., “Well Testing,” GRI Coalbed Methane Workshop, Pittsburgh, Pennsylvania (February 6-7, 1989).

Rushing, J.A. et al, “Analysis of Slug Test Data From Hydraulically Fractured Coalbed Methane Wells,” SPE Paper 21492, Texas A&M University/Society of Petroleum Engineers, SPE Gas Technology Symposium, Houston (January 23-25, 1991).

Rushing, J.A. et al, “Slug Testing in Multiple Coal Seams Intersected by a Single, Vertical Fracture,” SPE Paper 22945, Texas A&M University/Society of Petroleum Engineers, 1991 SPE Annual Technical Conference and Exhibition, Dallas (October 6-9).

Saulsberry, J.L., S.W. Lambert, and Dobscha, F.X., “Determining Production from Individual Coal Groups in Multi-Zone Wells with a Zone Isolation Packer,” Proceedings of the 1991 Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama (May 13-16).

9-29

Appendix A Summary of Permitting Requirements for Drilling a Coalbed Methane Well in Alabama (State Oil and Gas Board of Alabama)

Summary of Permitting Requirements for Drilling a Coalbed Methane Well in Alabama A summary of the permitting requirements of the State Oil and Gas Board of Alabama are listed below:

Permit to Drill Before you can spud a well in the State of Alabama, you must submit a Form OGB I (Application for Permit to Drill, Deepen, Convert, or Amend). This form must be accompanied by the following: • Permit Fee • Certified Survey Plat (Triplicate) • Affadavit of Ownership or Control, Form OGB- 11. • Bond, Form OGB-3 or OGB-4. • Organization Report, Form OGB-5 This permit may not be approved until all other applicable environmental regulations have been approved by other agencies.

Drilling Operations During drilling operations, an agent of the State Oil and Gas Board of Alabama (Board) must be notified and approval obtained prior to performing any of the following operations: • • • • • • • • •

Construction of any pit Spudding Setting surface casing Slotting casing Running intermediate or production pipe Cleaning Perforating Chemical treatment or fracturing Logging

• • • • • • •

Attempting to recover a radioactive logging Testing of wells Disposing of pit fluids Plugging Recompletion or reworking Restoration of location Any other operation the Supervisor of the Board may designate. Some of these operations may be witnessed by an agent of the Board.

Casing Requirements The minimum amount of surface or first string intermediate casing to be set below ground level and the test pressure requirements are as follows: Coalbed methane gas wells may be completed open hole or cased hole. If completed open hole, the production casing must be set not more than 100' above the uppermost coalbed which the operator intends to complete and the casing must be cemented to a point 200' above the base of the casing. For cased hole completions, the production casing must be cemented in place with sufficient cement to allow for 200' of cement over the uppermost coalbed that the operator intends to complete. After cementing the casing and before completing the well, the production casing must be tested to 600 psi for 30 minutes without a drop of more than 10 percent. The cement shall be allowed to stand a total of 12 hours before drilling the plug or initiating tests.

Drilling Pits Reserve pits which are used during the drilling of the wells must be inspected by a qualified engineer and determined to be constructed in a manner that will prevent the pollution of the ground water. Ile level in the pits must be kept at least 2' below the top of the pit. After the well is completed or is plugged and abandoned, all fluids and recoverable slurry from pits must be disposed in a manner that is acceptable to the Board and the pit must be backfilled within 90 days.

Miscellaneous • A detailed and accurate record of the well must be kept during the drilling and completion of the well and must be accessible to the Board at any time. Pertinent information from these records must be submitted to the Board within 30 days of the completion of the well.

• Copies of logs, drillstem test results, and cuttings must be submitted to the Board within 30 days of the completion of the well. • If cores are taken, either whole or at least quarter slabs must be submitted to the Board within 6 months unless otherwise approved by the Board. • Adequate blow-out preventers are required and must be tested regularly. Test results should be recorded in the drillers log and available to an agent of the Board upon request. • Inclination surveys are required beginning with a depth not greater than the surface casing and succeeding shot points not more than 1000' apart or as required by the Board. The results should be reported to the Board on Form OGB-7. The summary above is only a partial listing of the regulations which affect the drilling of a coalbed methane well in Alabama. For further detail regarding these regulations and a full listing of the regulations regarding production operations in Alabama, you should consult the State Oil and Gas Board of Alabama Administrative Code. v

v v

Appendix B Summary of Permitting Requirements for Drilling a Coalbed Methane Well in Alabama (State Oil and Gas Board of Alabama)

QUALITY CONTROL GUIDELINES

Page 1

QUALITY CONTROL AND JOB SUPERVISION GUIDELINES FOR STIMULATION TREATMENTS

INTRODUTION Quality control is a key element in the successful implementation of any stimulation treatment. Simply stated, attention to quality control is needed to ensure that the stimulation treatment is pumped as designed. Often times, quality control is considered the responsibility of the service company alone, but frankly, ensuring a successful job is the responsibility of both the operator and the service company. Attention to detail by both the operator and the service company and close cooperation between the two before, during, and after the job is certain to increase the quality of service in any stimulation treatment. The guidelines which follow this discussion should assist the engineer in the quality control and job supervision of stimulation treatments. The guidelines include a comprehensive supervision checklist to remind the engineer of equipment needed for the job, safety concerns, and questions to ask before, during, and after the job. The tables that follow the checklist permit the engineer to prepare a complete summary of the job (injection rates, injection pressures, fluid and proppant volumes, etc.), as well as an inventory of all products on location before and after the treatment. An important responsibility of the stimulation engineer is to obtain a reliable record of what actually occurred during the treatment; these guidelines and tables should help meet this responsibility. While these guidelines can be used for quality control and supervision of any stimulation treatment, we have attempted to tailor them for use in Appalachian Basin reservoirs where possible. While quality control problems are not unique to this area, proper job execution in Appalachian Basin reservoirs is especially important due primarily to the smaller treatments pumped routinely. Quality control on smaller, shorter treatments is often more troublesome than for the much larger stimulation treatments typically pumped in the western and southwestern United States. On larger volume treatments involving high pressure, high temperature

GAS RESEARCH INSTITUTE


Page 2

wells, there is often more time to correct mistakes. In addition, the reservoir pressure and temperature themselves may help reduce cleanup problems created by gel lumping or lack of sufficient breaker. The combination of low pressures and low temperatures frequently encountered in many Appalachian Basin reservoirs provides for an environment that is not as tolerant of procedural mistakes. Unbroken gel or gel lumping, which may be only inconveniences in well cleanup for most wells, can result in the failure of a stimulation treatment in the Appalachian Basin. Preand post-fracture inventory of materials, fluid quality assurance, real-time monitoring of chemical additives, and attention to details such as flush volume and proper flowback can often make the difference between success and failure in low-pressure, low-temperature reservoirs.



Page 3

Fracture Stimulation Supervision Checklist Fracture Stimulation Company: Supervisor: Company: Well: I. Equipment needed on job site

Date: Location:

1. Company workover procedure with data sheet containing reservoir properties to include fracture gradient, bottomhole pressure, porosity, permeability, and temperature. Also, a complete surface and wellbore sketch and equipment inventory should be available from the operator. 2. Stimulation design 3. Logs with perforations and collars premarked 4. Tank strap (from service company) 5. Sand sieves (from service company) 6. Service company reference tables 7. Containers for samples, beakers 8. Calculator, pencils, and Quality Control Forms 9. Hardhat and steel-toed boots 10. Fann 35 or equivalent viscometer or availability of same from service company 11. Water and Acid test equipment (from service company) a. pH meter or paper i. TDS probe b. Thermometer j. B-2 bob and heat cup C. Iron test kit k. Syringes d. Phosphate test kit 1. Portable scale e. Reducing agent tester m. Blender and jar f. Chloride test kit n. Hydrometer g. Graduated cylinders o. Acid titration kit h. Bacteria vials II. The day before the job Tanks 1. Are there enough tanks on the location to store all fluids? Assume 10% of the tank volume will be umpumpable. Recommend at least 10% extra fluid on the location. 2. Have the tanks been cleaned prior to the job? How were they cleaned? 3. Was bactericide added prior to filling the tanks? 4. Does the water have the proper amounts of potassium chloride, sodium chloride, and other compounds? Check source water with water test kit. Is the source water compatible with proposed additives? Check with the chemist. 5. Are all of the tanks full? Get on the tanks yourself - do not take anyone’s word! 6. Where did the water come from? Does it appear to be clean? Check each tank yourself Do not pump dirty fluid down a well. River water may contain fines.



Page 4

7. Check the valves on the tanks to ensure that they are not leaking. If a valve has a trickle leak, replace it before the next job. If the tank has a large leak, consider having the tanks switched out prior to any pumping. 8. Conduct pre-gel quality control on fluid by completing quality control Tables 1, 2, 3, 4 or 5, and 7. Parts of Tables 1 and 2 will be done either again or only on the day of the job. Sand Storage 1. Get on top of the sand storage unit yourself and see if they contain enough proppant to do the job. Sieve proppant from each compartment. 2. Is the proppant in each compartment the correct size? Check for contamination. Add sand or other proppant to water and check pH. Also check while sieving for foreign material. Discussions with the Service-company Treatment Supervisor 1. Review the sand and fluid schedules in detail. 2. Are the proper additives and amounts going to be on the location? 3. Ask for confirmation that the chemicals are fresh and not shelf degraded or contaminated. 4. Is a standby blender going to be on location and in position to be usable? A standby is needed on treatments with pump time exceeding 1 hour. 5. Insist that a sand densiometer be available on the job. Check for the last time the densiometer was calibrated. 6. When pumping energized fluids, insist that a flowmeter is installed to measure the gas injection rates. 7. If the pumping time is going to take more than 4 hours, request that a service company mechanic be on the location to repair any equipment that malfunctions. Also, request an electronics technician to repair electrical problems on jobs with long pump times. 8. Make sure the required hydraulic horsepower is on location. Plan for contingencies. Are you willing to treat the well at a lower rate if a pump fails? 9. Go over rig up checklist (Table 15) with service company representative. 10. Arrange for testing of all gelled fluids and test crosslink time if applicable. (Table3). 11. Establish rapport with the treater and give the treater instructions on what you expect before, during, and after the treatment. 12. Have Tables 1, 2, 3, 4 or 5, 6, 7, 8, and 9 completed (to the extent possible) at least 2 hours before pump time. III. Just Before Beginning the Treatment Discussions with the Service-company Treatment Supervisor 1. Review the sand and fluid schedules. Discuss quality control Tables 1, 2, 3, 4 or 5, 6, 7, 8, 9, 10, 11, and 12.



Page 5

2. Specify whether clean or dirty volumes will be recorded. Clean volumes are fluid volumes with no sand. Dirty volumes are the slurry volumes. Also check to see if the volumes will be displayed in barrels or gallons. Dirty volume, bbl = Clean volume, bbl + (lb/gal sand x 0.00109) = bbl + ( lb/gal x 0.00109) = bbl or Dirty volume, gal = Clean volume, gal + (lb sand x 0.0456) = gal + ( lb x 0.0456) = gal 3. Calculate the foam quality that will be pumped (if applicable). Quality

-

Nitrogen Rate, scf/min x Volume Factor, bbl/scf Liquid Rate, bbl/min + Nitrogen Rate x Volume Factor

Calculate required sand addition at the blender, PPA PPA, lb/gal

-

Desired Bottomhole Sand Concentration, lb/gal (1-Quality)

Check with the treater to ensure the blender can handle the required PPA additional rate! PPA Addition Rate, lb/min PPA x Clean Rate, gal/min Calculate Foam Volumes Clean Volume, gal or bbl Foam Volume, gal or bbl

=

(1-Quality)

4. Finalize the pumping schedule on Table 4 or 5. 5. Get on top of the tanks YOURSELF and gauge ALL frac tanks using a tank strap. HAVE THE TREATER PRESENT. Having the treater gauge the tanks with you will prevent any disagreements about fluid volumes after the job is finished. This step should be completed only after all tanks have been rolled and viscosified. 6. Set up a system with the treater for numbering the tanks in the order that they will be drained. This helps keep track of the fluid volumes during the job. 7. Fill in the Frac Tank Tracking Chart (Table 8). This will help you keep track of how much fluid is left at any point during the job. 8. Arrange with the treater to have someone knowledgeable and dependable on top of the frac tanks. He or she should be there all the time that the job is being pumped to ensure a smooth uninterrupted flow of the proposed pumping schedule. 9. Impress upon the treater the adverse consequences if the pumps lose prime during the job because the tanks were sucked too low. When the fluid level in the frac tank drops below the suction valve, air is sucked into the pumps, causing the blender pumps to lose prime. The sand concentration becomes extremely high, and the rate has to be reduced. The sand concentration then tends to drop very low while the pumps regain prime. This chaos normally takes 5 to 10 min to correct -- 10 min is a lot of fluid at 50 bbl/min!



Page 6

10.

Get on top of the sand storage unit with the treater and gauge the volume of proppant in each compartment. Remember to check any 100-mesh sand that is being pumped in the pad as a fluid-loss agent. Keep hatches on the sand storage unit closed to protect proppant from inclement weather. Wet proppant will tend to clump in the storage unit and may not come out at the required delivery rates. 11. Set up a system with the treater on numbering the sand storage unit compart ments in the order that they will be pumped. 12. Have service company weigh sand trucks before leaving yard and upon return ing to yard. Complete the Proppant Tracking Chart (Table 9). This will help you keep track of how much proppant is left at any point during the job. 13. Complete the Crosslinker Tracking Chart (Table 10), if applicable. This will help you keep track of how much crosslinker is left at any point during the job. 14. Complete the Breaker Tracking Chart (Table 11). This will help you keep track of how much breaker is left at any point during the job. 15. Complete the Fluid Loss Additive Tracking Chart (Table 12). This will help you keep track of how much fluid loss additive is left at any point during the job. 16. If pumping energized fluid, fill out the nitrogen product tracking chart (Table 13). Discussions with the Service-company Field Chemist or District Engineer 1. Have the chemist complete Table 1 for each tank of gel and acid. This is in addition to your own quality control work. Always have the service company confirm your tests to be surthe values are correct. 2. Check with the chemist to find which additives (such as crosslinkers, fluid-loss additives, and breakers) will be added on the fly during the job. 3. Check with the chemist to see that all tanks have been premixed with the necessary additives. 4. If running a crosslinked gel, catch a sample of gel from each tank and add the appropriate amount of crosslinker to evaluate the crosslinker. 5. Test the crosslinker and breaker systems at bottomhole temperature using a Fann 35 and a heated cup. Equipment 1. Is all equipment fueled up, and is there enough fuel on the location to complete the job? 2. Were all pumps and lines flushed with clean water before the job started? 3. Are all injection lines staked down? Ibis is very important when pump energized fluids. 4. Is a standby blender rigged up or in an immediately usable position? 5. Is the blender located close enough to each tank so that sucking the fluid at a high rate will not be a problem? 6. To be assured of sufficient suction between the blender and the tanks you should have 1 suction hose per 10 BPM for thin fluids; for thick fluids use 1 suction hose per 5 BPM. For example, a 40 BPM rate would require 8 suction hoses for 60-pound viscous gel.



Page 7

Safety Equipment Checklist 1. Locate pumping trucks and tanks crosswind and a reasonable feet from well. Head all vehicles away from the well and keep access roads clear. 2. Each discharge line should have a full swing at the well and at the truck manifold and be staked at each end. Additional staking may be needed based on certain conditions. 3. Install check valves in each discharge line as near the wellhead as possible. 4. No one should stand on or near discharge lines under pressure and never pass lines under trucks or other equipment. 5. Pressure test discharge lines from pump to well at 500± psi greater than maximum treating pressure. 6. Inspect wellhead for any low pressure connections that may have inadvertently been added during well servicing. 7. Bleed off lines should be staked and in a safe direction (downwind, downhill, and/or to a pit). 8. Ensure that adequate fire fighting equipment is in good working condition and strategically located. 9. Conduct pumping operation in daylight. Do not pump during electrical or severe dust storms. 10. All personnel and equipment not necessary to the operation should move to a point at least 150 feet from well. 11. If flammable materials (crude oil, diesel, xylene, methanol, etc.) are pumped, all per sons within at least 150 feet from well should remove matches, lighters, and cigarettes from their pockets. 12. Prior to pumping, all company and contract supervisors and crew should meet to dis cuss job procedures, work signals, hazards, and safety precautions. At this time, an emergency assembly area should be designated in an upwind direction from the well. Also, a head count and a buddy system should be established so that all personnel can be accounted for, if necessary. 13. If pumping flammable material, have the service company wrap all discharge hoses from the blender to the pump trucks with canvas or other material. This will negate spraying of flammable material should the hoses leak or burst. Pumping Energized Fluids 14. Ensure that pressure release valves on pumping equipment are in working order and will ‘pop off’ at the proper pressure. 15. Make sure nitrogen or C02 lines are laid in a straight line to the manifold and are staked down across their entire length. 16. Pressure test nitrogen lines to 500 psi above the maximum treating pressure. 17. Make sure treating van is strategically located so that the treater can see both the liquid and nitrogen injection lines. 18. Ensure check valves are installed in the nitrogen injection lines.



Page 8

TABLE 1 FLUID COMPOSITION AND JOB RECAP

I. PRE-TREATMENT INFORMATION Water Sample Analyzed by: Water Analysis Results: Bacteria Culture Results:

Date: Aerobic: Anaerobic:

Bactericide Recommendation: Gel Pilot Test Results Frac Tanks Delivered: No. Frac Tanks Inspected: Date: Remarks: Bactericide Added: Date. Water Added: Date: II. TREATMENT INFORMATION Type of Fracturing Fluid: Amount of Fracturing Fluid on Location Beginning of Job: End of Job: Amount of Nitrogen on Location (if applicable): Beginning of Job: End of Job: Type of Proppant: Amount of Proppant on Location Beginning of Job: End of Job: Type of Prepad and Flush: Amount of Prepaid and Flush on Location Beginning of Job: End of Job: Pre-Job Safety and Information Meeting: Remarks:

Date:

Amount: Amount:

Pumpable(minuscooldown): Total Pumped:

Time:



Page 9

TABLE 1 (Continued) Products Batch Mixed: Products Added on the Fly: Job Started: Time: Job Completed: Time: Job Recap: Average Clean Rate, BPM Average Nitrogen Rate (if applicable), scf/min Average Dirty Rate, BPM Average Total Rate (if applicable), BPM Average Pressure, psi Maximum Rate, BPM Maximum Pressure, psi ISIP, psi Frac Gradient, psi/ft 15 Minute Shut-In, psi Total Proppant Pumped, lbs Total Fluid to Recover, bbls

Acid

Frac

Remarks:


TABLE 2 BASE FLUID ANALYSIS* Vicosity Type Fluid

Fluid Temp. (°F)

pH Chlorides (ppm)

rpm (cp)

rpm (cp)

rpm (cp)

Tank Length (ft)

Tank Diameter (ft)

Cross Link Time ()

Volume Volume Start End of Job of Job () ()

Iron (ppm)

Phosphate (ppm)

TDS (ppm)

Reducing Agent (+or-)

Iron (ppm)

Phosphate (ppm)

TDS (ppm)

Reducing Agent (+or-)

* Base fluid prior to adding gel.


Tank No.

TABLE 3 BASE GEL FLUID ANALYSIS* GAS RESEARCH INSTITUTE

Vicosity Tank No.

Type Fluid

Fluid Temp. (°F)

pH Chlorides (ppm)

rpm (cp)

rpm (cp)

rpm (cp)

Tank Length (ft)

Tank Diameter (ft)

Cross Link Time ()

Volume Volume Start End of Job of Job () ()

* Base fluid following addition to gel.

Page 10

TABLE 4 PROPOSED GELLED FLUID PUMPING SCHEDULE* During Treatment Checks Dirty Stage Volume ()

Proppant Proppant Stage Proppant Concentration Weight Remaining (ppg) (lbs) (lbs)

Cross Linked

Fluid Volumes ()

Sand Volumes ()


Clean Type Stage Stage Fluid Volume ()

GAS RESEARCH INSTITUTE *Use this schedule for gelled fluid fracture treatments

Page 11

TABLE 5 PROPOSED FOAM PUMPING SCHEDULE* During Treatment Checks Dirty Stage Volume ()

Proppant Proppant Stage Proppant Concentration Weight Remaining (ppg) (lbs) (lbs)

Cross Linked

Fluid Volumes ()

Sand Volumes ()


Clean Type Stage Stage Fluid Volume ()

GAS RESEARCH INSTITUTE *Use this schedule for foam fracture treatments

Page 12

TABLE 12 DESCRIPTION OF FRACTURE PROPPANTS

Compartment No. Proppant Type Sieve Sizes

Percent On Percent On Percent On Percent On Percent On Percent On Percent On Percent On Percent On

8 10 12 16 20

Percent On


TABLE 12

25 30 35


40 60 80 100 120 140 Pan *If this data not available on location, have service company supply recent sieve analysis on sand in yard.

Page 13


Page 14

TABLE 7 DESCRIPTION OF FRACTURE FLUIDS

Fluid Type: Base Fluid: Salts Added: Base Gel: Crosslinker: Bactericide: Surfactant: Buffer: Breaker: Fluid Loss:

Fluid Type: Base Fluid: Salts Added: Base Gel: Crosslinker: Bactericide: Surfactant: Buffer: Breaker: Fluid Loss:

Type Type Type Type Type Type Type Type Type Type

Amount Amount Amount Amount Amount Amount Amount Amount Amount Amount

/1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal

Type Type Type Type Type Type Type Type Type Type

Amount Amount Amount Amount Amount Amount Amount Amount Amount Amount

/1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal /1000 gal



Page 15

TABLE 8 FRAC TANK TRACKING CHART

Tank No.

GaugedVolume in Tank ()

PumpableVolume* in Tank ()

Volume on LocationAfter Treatment ()

Total *Pumpable volume = gauged volume - 10% of tank volume. (Some tank configu rations may allow more or less fluid removal. Consult with the treater as to pumpable tank volume.)



Page 16

TABLE 9 PROPPANT TRACKING CHART

Compartment No.

Type Proppant

Gauged Quanity in Compartment (lbs)

Proppant Remaining After Treatment (lbs)

Total Have service companies weigh sand trucks before leaving yard and upon return to yard.



Page 17

TABLE 10 CROSSLINKER/FOAMER TRACKING CHART Total Volume Crosslinker/Foamer on site: Crosslinker/Foamer Addition Rate: Stage Cumulative Stage Volume Usage (gal) (gal)

Crosslinker/Foamer Volume Remaining (gal)

Total *Usage for crosslinker or foamer as appropriate.



Page 18

TABLE 11 BREAKER TRACKING CHART Total Volume on site: Breaker Addition Rate: Stage Stage Volume (gals)

Cumulative Usage (gals)

Breaker Volume Remaining (gals)

Total Breaker Used:


TABLE 12 DESCRIPTION OF FRACTURE PROPPANTS

Compartment No. Proppant Type Sieve Sizes

Percent On Percent On Percent On Percent On Percent On Percent On Percent On Percent On Percent On

8 10 12 16 20

Percent On


TABLE 12

25 30 35


40 60 80 100 120 140 Pan *If this data not available on location, have service company supply recent sieve analysis on sand in yard.

Page 19

TABLE 13 NITROGEN PRODUCTION TRACKING CHART


1 2

Truck 3 % Remaining Remaining Volume (scf)



Total Volume Used (scf)


Stage

Truck 1 Truck 2 Planned % Remaining % Remaining Volume Usage Remaining1 Volume2 Remaining (scf) (scf) (scf)

Read from guage on service company nitrogen truck. Obtain volimes from service company charts for the nitrogen truck.

Page 20


Page 21

TABLE 14 ACID AND FRACTURE TREATMENT SUMMARY SHEET Frac via

Tubing Casing Annulus Tubing Size & Weight: Packer Depth: Packer Type: Casing Size & Weight: SITP: Tested Frac Lines to:

Fluid Time Type

Clean Volume ()

Tubing Volume:

Casing Volume to Perfs: Total Flush Volume:

SICP:

Perforations: ISIP: Pressured Tubing-Casing Annulus to:

Dirty Tubing Volume Rate Pres. () (BPM) (psi)

Annulus Pres. (psi)

Remarks


QUALITY CONTROL GUIDELINES Page 22 TABLE 14 (Continued)

Fluid Time Type

Clean Volume ()

Dirty Tubing Volume Rate Pres. () (BPM) (psi)

Annulus Pres. (psi)

Remarks



Page 23

TABLE 15 RIG UP CHECKLIST 1. Compact rig-up - minimum iron used This is a judgment call that will come with experience. What we are looking for here is utilization of the smallest amount of flexible iron possible. We have seen many times, simply because of personnel lacking expertise or insome occasions ignorance or laziness, a large amount of iron is placed on the location. In addition to being dangerous and just more material which may leak or fail, excessive iron can cause high treating pressures and inefficient use of hydraulic horsepower. A compact location where very little iron is used from the trucks to a manifold and then a single large line to the wellhead at a relatively safe distance is your goal. Trucks parked helter skelter around location and little care taken in positioning the trucks for maximum efficiency should be discussed with the service company. 2. Safe practical distance from the wellhead. Some years ago, major oil companies specified 100 or 200 ft from the wellhead for all their treat ments. We are all aware that in many cases, particularly mountainous terrain, this simply is not pos sible. We believe that efforts should be made to remove fuel tanks, engines and other devices as far as possible from the wellhead should a fire or leak occur. You need to use common sense protecting the wellhead and equipment in the event of a disaster. There are some locations where you must be very close to the wellhead to get the equipment on location. In this case, we recommend having the pumps and fluid ends located in the proximity of the wellhead, and the drive engines, blenders, and other assorted equipment as far away as possible. 3. Treating iron large enough to accommodate anticipated treating rate. Typical sizes of treating iron available from service companies are 2-inch, 3-inch, and 4-inch. A good working rule of thumb for a 2-inch iron is 8 bbls/min maximum rate; 3-inch, 20 bbls/min; and 4-inch, 37 bbls/min. A major consideration is that above these rates excessive friction pressures may occur. Also, when using proppants, you would expect a much shorter life on the iron in relation to pumping abrasive fluids, i.e., proppants. It should be noted that this rate or the total rate that we are talking about is from the final manifold that comes together from all of the trucks going to the wellhead. Obviously, each of the individual trucks does not have to have 4-inch iron if you are going to be pumping at 30 bbls/min. Typically, you may have 2- or 3-inch iron coming from the individual trucks whose rate may not exceed 8 to 10 bbls/min. 4. A check valve properly installed near the wellhead. The most common mistake in the use of check valves is placing them at great distances from the wellhead. The check valve is the last resort should your iron part between the check valve and the treating equipment. This no flow/return flow valve should be as close as possible to the injection point going into the well. Many times the vibration that typically occurs on a fracture treatments occurs at or near the wellhead. If one parts the pipe downstream of the check valve, then it has no functionality. You need to question the personnel to be sure they are using a flapper type check valve if ball sealers or large materials are going to be used compared to a dart type check valve which can be plugged off with ball sealers or diverting agents. Flapper type check valves need to be positioned so that the flapper will close in event of no positive flow through the pipe.



Page 24

TABLE 15 (Continued) 5. Pressure transducer at or near wellhead. It is not uncommon to have pressure transducers actually being placed back at the pump trucks. This is not a disastrous situation, but it can be costly. You need to have the pressure transducer as close to the wellhead, because that is the hydraulic horsepower that you are paying for. If you put the transducer at greater distances from the wellhead, you have to pay for the friction between the pump trucks and the wellhead. This pressure can be much higher if the service company is using small iron to get to a manifold or small iron to go to the wellhead. 6. Tree saver, if required, properly installed. A major consideration is to be sure that the tree saver is, in fact, pumped down and in place and seated in the tubing. You need to make sure that the annulus valve or the wing valve is left open during the treatment assuring that the tree saver is in fact installed and sealing off in the tubing. Never shut in a wing valve and trust the tree saver to work. If the tree saver or the packer on the tree saver fails, you will be aware of failure with fluid coming out the wing valve. Do not exceed the maximum allowable rate for each size tree saver. Excess rate can cause the tubing to be cut below the isolation tool. Refer to service company guidelines. 7. Lines properly staked. Staking of pumping lines is particularly important when using energized fluids. If a line parts on a location, it is not uncommon for that line to blow up into the air and flail around the location causing potential loss of life and great injury. Staking of lines requires physical labor, but should be a requirement for safety. 8. All irons should be flexible. One of the major reasons for catastrophic failure of treating iron on fracture treatments, cementing treatments, etc. is that at some point in the installation of the treating iron, improper use of chicksans left a treating line virtually rigid. 9. Check valve and plug valve on each pump pretested before a job. This is a controversial item and may not be an absolute necessity depending upon the pressures and type of jobs being conducted. When treating wells where the pressures are high and there is potential for loss of a well, it would seem prudent to have the ability to isolate individual pumps during the treatment for repair of equipment or leaks. By having a check valve and a plug valve on each pump, you have a double safety device so if the check valve fails, you have a backup whereby pumping equipment can be individually isolated. The failure of a plug valve or a check valve without a backup on a treatment would almost necessitate the shut down of the entire job should a leak occur. We have found on many locations that check valves in many areas have not been maintained and are subject to leaking. We have also noted on many locations that service companies do not even put a blocking valve between their pump trucks and the wellhead. This necessitates going to the wellhead and shutting the well in should a failure occur between the wellhead and the pump. Many times this type of failure will result in the inability to get to the wellhead. We, therefore, recommend plug valves and checks between each pump and blocking valves at the wellhead.



Page 25

TABLE 15 (Continued) 10. Check minimum and maximum rates for trailer manifold, if used. It happens many times that pigs, manifold trailers, ground manifolds, or other terminology used for this type of equipment are designed for a maximum rate or in many cases for a minimum rate. Ile same restrictions apply on maximum rate through the manifold trailer as far as discharge lines. If you are going to have to pump 40 or 50 bbl/min and you have a 3-inch I.D. discharge line in the manifold trailer or the manifold itself, severe corrosion or friction will occur in the manifold. Additionally, these trailer manifolds or ground manifolds have large I.D. suctions. This can cause a great deal of proppant settling and potential plugging off on low viscosity delayed crosslink jobs or foam frac treatments where high proppant concentrations are being pumped. Discuss the potential settling out of high concentrations of proppant in low viscosity fluids with the service company if trailer manifolds are going to be used where these conditions exist. 11. Check for sufficient suction hose and evaluate velocity per hose. It is very common to find insufficient suction hose being used between the frac tanks and the blender and additionally insufficient hose being used on the discharge side of the blender. A good rule of thumb for 10 to 20 ft sections of 4-inch hose on the backside of the blender is that you must have one hose per 10 bbl/min of suction required for thin fluid, i.e., prepad or flush fluid. You should have one 4-inch hose for 5 bbl/min if pumping a 50 or 60 lb viscous gel. In the case of the discharge side where you are using pressurizing pumps, you need at least one hose for 10 bbl/min of discharge rate. Obviously, you need to consider the length of hosing and add additional hoses if there are indications of pumps starving, i.e., not getting fluid. This becomes a very important consideration on large treatments where many trucks are positioned at fairly large distances from the pressurizing blender. There is another consideration that needs to be taken into account when using high concentrations of proppant, as in foam fracturing treatments. Here, you need to maintain high velocities per hose to keep settling out and slugging of proppants occurring in low viscosity fluids. Where pumping very high concentrations of proppants such as 18 to 21 lb/gal from the blender to the pump trucks, you need to keep the hose length as short as possible and use as small an I.D. hose as will achieve the necessary rate without starving the pump. 12. Check horsepower and plunger sizes of pumps on location. This would appear to be something that is obvious and not the responsibility of the quality control engineer. That simply is not the case. You need to question the service engineer and find out the plunger size and horsepower of all trucks on location. By doing so and having him give you a flow rate versus pressure at various gear rates for the pumps, you have a backup for flow should flowmeters or other devices fail during the treatment. Additionally, it is not uncommon to have equipment on location that is not suited for the pumping pressures anticipated on the treatment. This would occur if large size plungers were on location where very high pressure pumping would occur. Human beings are used to set up equipment, and people make mistakes. The use of equipment not designed for high pressure pumping or alternatively high rate pumping where small size plungers are on pumps on location can cause very rapid failure of this equipment


QUALITY CONTROL GUIDELINES Page 26

TABLE 15 (Continued) 13. Check flow monitoring equipment before the job. It is always advisable to circulate the equipment on location and be sure that flowmeters, densiometers, etc. are functioning prior to starting the treatment. This should be done the day before or early in the morning of the treatment so that any electronic problems can be worked out and not delay treatments. Ensure that the flowmeters are properly sized for the designed pump rates. This is especially important on foam treatments, because liquid pump rates are typically much lower than on normal non-foam treatments. Know the minimum flow rate the meters can measure accurately. This applies to all types of meters (turbine, venturi, mass, etc.). 14. Estimate available fluid removable from the tanks. Depending upon the type of frac tanks used, there is always a certain portion that is simply not practically removed from that tank during that treatment. With large lay down 500 bbl tanks, it is not uncommon that you will leave 50 bbls or so of fluid in the tank. Attempting to suck lower than this on small volume or high rate treatments can cause loss of suction resulting in catastrophic problems at the blender. Work with the service company along these lines making sure that you have sufficient fluid to do the fracture treatment. Another approach would be to use work tanks to supply fluid to the primary fracturing blender. The work tanks are kept full, providing good hydrostatic pressure, by pumping from the other tanks into the work tank using a centrifugal pump or another blender. This will allow you to draw the fluid level in the other tanks as low as possible without the potential for losing suction at the primary blender. On large fracture treatments it is not uncommon to use two or three work tanks. It is never a good practice to suck out of 8 or 10 tanks simultaneously on a treatment. This allows no visual monitoring of pump rate during a treatment. You can very easily suck one of the tanks all the way down and lose prime, potentially screening out the well. 15. Check placement of proppant storage to assure convenient movement and access to standby blender. It obviously does no good to have standby blenders if you cannot get proppant to that blender during the treatment. A standby blender should be one that can immediately come on if you lose the primary equipment. The standby blender should be primed up and running before and during the treatment. It is also good practice to ask the service company to bring on the standby blender during the prepad of the treatment to see its efficiency in doing so, and then go back to the primary equipment. You need to physically look and be sure that proppant can get to the blender. One needs to check suction hoses and discharge hoses and be sure they are properly rigged up and chemical can be transferred and added when using a standby blender. 16. Double check working pressure rating on frac iron. We recommend physically walking around looking at the iron, and questioning the people on location if something does not look right. You should ask the personnel if all the iron is, in fact, the same pressure rating. A common problem here are fittings or connections at the wellhead that may or may not be supplied by the service company. Examples of disastrous occurrences are using low pressure L’s or T’s as crossover to the service company equipment. Double checking this equipment is an absolute must for safety and prevention of potential catastrophic accidents.



Appendix C Procedures and Surface Equipment for Implementing the Forced Closure Fracturing Technique (Excerpt from “New Techniques and Quality Control Find Success in Enhancing Productivity and Minimizing Proppant Flowback” Ely, Arnold, and Holditch, 1990, SPE 20708)


FORCED CLOSURE IMPLEMENTATION PROCEDURE 1. Be sure that the wellhead and flowback manifold system are installed and tested so the well can be flowed back within 30 seconds of completing flush. Figure 12 illustrates a typical surface layout for forced closure implementation. 2. If a liquid fracturing fluid is used, install a flow meter capable of monitoring rates from 10to 20 gallons per minute downstream of a variable choke. If a foam fracturing fluid is used, no flow meter is needed. The flowback rate of gas can be calculated from the pressure drop across the orifice. 3. Isolate the choke and flowmeter with a block valve during the treatment4. Insure that the choke is fully closed and isolated prior to starting the fracture treat ment. 5. Within 30 seconds after completing the flush, open the block valve with the choke still closed. If the choke fails, the block valve can be used as a back-up to regulate flow rate. 6. Open the choke slowly. Do not exceed a flowback rate of 10-15 gallons per minute for liquids or an equivalent rate for gases. 7. Monitor pressure vs time to detect fracture closure. 8. Continue to flow at a low rate for 30 minutes after near wellbore fracture closure has been detected. 9. The flowback rate can then be increased to 20-25 gallons per minute for liquids or equivalent rates for gases. 10. Continue flowing for an additional ’30 minutes. For normal pressured or energized produced fluids to measure sand content.wells, the flowback rate ran eventually be increased to 1-2 BPM. Always monitor the produced fluids to measure sand content. 11. Choke back the well as necessary when gas or oil flow rates become large. 12.Flow the well for several days or weeks using choke sizes no larger than 10-12/64 inch. 13.Monitor and record all data concerning flowing pressures and oil, gas and water flow rates.

Diagram illustrating surface layout required to implement forced closure

A Guide to Coal Bed Methane Operations

Recommend Documents