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Drinking Water
Academy
DRINKING
WATER
ACADEMY
Introduction to
Underground Injection
Control Permitting
App.
Yes
Issue
draft
permit
Issue
notice of
intent to
deny
* complete?
i No
Issue
NOD
Mail
schedule
to
applicant
Review
application,
draft permit
Prepare
statement
of basis,
public
notice
30-day
public
comment
period
Review
comments,
prepare
responses,
develop
final permit
Hold
public
hearing
Issue final
I
permit
decision
and
2
response
to
comments
Complete
adminis.
\
record
1
Permit
effective
in 30 days
unless
appealed
and
stayed
Chicago, Illinois
December 4 - 6, 2001
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DRINKING WATER ACADEMY
Introduction to Underground Injection
Control Permitting
AGENDA
DRINKING
WATER
ACADEMY
Tuesday, December 4,2001
9:00 - 9:15 a.m. Introductory Remarks
9:15-10:15
10:15-10:30
10:30 - 12:00 noon
12:00- 1:00 p.m.
1:00-2:30
2:30-2:45
2:45 - 4:45
4:45 - 5:00
Introduction to UIC Permitting
Break
Introduction to UIC Permitting
Lunch
Introduction to UIC Permitting
Break
Introduction to UIC Permitting
Questions and Answers
State or Regional
Representative
Mary Lou Rochotte,
Kemron
Larry Browning,
Geological Engineering
Specialties
Wednesday, December 5,2001
8:30 - 10:15 Introduction to UIC Permitting
10:15-10:30 Break
10:30 - 12:00 noon Introduction to UIC Permitting
12:00 - 1:00 p.m. Lunch
Mary Lou Rochotte,
Kemron
Larry Browning,
Geological Engineering
Specialties
-------
1:00 - 2:30 Introduction to UIC Permitting
2:30 - 2:45 Break
2:45 - 4:45 Introduction to UIC Permitting
4:45 - 5:00 Questions and Answers
Thursday, December 6,2001
9:00 - 9:15 a.m. Introductory Remarks
9:15 - 10:15 Introduction to UIC Permitting
10:15-10:30 Break
10:30 - 12:00 noon Introduction to UIC Permitting
12:00 - 1:00 p.m. Lunch
1:00 - 2:30 Introduction to UIC Permitting
2:30 - 2:45 Break
2:45-3:45 Introduction to UIC Permitting
3:45 - 4:00 Questions and Answers
State or Regional
Representative
Mary Lou Rochotte,
Kemron
Larry Browning,
Geological Engineering
Specialties
-------
Speaker Bios
Mary Lou Rochotte has 17 years experience as a geologist/scientist. As a Project
Geologist/Manager with KEMRON, Ms. Rochotte's project work has included permit
development and regulatory interpretation for the chemical industry, FAA Environmental
Due Diligence Audits, UST removal and closure, facility environmental audits, and Phase
I site assessments conducted in accordance with both ASTM and brownfields standards.
From October 1991 to May 1998, Ms. Rochotte served as the Geology Program Manager
for Ohio EPA. She managed the statewide underground injection control (UIC) program
for Class I, IV and V injection wells. She was instrumental in developing State statutes,
and responsible for developing State regulations and ensuring consistency with all
applicable portions of the Federal and State equivalents of the Safe Drinking Water Act
(SDWA) and Resource Conservation and Recovery Act (RCRA). Ms. Rochotte has an
M.A. in geology from Miami University in Oxford, Ohio, and a B.S. in geology from
Marietta College in Marietta, Ohio.
Larry Browning is an expert in every aspect of the UIC program. As a consultant or an EPA
employee, Mr. Browning has supported virtually every UIC regulatory initiative since the
program began, and has in-depth knowledge of all classes of UIC wells. Mr. Browning
was appointed special technical advisor to EPA's landmark Class I Regulatory
Negotiation Committee. For EPA's Class I petition review process, he developed
training documents and performed technical reviews of important petitions. He
performed two analyses of Class I mechanical integrity failures, spanning 1988 through
1998. Since 1975, he has performed more than 120 technical studies for EPA, and
prepared a two-volume technical manual on wireline testing of Class II injection wells
which is used in all ten EPA Regions. Mr. Browning worked with EPA's Region 6, and
supported writing the original UIC regulations. He has also performed ground water
investigations, well testing, and investigations of injection wells and hazardous waste
disposal facilities. Mr. Browning has a Master's degree in geology from the University of
Texas at Austin, and a Bachelor's degree in geology from Northern Kentucky University.
-------
About the DWA
-------
United States
Environmental Protection
Agency
Office of Water
(4606)
EPA 816-F-99-004
September 1999
&EPA Fact Sheet L
The Drinking Water Academy %
^3^
WHAT IS THE DRINKING WATER ACADEMY?
The Drinking Water Academy (DWA) is a long-term training initiative established by the
Office of Ground Water and Drinking Water (OGWDW) to expand EPA's capability to support
states and other organizations as they implement the Safe Drinking Water Act (SDWA)
Amendments of 1996. The goal of the DWA is to assist EPA, states and tribes to build program
capability to successfully carry out the SDWA requirements. This, in turn, will promote
increased program compliance and greater public health protection.
WHAT ARE THE CHALLENGES?
EPA created the DWA in response to the far reaching changes brought forth by the 1996
SDWA Amendments. The Amendments created new programmatic challenges for states and
water systems and also provided new funding opportunities to meet these growing needs. EPA
has promulgated and will continue to promulgate and implement new regulations. States, in
addition to maintaining their current drinking water programs, are required to adopt and
implement these new regulations and other requirements. For example, States must adopt new
microbial and disinfection by-products standards, increase source water protection efforts,
develop new funding programs to provide low-cost loans for the construction of important
drinking water infrastructure needs, and states must encourage greater public awareness and
involvement in how their drinking water programs are developed and implemented.
NEED FOR TRAINING?
The new requirements and approaches to regulating drinking water systems have increased the
need for training EPA, state, and tribal personnel, particularly those personnel new to SDWA
programs. The Academy will focus on helping EPA and states to maintain a high level of
expertise in their drinking water programs, which otherwise could be diminished through
personnel changes and lack of sustained training. The DWA will help strengthen the
knowledge of all staff about statutes, regulations, and other important SDWA requirements.
WHAT TYPES OF TRAINING NEEDS WILL BE ADDRESSED?
The DWA curricula are being developed by a workgroup composed of state and EPA personnel,
to meet the training needs of SDWA EPA and state program staff responsible for Public Water
System Supervision, Underground Injection Control, Ground Water, and Source Water
Protection programs. Training will take place through a combination of classroom style,
workshops, web-site based, and on-site inspections where appropriate. Field work, where
applicable, may include inspections of public water systems and UIC wells. Trainers will have
extensive experience with SDWA programs.
HOW CAN I OBTAIN MORE INFORMATION?
For general information on the SDWA, call the Safe Drinking Water Act hotline at
1-800-426-4791 or (202) 260-7908. For information on the Drinking Water Academy, please
visit the DWA website at http://www.epa.gov/safewater/dwa.html or contact James Bourne at
(202) 260-5557 or bourne.iames@epa.gov.
-------
&EPA
United States
Environmental Protection
Agency
Office of Water
(4606)
EPA EPA/816-N-01-003
October 2001
Drinking Water
Academy Bulletin
D W A
r
In This Issue
The Drinking Water
Academy Offers UIC
Training
The DWA Holds Its Annual
Advisory Board Meeting
The DWA Establishes a
Sanitary Survey Web Site
i.
Drinking Water Academy
Contacts ,
Training Course Schedule
The DWA Offers New Training
for Comprehensive Performance
Evaluations
Te Office of Ground Water and Drinking
Water, the Office of Research and
Development, and EPA Region 6 have
developed a series of courses addressing compre-
hensive performance evaluations (CPEs). A CPE
is an evaluation of a surface water plant to
determine if the existing facility (design, opera-
tions, maintenance, and administration) is
achieving optimized performance. Four courses
are available:
1 CPE 101 - Fundamentals of CPEs. This
classroom training raises awareness and
lays a foundation for understanding the
importance of CPEs. This fundamentals
course is the first step in building capacity
and familiarizing States, technical
assistance providers, and consulting
engineers with the concepts of a CPE.
Note that this course is not intended to
train students to conduct a CPE. This
basic training course addresses the
following questions:
What is a CPE?
How does a CPE work?
How do CPEs fit into the bigger
picture (e.g., Area Wide Optimization
Program)?
Why is a CPE beneficial to the State
and the water system?
States deciding to conduct their own
CPEs would progress to CPE 201 and
CPE 301, whereas States deciding to have
a third party conduct the CPEs would
progress to CPE 202.
CPE 201 - Introduction to CPEs. The
concepts behind conducting CPEs at
surface water treatment plants are
introduced through a one-day series of
classroom presentations, workshops,
followed by a three-and-a-half day field
exercise at a surface water treatment
plant. After the course, a full CPE report
is produced based on the findings of the
field exercise. Trainees are guided
through the process by experienced
instructors. The trainees help the instruc-
tors with the investigation at the surface
water plant and present some of the
group's findings to the plant staff at an
exit meeting at the end of the course.
CPE 202 - CPE Oversight and Review.
This course covers the components of a
CPE in more detail, helps students
establish a procedure to approve third
parties, and trains students to understand
what to look for in reviewing a CPE
report. One day of classroom training is
followed by a two-and-a-half day field
exercise at a surface water treatment
plant.
CPE 301 - CPEs (Progressive). As a
follow-up to CPE 201Introduction to
CPEsup to six trainees are facilitated
through two additional drinking water
system CPEs. After completion of these
additional CPEs, in addition to the one
CPE performed in the Introduction to
CPEs training, the trainee will indepen-
dently be able to conduct a CPE. Each
session consists of three-and-a-half days
of field work at a drinking water system
and one report. In these evaluations, the
Continued on page 2
-------
ฉ
The Drinking Water Academy Offers UIC Training
From October IS to 18, 2001, the Drinking
Water Academy (DWA) will hold two
underground injection control (UIC)
training courses in Washington, DC. On
October 15, the DWA will present Introduction
to the Underground Injection Control Program.
This training module is intended for non-
technical audiences. It describes the foundation
The DWA Holds Its
Annual Advisory Board
Meeting
Te Drinking Water Academy Advisory
Board met on July 23 and 24 in Reno,
NV for its annual meeting. The Board
was welcomed by Galen Denio, Nevada Bureau
of Health Protection Services, who provided a
State perspective on training needs and ap-
proaches. The agenda for the meeting addressed
a number of topics, including the FY 2001-2002
training schedule, recent international activities,
comprehensive performance evaluation training,
sanitary survey training, and training develop-
ment priorities for FY 2002. The Advisory Board
also had lively discussions about distance
learning and setting training standards. Both are
projects the Board will undertake during FY
2002.
of the UIC program; discusses the framework of
the UIC program; explains the five classes of
wells and their construction; and explains the
challenges facing today's UIC programs.
On October 16-18, DWA will present a pilot of
Introduction to UIC Permitting. This course,
which is for technical staff, will introduce
inexperienced federal or State permit writers to
the requirements for UIC permitting and their
responsibilities in reviewing the permit applica-
tion and developing permit conditions, Tlie two-
and-a-half-day course, which includes class
discussions and exercises, covers these topics:
1 Site evaluation, including site and
injectate characteristics.
1 Monitoring and mechanical integrity
testing.
1 Formation testing.
1 Area of review.
1 Injection dynamics.
1 Well construction.
1 Financial responsibility.
1 Public participation.
The meeting ended with a presentation of
plaques by Jamie Bourne to members of the
Advisory Board. He thanked them for their
excellent work on behalf of the DWA. Mario
Salazar also presented Jamie with a plaque from
the OGWDW members of the Advisory Board in
recognition of his good leadership. 1
DWA Offers New CPE Training (
-------
The DWA Establishes a Sanitary Survey Web Site
Te Drinking Water Academy has estab-
lished a Web site to provide a focal point
for sanitary survey training and other
resources that EPA offers.
A sanitary survey is an on-site review of the
water source, facilities, equipment, operation,
and maintenance of a public water system for the
purpose of evaluating the adequacy of such
source, facilities, equipment, operation, and
maintenance for producing and distributing safe
drinking water. Sanitary surveys are becoming an
increasingly important means of educating
system operators and identifying systems that
need technical or capacity development assis-
tance.
The Drinking Water Academy provides
sanitary survey training to upgrade and maintain
the ability of inspectors to conduct comprehen-
sive, technically sound sanitary surveys of small
water systems. EPA also offers a training
manual, guidance materials, and videos to
support sanitary surveys. These resources are
accessible from the Web site, or can be ordered
using the form on the Web site. Visit the sanitary
Drinking Water Academy Contacts
Contact
Location
Telephone
E-mail
Jackie LeClair
EPA Region
1
(617)
918-1549
leclair.jackie@epa.gov
Norma Ortega
EPA Region
2
(212)
637-4234
ortega.norma@epa.gov
Rick Rogers
EPA Region
3
(215)
814-5711
rogers.rick@epa.gov
Janine Morris
EPA Region
4
(404)
562-9480
morris.janine@epa.gov
Helen Lenart
EPA Region
5
(312)
353-6058
lenart.helen@epa.gov
Bill Davis
EPA Region
6
(214)
665-7536
davis.williamh@epa.gov
Stephanie Lindberg
EPA Region
7
(913)
551-7423
lindberg.stephanie@epa.gov
Dan Jackson
EPA Region
8
(303)
312-6155
jackson.dan@epa.gov
Barry Pollock
EPA Region
9
(415)
744-1854
pollock.barry@epa.gov
Bill Chamberlain
EPA Region
10
(206)
553-8515
chamberlain.william@epa.gov
Mark Anderson
Virginia
(804)
786-5569
manderson@vdh. state, va. us
Theresa Rogers
Texas
(512)
239-1734
trogers@tnrcc.state.tx. us
Stew Thornley
Minnesota
(651)
215-0771
stew. thornley@health. state, mn. us
Murlene Lash
EPA HQ
(202)
260-7197
lash.murlene@epa.gov
Mario Salazar
EPA HQ
(202)
260-2363
salazar.mario@epa.gov
James Bourne
EPA HQ
(202)
260-5557
bourne.james@epa.gov
survey Web site at http://www.epa.gov/safevvater/
dwa/sanitarysurvev.html.
The Learner's Guide for Conducting Sanitary
Surveys is available in a Spanish translation. To
obtain a copy, contact Mario Salazar at (202)
260-2363 or salazar.mario@epa.gov. [~
EPA Photo
Sanitary surveys have been a critical component of State
drinking water programs for decades. They are used to prevent
and correct sanitary deficiencies and are indispensable for
ensuring the delivery of safe water on a sustainable basis.
-------
o
Training Course Schedule
Course Title
Audience
Date Scheduled
Location
Contact
Risk Communication
under the Safe Drinking
Water Act (pilot)
State and Regional drinking
water staff, local health
department staff
Aug. 8 & 9, 2001
Morgantown, WV
Rick Rogers
(215) 814-8711
rogers.rick@epa.gov
Phase ll/V Chemicals
and Radionuclides Rules
State and federal drinking
water staff
Aug. 9 & 10. 2001
Dallas, TX
Ronald Bergman
(202) 260-6187
bergman .ronald@epa .gov
Risk Communication
under the Safe Drinking
Water Act (pilot)
State and Regional drinking
water staff, local health
department staff
Aug. 15 & 16, 2001
Washington, DC
Jamie Bourne
(202) 260-5557
bourne.james@epa.gov
Phase ll/V Chemicals
and Radionuclides Rules
State and federal drinking
water staff
Aug. 16 & 17, 2001
Denver, CO
Ronald Bergman
(202) 260-6187
bergman.ronald@epa.gov
SDWIS/STATE Initial State and EPA drinking Aug. 21-23, 2001 Jefferson City. MO Darrell Osterhaudt
User Training water staff who use (673) 751-1187
SDWIS/STATE Sept. 11-13, 2001 Trenton, NJ Unda Friedman
(609) 292-5S50
Sept. 25-27, 2001 Little Rock. AR Karen Howard
(501) 661-2543
Oct. 16-18, 2001 Frankfort, KY Vlckl Ray
(502) 564-3410
Oct. 30-Nov. 1, 2001 Denver, CO Robert Miller
(303) 692-3587
SDWIS/STATE System
Administration Training
State and EPA drinking
water staff who use
SDWIS/STATE
Aug. 14-16,
Aug. 28-30,
2001
2001
Frankfort, KY
Denver, CO
Vicki Ray
(502) 564-3410
Robert Miller
(303) 692-3587
Sanitary Survey Training Alaska State drinking water
staff
Aug. 27-30,
2001
Alaska
Bill Davis
(214) 665-7536
davis.williamh@epa.gov
Sanitary Survey Training
Colorado State drinking
water staff
Aug. 28-31,
2001
Denver, CO
Bill Davis
(214) 665-7536
davis.williamh@epa.gov
Surface Water
Treatment Rule. Total
Coliforn Rule. IESWTR,
and Stage 1 DBPR
EPA and State drinking
water staff, training provid-
ers and water system
operators
Aug. 14-16,
2001
New York, NY
Ann Hanger
(202) 260-6781
hanger.ann@epa.gov
Sanitary Survey
Troubreshooter's
Training
State drinking water staff
Aug. 20-23,
2001
Cumberland, MD
Rick Rogers
(215) 814-5711
rogers.rick@epa.gov
Risk Communication
under the Safe Drinking
Water Act
State and Regional drinking
water staff, local health
department staff
Sept. 5 & 6,
2001
Mlddletown, PA
Rick Rogers
(215) 814-5711
rogers.rick@epa.gov
CPE Oversight and
Review (CPE 202)
State staff responsible for
establishing and overseeing
a third-party program
Sept. 10-13,
2001
Seattle, WA
Nicole Foley
(202) 260-0875
foley.nicole@epa.gov
UIC Inspector Training Federal and State UIC Sept. 10-14, 2001 Bakersfield, CA Steve Piatt
inspectors (215) 814-5464
platt.steve@epa.gov
Continued on page 5.
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Training Course Schedule (Continued)
Course Title
Audience
Date Scheduled
Location
Contact
SDWIS/FED Data Entry
Federal and State personnel
whose responsibilities
Include entering data Into
the SDWIS/FED system
Sept. 17-21, 2001
Boston, MA
Joe Lewis
(202) 260-7079
lewis.Joe@epa.gov
SDWIS/STATE
Advanced User Training
State and EPA drinking
water staff who use
SDWIS/STATE
Sept. 18-20. 2001
Oct. 2-4. 2001
Dover, DE
Trenton, NJ
Anita Beckel
(302) 739-5410
Linda Friedman
(609) 292-5550
Introduction to SDWA
and the Public Water
System Supervision,
Underground Injection
Control, and Source
Water Protection
Programs
EPA Region 8 State and
federal drinking water staff
Sept. 18-20, 2001
Denver, CO
Marty Swickard
(303) 312-7021
swickard.marty@epa.gov
Sanitary Survey Training
Utah State drinking water
staff
Sept. 18-21, 2001
Salt Lake City, UT
Bill Davis
(214) 665-7536
davi8.williamh@epa.gov
IESWTR and Stage 1
OBPR
State and federal drinking
water staff
Sept. 20-27, 2001
Alaska
Nicole Foley
(202) 260-0875
foley.nlcole@epa.gov
Phase ll/V Chemicals
and Radionuclides Rules
State and federal drinking
water staff
Sept. 25-26, 2001
Chicago, IL
Ronald Bergman
(202) 260-6187
bergman.ronald@epa.gov
Introduction to SDWA
and the PWSS Program
Montana State drinking
water staff
Sept. 25. 2001
Helena, MT
Marty Swickard
(303) 312-7021
swickard.marty@epa.gov
Sanitary Survey Training
Guam State drinking water
staff
September 2001
Guam
Bill Davis
(214) 665-7536
'davls.williamh@epa.gov
Managerial and Financial
Capacity Development
EPA Region 8 federal and
State drinking water staff
September or October
2001
Denver. CO
Marty Swickard
(303) 312-7021
swickard.marty@epa.gov
Phase ll/V Chemicals
and Radionuclides Rules
State and federal drinking
water staff
Oct 2 & 3, 2001
Wahham, MA
Ronald Bergman
(202) 260-6187
bergman .ronald@epa .gov
Risk Communication
under the Safe Drinking
Water Act
EPA Region 8 federal and
State drinking water staff
Oct. 1T & 12, 2001
Denver. CO
Marty Swickard
(303) 312-7021
swickard.marty@epa.gov
Introduction to the UIC
Program
Federal and State drinking
water staff new to the UIC
program, or who want a
non-technical overview of
the UIC program
Oct. 15, 2001
Washington, DC
Mario Salazar
(202) 260-2363
saiazar.mario@epa.gov
Risk Communication
under the Safe Drinking
Water Act
Idaho State drinking water
staff and water system
operators
Oct. 15 & 18, 2001
Boise, ID
Jeff Long
Idaho Rural Water
(208) 343-7001
Introduction to UIC
Permitting (pilot
presentation)
New or inexperienced
federal and State UIC
permit writers with a
technical background
Oct. 18-18. 2001
Washington, DC
Mario Salazar
(202) 260-2363
salazar.mario@epa.gov
Continued on page 6.
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0
Training Course Schedule (Continued)
Course Title Audience Date Scheduled
Location
Contact
CPE Oversight and
Review (CPE 202)
State staff responsible for
establishing and oversee-
ing a third-party program
Oct. 16-19, 2001
Boston, MA
Nicole Foley
(202) 260-0875
foley.nicole@epa.gov
Risk Communication
under the Safe
Drinking Water Act
Washington State drinking
water staff and water
system operators
Oct. 18 & 19, 2001
Shelton, WA
Scott Hemingway
Evergreen Rural Water
(509) 962-6326
Risk Communication
under the Safe
Drinking Water Act
Oregon State drinking
water staff and water
system operators
Oct. 22 & 23, 2001
Tillamook, OR
Cheris Lane
OR Assn. of Water Utilities
(503) 873-8353
programs@oregonvos.net
Sanitary Survey
Training
Alaska State drinking
water staff, TA providers
and third-party sanitary
surveyors
October and November
2001
Alaska
Lee Michalsky
(907) 747-7755
leeamichalsky@uas.alaska.edu
Phase ll/V Chemicals
and Radionuclides
Rules
State and federal drinking
water staff; technical
assistance providers
Oct. 31-Nov. 2. 2001*
Nov. 6 & 7, 2001
Nov. 15 & 16, 2001
Orlando, FL
Seattle, WA
Kansas City, KS
Ronald Bergman
(202) 260-6187
bergman.ronald@epa.gov
Point of Use/Point of
Entry Training
Federal and State drinking
water staff; technical
assistance providers
Fall 2001
Philadelphia, PA
Rick Rogers
(215) 814-5711
rogers.rick@epa.gov
IESWTR and Stage 1
DBPR
State and federal drinking
water staff; technical
assistance providers
Fall 2001
Atlanta, GA
Nicole Foley
(202) 260-0875
foley.nicole@epa.gov
Compliance
State and federal drinking
Fall 2001
Boston, MA
Nicole Foley
Determinations
water staff; technical
New York. NY
(202) 260-0875
assistance providers
Philadelphia, PA
foley.nicole@epa.gov
Dallas, TX
Kansas City, KS
Seattle, WA
Simultaneous
State and federal drinking
Fall 2001
Seattle. WA
Nicole Foley
Compliance
water staff; technical
(202) 260-0875
assistance providers
foley.nicole@epa.gov
Unit Treatment
State and federal drinking
Fall 2001
Boston, MA
Nicole Foley
Processes
water staff; technical
Philadelphia, PA
(202) 260-0875
assistance providers
Atlanta. GA
foley.nicole@epa.gov
Chicago, IL
Dallas, TX
Kansas City, KS
Denver, CO
Seattle, WA
Managerial and
State and federal drinking
Fall 2001
Chicago, IL
Peter Shanaghan
Financial Capacity
water staff; technical
Dallas, TX
(202) 260-5813
Development
assistance providers
shanaghan.peter@epa.gov
State and federal drinking
Fall 2001
Boston, MA
Peter Shanaghan
Financial Capacity and
water staff; technical
(202) 260-5813
Ratemaking
assistance providers
shanaghan.peter@epa.gov
Assessing Capacity
through Sanitary
Surveys
State and federal drinking
water staff; technical
assistance providers
Fall 2001
Dallas, TX Jamie Bourne
(202) 260-5567
bourne.james@lepa.gov
'This Is a condensed training of the Phase ll/V, radionuclides, IESWTR, Stage 1 DBP, and FBR Rules.
Continued on page 7.
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ฉ
Training Course
Schedule (Continued)
Course Title
Audience
Date Scheduled
Location
Contact
Fundamentals of CPEs
(CPE 101)
Small system operators;
State and federal drinking
water staff; technical
assistance providers
FaU 2001
New York. NY
Philadelphia, PA
Kansas City. KS
Nicole Foley
(202) 260-0875
foley.nicole@epa.gov
Introduction to Source
Water Protection
State and federal drinking
water staff; technical
assistance providers
Fail 2001
San Francisco. CA
Jamie Bourne
(202) 260-5557
bourne.james@epa.gov
Source Water Protection
Measures
State and federal drinking
. water staff; technical
assistance providers
Fall 2001
San Francisco. CA
Alaska
Steve Ainsworth
(202) 260-7769
ainsworth.steve@epa.gov
Introduction to the UIC
Program
State and federal drinking
water staff; technical
assistance providers
Fan 2001
Chicago, IL
Mario Salazar
(202) 260-2363
salazar.mario@epa.gov
Introduction to UIC
Permitting
State and federal drinking
water staff; technical
assistance providers
FaU 2001
Chicago, IL
Dallas, Texas
Mario Salazar
(202) 260-2363
ealazar.mario@epa.gov
Risk Communication
under SDWA
State and federal drinking
water staff; technical
assistance providers
Fall 2001
Denver, CO
Marty Swickard
(303) 312-7021
swickard.marty@epa.gov
Filter Assessment
State and federal drinking
water staff; technical
assistance providers
Fall 2001
Boston, MA
Training Skills Delivery State and federal drinking Fall or winter 2001 TBD (2 locations; Jamie Bourne
Workshop water staff; technical one in the East and (202) 260-5557
assistance providers one in the West) bourne.james@epa.gov
Introduction to
Comprehensive
Performance Evaluations
(CPE 201)
State field staff responsible
for evaluating operations of
surface water plants; State
and EPA Regional staff
reviewing CPE reports
Dec. 10-14. 2001
Albuquerque, NM
Bill Davis
(214) 665-7536
davis.wiliiamh@epa.gov
Progressive CPE
Training (CPE 301)
State field staff responsible
for evaluating operations of
surface water plants; State
and EPA Regional staff
reviewing CPE reports
Feb. 15-18, 2002
Albuquerque. NM
Bill Davis
(214) 66S-7536
davis.wiliiamh@epa.gov
Progressive CPE
Training (CPE 301)
State field staff responsible
for evaluating operations of
surface water plants; State
and EPA Regional staff
reviewing CPE reports
May 13-17, 2002
Albuquerque, NM
Bill Davis
(214) 665-7536
davis.wiliiamh@epa.gov
Sanitary Survey Training EPA Region 8 State and
federal drinking water staff
June 2002
Denver, CO Marty Swickard
(303) 312-7021
swickard.marty@epa.gov
'Final dates and locations will be posted on the DWA Web site as soon as they are available (www.epa.gov/safewater/dwa/calendar.html).
DWA courses may be presented as requested. See the course catalog on the DWA Web site for more information (www.epa.gov/safewater/
dwa/course.html).
-------
<^6DS%
^ PRO^
DRINKING
WATER
ACADEMY
Visit EPA's Drinking Water Academy Web Site
at:
http://www.epa.gov/safewater/dwa.html
The Drinking Water Academy's Web site is your source of information for
drinking water training. The site includes:
~~~ Background information on the DWA,
~~~ A regularly-updated calendar of course offerings, and
Detailed course descriptions.
The Electronic Workshop provides self-paced training modules that give a broad
introduction to the many facets of the Safe Drinking Water Act. In addition, the
site provides links to other organizations that provide relevant training.
-------
Intro to UIC Permitting
-------
November 2001
Introduction to UIC
Permitting
1-1
-------
November 2001
Course Objectives
Understand the key elements required for
UIC permits, including:
- USDW identification and exemptions
- Area of review
- Construction and testing procedures
- Operational and maintenance conditions
- Financial assurance documentation
- Public participation requirements
This course is intended to acquaint technical personnel with basic permitting
components and issues. The course has been designed based on the required
elements of the EPA permit application and attachments, which are
completed and submitted by the applicant.
At the course's completion, you will have been introduced to key elements
for which you will be responsible in reviewing permit applications and
developing permit conditions.
This course will provide resources for future reference as you work with more
experienced permit writers to enhance your skills and prepare to make
decisions that protect critical underground sources of drinking water.
1-2
-------
November 2001
Course Objectives
Know what data should be obtained prior
to and during well construction
Understand the construction and
cementing processes
Have insight into setting permit
conditions for construction, operation,
maintenance and monitoring
In order to achieve these objectives, the instructors will:
^ Present technical information specific to permitting issues and writing
permits;
> Explain the regulatory basis for the various key permitting elements;
* Discuss the relevance of the regulations to the various well classes and
protection of USDWs;
* Indicate the availability of options or alternative methods for solving
permitting problems;
* Present resources available to assist you as you review permit
applications; and
^ Provide a forum for sharing permit strategies among UIC professionals.
1-3
-------
November 2001
Course Objectives
Know plugging and abandonment
requirements and how to address well
failures
Understand financial assurance
requirements
Explain public participation in the UIC
permitting process
The course objectives are focused on giving you a concise but thorough
review of these key permitting elements.
This course manual and the supporting materials in the appendices should be
used as references as you review applications and develop permits in the
future.
1-4
-------
November 2001
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The UIC Permit Application Form marks the beginning of the permit process
(filled in by the operator, of course).
1-5
-------
November 2001
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The Completion Form and required attachments for Injection Wells usually
marks the end of the permitting process. During this course, we are going to
talk about everything in-between.
1-6
-------
November 2001
Lesson 2
Basic Permit
Application Form
DRINKING
WATER
ACADEMY
iPROt^
The first step in the process of acquiring a permit for a UIC facility is, of
course, filing an application. In addition to the basic permit application form
and various attachments, each project needs to be evaluated to determine if
any of the following Federal laws apply, as listed in 40 CFR 144.4:
* Wild and Scenic Rivers Act;
* The National Historic Preservation Act of 1966;
* Endangered Species Act;
* The Coastal Zone Management Act; and,
* Fish and Wildlife Coordination Act.
If any of these acts are applicable to the project, additional interagency
coordination will be necessary, and the time frame for permit review and
issuance should be expected to be significantly long than usual. These Federal
statutes are not listed and included in the application, so make sure you think
about them early in the process.
2-1
-------
November 2001
The UIC Permit Application Form marks the beginning of the permit process
(filled in by the operator, of course).
This same form is used for all injection well classes, so some of the
information presented in this course regarding the process and general
requirements for permitting will help you when permitting Class I, II, HI and
V wells. Most of the technical information presented, however, is focused on
Class I, Class n and Class III injection wells.
The basic form is very simple, providing information on the owner and
operator (who may not be the same), type of well and facility, status of the
well, basic site information (how many wells at the site, etc.), well location
information, and whether the well is on Indian lands. This last little box
makes a big difference, as the Regions have special agreements with Tribes.
A certification that carries a tremendous legal weight finishes the form. The
owner or operator certifies under penalty of law that everything submitted in
the application is true and accurate. 40 CFR 144.32 lists who is authorized to
sign and certify the application. Terms such as "responsible corporate
officer," "general partner," and "principal executive officer" are used - a
person with decision making authority. By doing so, he or she states that the
information being submitted has been personally reviewed, and thus personal
liability is attached.
The real work starts after this first page!
2-2
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November 2001
Application
Attachments
Attachments required vary by well type and
status (new versus existing)
Smallest number possible is nine (new Class
II well)
Provide the details needed to determine if the
site and well meet Federal criteria
The application form is actually six pages long, including all the directions.
It is one of a series of forms known as the "7520s," which are various
reporting forms used in the Federal UIC Program. It is available on EPA
Region 5's website at:
www.epa.gov/r5water/uic/forms.htm
The form alone, without the instruction sheets, is available as part of the
7520s forms at www.epa.gov/safewater/7520s.html.
Primacy States (States that have been delegated authority for the UIC
Program and implement it with oversight from EPA) have their own
application forms. However, the various elements in the Federal applications
must be included in State applications, since State programs have to be at
least as stringent as EPA. While additional information may be required by
States, the majority of the permitting elements and processes we discuss in
this course are applicable to and useful for State UIC program personnel.
A number of attachments must be prepared and submitted with the first page
of the application. Class II wells have the least number of required
attachments, and the instruction form tells operators to expect to take about
16 hours to prepare the application. Class I and III wells must submit more
information, and the instruction sheet directs operators to expect to spend 200
hours to prepare a Class III application and 255 hours for a Class I well
application. You can guess, based on the time, a lot of detail is included.
2-3
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November 2001
So Many Details...
Details of
- Site geology
- Other nearby wells
- Proposed construction, completion and
operation
- Plans for plugging and abandonment
- Demonstrating financial ability
The application contains many details about the owner and operator, the
proposed site, and the way the well will be designed, operated, monitored and
maintained. All the information sent to and from EPA during the permitting
process is public information, unless the owner/operator makes a claim of
confidentiality which we will discuss later.
Some of the information may not be exceptionally exciting as you read it, and
might be easy to gloss over. But as a permit reviewer and writer, you need to
pay close attention to every detail. Remember that all those details lead back
to protection of USDWs. Also, the items listed in the various attachments to
the application are required by the regulations. It is important to identify any
deficiencies and list those in writing to the applicant. Failure to identify and
deal with deficiencies not only puts the environment at risk, but also may
unnecessarily cause the operator to be out of compliance later on.
2-4
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November 2001
Regional Checklists
Each Region has a permit checklist for at
least some well classes
Provides a good summary and check of
required elements in basic form
Will not answer whether the application is
genuinely complete
Technical review of the details essential
Most Regions have a checklist for reviewing UIC permit applications. Keep
in mind that while the checklist is helpful, many of the details to review are
site-specific. Just because information is presented does not mean it is
adequate to fully address questions that arise about the proposed facility. An
application needs to be complete in all aspects - it must contain all required
elements, and it must provide the technical details in each element to
demonstrate that a permit should and can be issued.
Use the checklist to see if all the required elements are included, but use good
science and logic to make sure the permit application really is complete.
We are going to discuss each of the attachments that can be required in the
permit application for Classes I, II and III injection wells. They are not
presented in the order they are listed on the application, but they are all here.
If you refer back to this training manual, and use the resources available to
you in the UIC Program personnel around you, you should be able to wade
through a fairly complex application and survive!
2-5
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November 2001
Lesson 3
Existing Permits
3-1
-------
November 2001
Existing EPA Permits
All other EPA permits at the facility must be
listed
- NPDES
- RCRA
- Title V, PSD or other air permits
- State permits
Information provided must include program
area and permit number
Gives permit writer ability to check compliance
and ensure permitting consistency
The applicant must include a list of all other EPA permits that are in existence
for the facility at which the UIC wells are located. This includes both EPA
and State permits under the NPDES (surface water discharge), RCRA
(hazardous waste treatment, storage, and disposal), CAA (Title V or
Prevention of Significant Deterioration), or other permit programs (see 40
CFR 144.31(e)(1) and (e)(6)). When reviewing this information, the permit
reviewer should verify this information by contacting the other program areas.
Additionally, the reviewer should investigate what the compliance rate of the
owner/operator has been under these existing permits. This can help
determine whether special terms and conditions may be necessary if the
owner/operator is historically a significant noncomplier in other programs. At
a minimum, it will alert you to closely evaluate details, and ask questions, if
the owner/operator's reputation with the Agency is poor. If the facility has
had major environmental problems in the past, you will be aware of the history
and status. Such issues are likely to arise at any public forum at which the
permit is discussed, and you will be better prepared.
Finally, it is important for the Agency to issue permits that are compatible and
consistent with one another. For instance, if the facility has a RCRA permit
that forbids the owner/operator from bringing a certain substance on site for
treatment or storage (such as PCBs), the UIC permit should not authorize
disposal of that substance in a Class I UIC well.
3-2
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November 2001
RCRA and UIC Overlap
RCRA and UIC can both affect a UIC well
RCRA regulates above ground hazardous
waste units
- Both may regulate filtration system and other
treatment that may affect injectate quality
Land disposal restrictions apply to Class IH
wells
Certain mining and other wastes exempt from
RCRA under Bevill amendment ^
Coordinate closely with RCRA staff on all well
classes to ensure all regulations applied
appropriately
The hazardous waste program under RCRA and the UIC program under SDWA have a
variety of overlaps.
If hazardous waste generation, storage, treatment or disposal occurs at a site, RCRA applies
in some form. Generally, the RCRA program's oversight of the facility will end at the
wellhead. Even Class I UIC wells used for disposal of hazardous wastes are permitted under
the UIC program, not RCRA (they receive a permit-by-rule under RCRA if they have a UIC
permit).
Some portions of the facility, such as the filtration system, may be regulated by both RCRA
and UIC. Since filtration may be "treatment" and it is above ground, RCRA has authority,
However, the filtration system directly affects the quality of the injectate, and the UIC
program may also regulate it.
Under the Hazardous and Solid Waste Amendments to RCRA in 1986, land disposal of
hazardous waste is prohibited unless it is treated to meet specified standards (called the land
disposal restrictions or LDRs) or it is disposed of in a land disposal unit that has an approved
"no-migration " petition. All Class I hazardous waste disposal wells have to receive an
approved no-migration petition, above and beyond the permit, to dispose of hazardous waste
that does not meet the treatment standards.
Be aware, also, that certain mining wastes and other wastes are specifically exempt from
RCRA regulation under the Bevill amendment and subsequent EPA interpretations,
regulations and policy pursuant to the Bevill exclusions. You should coordinate closely with
RCRA staff on these issues that may affect a variety of UIC wells.
All generators of waste are required to characterize their wastes to determine whether they
meet the definition of hazardous waste. Again, coordination with Regional RCRA personnel
will make the review and interpretation of this information much simpler than trying to make
the determinations on your own.
-------
November 2001
Lesson 4
Description of
Business
4-1
-------
November 2001
Brief Summary
Attachment includes facility tracking
information
The owner/operator briefly describes
the business as supplement to page 1
of the application form
- What's happening at the site
- Relationship to well operations
The owner/operator filing the application is required to submit Attachment U,
a description of the business. This does not have to be a highly technical
discussion, but merely a brief summary of the nature of the business being
conducted.
It should include a brief summary of the primary business aspects of the site
and how the injection wells fit into that. It need only be a paragraph or two.
This information provides a textual supplement to the basic business
information provided on the first page of the application. For instance, page 1
of the application requires the applicant to list up to four Standard Industrial
Classification (SIC) codes that best reflect the principal products or services
provided by the facility (40 CFR 144.31(e)(3)). The description in Attachment
U will state in text form what the facility does. For instance, a SIC code of
3312 may be provided on page 1 of the application submitted by the operator
of a hot-rolled steel manufacturing facility. The description would state that
the facility manufacturers hot-rolled steel and steel products. The operator
would probably state that the application was being submitted for disposal of
spent pickle liquor (a hazardous waste) in a Class I hazardous injection well.
4-2
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November 2001
Using the Information
Information from the attachment is
useful for the fact sheet or statement of
basis and for public information
Checking the basic information in this attachment is straightforward.
The information can be useful when preparing a fact sheet or statement of
basis for the facility, and for general public information. We will talk more
about fact sheets and statements of basis later in this course, under the Public
Participation section.
4-3
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November 2001
Lesson 5
USDW Identification
and Protection
The primary mission of the UIC program is protection of underground sources
of drinking water (USDWs). In 40 CFR 144.52(b)(1), the Director has the
authority to impose permit conditions on a case-by-case basis as necessary to
protect USDWs. It is extremely important, then, to have accurate information
regarding the location and characteristics of USDWs at an injection well
location.
In review, a USDW is defined at 40 CFR 144.3 as "An aquifer or its portion:
* (a)(1) Which supplies any public water system; or
* (2) Which contains a sufficient quantity of ground water to supply a
public water system; and
- (i) Currently supplies drinking water for human consumption; or
- (ii) Contains fewer than 10,000 mg/1 total dissolved solids; and
* (b) Which is not an exempted aquifer.
This means the permit must consider aquifers (and portions of aquifers) that do
not currently supply water to a public water supply but are capable of
producing that quantity of water.
5-1
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November 2001
USDW Protection
All wells are subject to the non-
endangerment standard of 40 CFR
144.12
The entire purpose of the application is
focused on this one goal!
The permit writer reviews the
application to ensure that this standard
will be met
All UIC wells are prohibited from endangering USDWs (40 CFR 144.12).
The prohibition on endangerment includes not only every day operations, but
construction, conversion, well maintenance and plugging and abandonment.
The entire purpose of EPA requiring permits, your review of the application
and writing conditions into the permit are focused on this one goal. The non-
endangerment standard applies from the time the well begins construction until
the end of time! As stated in the non-endangerment standard of 144.12:
* "The applicant for a permit shall have the burden of showing that the
requirements of this paragraph are met."
So, the permit application must clearly demonstrate that USDWs will be
protected and will not be contaminated throughout well construction through
the operational life of the well, and even during and after plugging and
abandonment of the well.
If sufficient evidence is not supplied to show USDWs will be adequately
protected, special conditions may be included in the permit to assure
protection, or the permit may be deemed incomplete or, ultimately, may be
denied.
5-2
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November 2001
>-
Q
WATER-TABLE
Attachment D of the permit application form requires that maps and cross
sections of USDWs present at the site be included in the permit application for
Class I and Class III wells. This information is not required for Class D well
applications.
For Class I wells, both vertical and lateral limits of all USDWs in the area of
review must be identified, while Class III well applications must include maps
and cross-sections showing only the vertical extent of USDWs. [Note: "Area
of Review" is defined in the regulations and will be discussed in detail later in
the course. For now, just be aware that it is a radius around the well where
injection pressures in the injection zone may cause fluids to migrate upward
into a USDW.]
The cross-sections and maps must show the position of all USDWs relative to
the formations receiving the injected fluid, and the direction of water
movement (if known) for every USDW that may be affected by the proposed
injection. Generally, that means all USDWs present.
5-3
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November 2001
Class II USDW Identi-
fication Requirements
Maps and cross-sections of USDWs not
required
Must include list of all USDWs that may
be affected by injection
For Class II injection well applications, Attachment E is applicable. This
attachment requires a listing of all USDWs that may be affected by the
injection operation. Note that this may require evaluation of formations
extending some distance from the site, especially in areas where pressures may
be affected by injection activities for a significant lateral area from the
injection well.
The list must include the geologic name and the depth to the base of all
USDWs that may be affected. Again, unless some extraordinary circumstance
arises, it is likely that any USDW present near the facility is going to
potentially be affected by injection, especially if one considers a worst case
scenario of a release into USDWs from a major mechanical integrity failure in
a well.
5-4
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November 2001
Permit Writer
Identification of USDWS
State geological survey maps
Drinking water program and/or source
water program staff
DRASTIC maps, ground water resource
maps, and other hydrogeological maps
Local health departments
While the permit applicant is responsible for identifying all USDWs present
that may be affected by injection, how does the permit writer know if the
information submitted is accurate and complete? There are many sources the
permit writer can use to verify the information submitted by the applicant.
First, there may be other UIC permit applications and permits in the same area.
Be sure to find out if there are other nearby wells, including other classes of
wells besides the well class that is the subject of the application, that may
provide valuable information.
Drinking water and/or source water protection program personnel often have
information regarding locations and geologic descriptions of public water
supply wells. Source water protection program personnel usually have a wide
variety of information about water supply capabilities of various aquifers.
The State geologic survey often can provide a wealth of information regarding
water well logs and drilling records, various formation maps and basic
geologic information regarding fresh water production in the area. DRASTIC
maps, groundwater resource maps, and other hydrogeologic maps, generally
available from a geologic survey, can also provide valuable information.
Local health departments may also have records of private water wells, if a
public water supply well is not located nearby. Remember, if the aquifer or a
portion of it is capable of supplying a public water supply, it's a USDW.
5-5
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November 2001
Permit Writer
Identification of USDWs
Permit application should cite specific
sources
Old information should be questioned
The permit applicant does bear the burden of proof in the application, so the
applicant should provide detailed information regarding USDWs. Citations
should be provided that will allow you to review information the applicant
used and check it to see if it is accurate and complete.
Sometimes a renewal application will not include the most recent data on
USDWs, or other geologic data for that matter. If only older citations are
provided, check to make sure more recent information is not available.
5-6
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November 2001
USDW Review Summary
Check cited information sources
Coordinate with other agencies and
departments with ground water information
Make sure of the >10,000 TDS determination
Check claims of no USDW being present
Specifically identify USDWs in the permit
Document in administrative record EPA's
decisions on what is or is not a USDW
In summary, your review of USDW information should evaluate all the data
provided, and involve others outside the UIC Program.
Check those citations we said should be provided. By coordinating with other
agencies or departments that collect and retain ground water information, you
can save yourself a good deal of legwork.
If the applicant claims that a USDW is not present, it is very important to
review maps and talk with geologic survey, source water or other
knowledgeable personnel. An applicant for a UIC well may be motivated to
state a USDW does not exist because permit conditions may be less stringent
in the absence of a USDW (at the Director's discretion). If the Agency agrees
with this determination that a USDW is not present, it sets a precedent for
other actions taken in the vicinity of the injection well regarding protection of
ground water. It is not unusual for private wells to exist within the search
radius. The productivity of private wells needs to be compared to the drinking
water program standards and definitions for the smallest of public drinking
water systems (transient, non-community public water supplies). If a private
well is capable of supplying the quantity of water the drinking water program
would regulate if it were a public water supply, the formation is a USDW.
Once you have come to a determination in your review as to which formations
comprise USDWs within the area of the UIC well's influence, make sure two
things occur. Ensure that all USDWs, including the determination of the
lowermost USDW, are identified in the UIC permit (either in the body of the
permit or an attachment). Also, make sure your determinations are noted and
placed in the administrative record of the permit.
5-7
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November 2001
Estimating TDS using
Electric Logs
Archie (1942) and Humble (1953):
Rw = QmR>_
0.62 where
Rw = resistivity of formation water
Rt = resistivity of formation
= porosity
m = cementation factor
There are many occasions during permitting or enforcement when it becomes
necessary to know the total dissolved solids (TDS) content of a particular aquifer or to
identify the true depth to the base of the lowermost USDW, i.e., where the saline
content is 10,000 mg/1 TDS. Most literature references are regional in scope, rather
than specific. State publications or water-well data, if available, are usually oriented
to drinking water aquifers of low TDS content. In a perfect world, a permit writer
should be able to get water samples just by wishing on a magic lamp, but in most
cases, what you will have in front of you is an electric log.
In 1942, G.E. Archie defined an empirical relationship between the resistivity of the
formation fluids, the porosity of the formation, and the TDS concentration of the
formation water. Humble (1953) simplified Archie's relationship for porous
formations as:
Rw = porosity (to the power of m) times Rt, divided by 0.62, where:
"Rw" is the resistivity of the formation water;
"m" is Archie's "cementation factorand
"Rt" is the resistivity of the formation.
Rt can be picked from a wireline log using a deep-focus curve in a thick (>5feet),
water-saturated bed. "m" is estimated using empirical values for differing degrees of
cementation and burial, and porosity can be calculated, estimated, or measured. Using
the solution for Rw, we can estimate TDS concentration using standard tables. This
method is variously called the "Archie method" or the "resistivity method."
5-8
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November 2001
Step 1: Porosity
Calculate
- Cross-plot using neutron and/or density logs
Measure
- Most fields have sidewall core or other data
Estimate
- Typical range from .20 to .40 (sands in .30's)
Step one of the resistivity method involves the determining formation porosity.
There are three methods of determining porosity for this analysis.
> Calculate: If sonic, density, or neutron logs are available for the well, one
can cross-plot porosity using two logs for known lithology or three logs
for unknown lithology. See any log interpretation manual for details.
> Measure: The subject well or other wells in the field may have sidewall
core data.
^ Estimate: Because we are almost always interested in water-saturated
aquifers, porosity probably ranges from .20 to .40, with most sandy
formations likely in the .30's. Because the possible range is relatively
small, estimates of porosity are usually satisfactory.
For our example well, the porosity of the zone of interest was measured at 32
percent.
5-9
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November 2001
Step 2: Cementation
Factor
Calculate
- Rt versus O log-log plot with depth
Estimate (Guyod, 1944)
- Highly cemented (limestone, quartzite): 2.0 - 2.2
- Moderately cemented (consolidated sands): 1.8 -
2.0
- Poorly cemented (friable, crumbly sands): 1.4 -
1.7
- Unconsolidated sands: 1.3
Archie described a "cementation factor" which relates to the degree of
cementation and burial. He intended that this factor be calculated: if several
values of Rt versus sonic or neutron porosity are plotted on a log-log graph
with increasing depth, then "m" is the slope of a best-fit line. Archie
considered that most deep cemented sandstones had a value of 2.15 for "m."
Guyod (1944) found, however, that "m" varies predictably with lithology. He
proposed the following values of "m:"
* Highly cemented (limestone, dolomite, quartzite): 2.0 - 2.2
* Moderately cemented (consolidated sands): 1.8-2.0
* Poorly cemented (friable, crumbly sands): 1.4-1.7
^ Unconsolidated sands: 1.3
Most USDWs are relatively shallow, and typically exhibit "m" values of 1.4
to 1.8. Our example zone is located from 1725 to 1820 feet depth from
surface, and is located in south Texas. A typical range of "m" for Gulf Coast
sands would be about 1.6.
5-10
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November 2001
This analysis requires a resistivity, induction, or Laterlog-type well log,
although you can even use a value from a pre-1940 "electric log." Choose a
log value for formation resistivity in a clean, permeable, thick (>5 feet) bed. If
you are using a resistivity log, use a "deep-focused" curve. Always watch the
scale, and make sure you have the decimal in the right place. In this case, the
value is 2.5 ohm-meters.
5-11
-------
November 2001
Solve for Rw
Rw = OmRL
0.62 or
R.._ (.32)16 (2.5) = .65
.62
Rw is the resistivity of the uninvaded formation water. The solution for our
example would be .32 raised to the 1.6 power, times Rt (2.5), divided by .62.
Therefore, in our example, Rw would equal .65.
5-12
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November 2001
Step 4:
Estimate
formation
temperature
AnraaUUaqn "ฆ
Surtwฎ Temoereture
27*
TcunpainlufOrod)ซrmCefiyciJJilou..rฐP/1dOIซ-. t#>3*C/idOin
ป!ปC/TOO*n ป O.S488*F/tpori
Temperature. ฐC
ฃ
ซ. '
r
MnmlMun
Surface Twnoeratur*
BOO ISO
Temperature. ฐF
3ฎ
EXAMPLE: Bottom holetemperature, BHT. kiOCTPnl ll.OOO ft ntrin* A).
Tctiipeiuiurc at KOOO ft & I&7*F tPolra B).
Most log headers will list the surface and bottom-hole temperatures. You must
convert bottom-hole temperature to the temperature in the zone of interest.
This is a typical graph of geothermal gradients. These graphs use mean annual
surface temperature and a bottom-hole temperature as the basis. For deeper
aquifers (>1,000 feet), use this handout or your own graph to calculate the
temperature at the depth of the selected formation. For aquifer depths less
than 1,000 feet, use a value between 75 and 90 degrees, depending on average
surface temperature and depth.
Our example log header measured bottom hole temperature as 107 degrees F
at 2850 feet. The corrected temperature in our example zone at 1780 feet
would be about 99 degrees.
5-13
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November 2001
Step 5:
Estimate
TDS as
NaCI
*
iff
m
o
%
10
>90
a
lr>ieto
200
JWO-
300
400
SOO
6
E
O
IS
Z
- 1000
160D
4000
- sooo
. 000
- ZQyWS
Temperature or ฐC)
Use this graph to convert Rw to TDS.
* First, find Rw on the vertical axis (left side) of the graph. Note that the
vertical axis features log-Rw. In our case, the Rw value was .65.
* Then find the formation temperature of 99 degrees on the bottom of the
graph. Use the upper right corner of a sheet of paper, and align the right
edge with temperature and the top edge with Rw. The "point" of the edge
indicates the TDS of our example: it falls vertically between two blue iso-
concentration lines.
* Read down to the right to find the TDS of the nearest iso-concentration
line. In our case, the tip lies about 3/4 of the vertical distance between the
6000 and 7000 TDS iso-concentration lines, indicating about 6750 ppm
TDS.
Note that this value is for sodium chloride solutions.
5-14
-------
November 2001
While this assumption is very accurate for deeper, more saline aquifers, it yields TDS
values that are inappropriate for USDWs, which usually feature ions such as calcium,
magnesium, bicarbonate, and sulfate. The net effect is that Rt will read lower in a sodium-
chloride zone than it would in a calcium-bicarbonate zone. In other words, our analysis
thus far has stated the results as sodium chloride, which overstates the actual TDS if they
are typical USDW constituents. In other words, our answer as NaCl represents the worst
case - 6,750 ppm TDS is the most saline the aquifer could be.
In theory, most aquifers that contain less than 4,000 TDS probably feature calcium,
bicarbonate, and sulfate as the dominant ions, rather than sodium chloride. Aquifers
containing between 4,000 and 10,000 TDS probably feature a combination, so, for our
example, we should consider an answer somewhere in between.
Step 6 uses Sinclair's method to convert the results from NaCl to USDW solutes. For each
ion other than sodium and chloride that is present in the aquifer, Sinclair assigns a multiplier
to adjust the ion concentration. In simple terms, we already know what the resistivity of the
formation water is. The multiplier will adjust the amount of each ion to reflect the true
concentration.
Enter the chart at the appropriate total-solids concentration of the solution, in this case,
6,750 ppm as sodium chloride. Notice that if the solution were 100 percent NaCl, the
multiplier would be "1," that is, the TDS is not adjusted. If, for example, the solution were
100 percent bicarbonate, at 6,750 TDS the multiplier would be .3. To adjust for the
presence of 100 percent bicarbonate, we would multiply 6,750 by .3, which equals 2,025.
This result says that 2,025 ppm of bicarbonate in solution would give the same resistivity
reading as 6,750 ppm of sodium chloride.
5-15
-------
November 2001
calcium, bicarbonate, and sulfate as the dominant ions,, rather than sodium
chloride. Aquifers containing between 4,000 and 10,000 TDS probably
feature a combination; so for our 6,750 TDS aquifer we probably should
consider a composition somewhere in between.
Let's consider the best case: assume that the zone contains water characteristic
of USDWs with calcium, bicarbonate, and sulfate. Fifty percent of the ions
would be calcium, 25 percent would be bicarbonate, and 25 percent would be
sulfate. The multipliers at 6,750 are calcium .8, bicarbonate.3, and sulfate .53.
The analysis looks like this:
(3375 x .8) + (1687.5 x .3) + (1687.5 x .53) = 4,100 ppm TDS
This would be the true salinity if the ions were representative of fresh water,
that is, only calcium, bicarbonate, and sulfate.
We said earlier that USDWs over 4,000 TDS probably feature a combination
of ions. Let's assume a typical brackish composition: 50 percent of the solutes
are sodium chloride, and the balance is calcium sulfate. That analysis would
be:
(3375 x 1) (the multiplier for sodium and chloride) + (1687.5 x .8) + (1687.5
x .53) = 5,619 ppm TDS
What have we learned about our example zone? The zone features water that
contains, as sodium chloride, 6,750 ppm TDS. The zone could conceivably
contain as little as 4,100, but probably contains about 5,600.
5-16
-------
November 2001
SP Method
Utilizes SP log and mud conductivity
Use only when:
- Mud is fresh water, and
- Beds are thick (> 5 feet)
Will not work in carbonates
So far we have been considering only one of the two methods for calculating
TDS from a well log, namely the Archie or resistivity method. The other
method is called the "SP method." When fresh water in the borehole is in
contact with more-saline formation fluids, a small electrical current is
generated. Measurement of the voltage change with increasing permeability
generates a spontaneous potential log.
The resistivity method holds up in almost every situation, but there is one
situation where the SP method is better: when fresh-water mud is used for
drilling and logging. Almost all oil wells will use saline mud to prevent
formation damage to deeper zones. In some cases, however, operators will use
city water for mud to drill the surface-casing hole and log the shallow section.
The only problem with the SP method is that it is not valid in thin beds (less
than 5 feet) or carbonates.
5-17
-------
November 2001
Step 1:
Rmf
@ temp
Tempeffflure (ฐF or ฐC)
First we need to establish the resistivity of the mud filtrate, or Rmf. Mud
filtrate resistivity is usually listed on the log header, usually as Rmf @ surface
temperature. We must convert resistivity at surface or bottom-hole
temperature to resistivity at formation temperature.
For this we use the resistivity/TDS chart. Our log header gave us Rmf as 3.81
at 75 degrees F, and we calculated the formation temperature as 99 degrees F.
Using the upper-right corner of the paper, index the value of 3.81 and 75
degrees. The intersection is the equivalent TDS concentration, as before.
Slide down the iso-concentration line until you intersect the 99 degrees mark
on the bottom scale. Read left for the Rmf value at 99 degrees, in this case 3.0
ohm-m.
Rmf was measured as 3.81 at surface temperature. We found that if measured
at formation temperature, Rw would measure 3.0.
5-18
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November 2001
Step 2: Determine Rmfeq
Rmfeq ~ 0^5 Rmf
or
Rmfeq = -85 X 3.0 = 2.6
For Rmf greater than 0.1 ohm-meter, this relationship is true. Since Rmf is
almost always greater than 0.1 ohm-meter for shallow SP logs, this simple
relationship provides a shortcut. For our example well, Rmf at reservoir
temperature equals 3.0. Substituting in the equation, we can solve that Rmfeq
equals 2.6.
5-19
-------
November 2001
SP Step 3: Pick SP Value
-H
to
200D
10
16" NORMAL
INDUCTION CONDUCTIVITY
40" SPACING
SPONTANEOUS POTENTIAL
Millivolts CALIPER
DEPTH
RESISTIVITY
Ohms mVm
CONDUCTIVITY
Millimhos/m
i _
:a
3
laie
set
ne
iE
iih
in
=3E
A
Next, pick the value for SP for our example zone. Remember that the SP
value is measured from the "shale baseline." Make sure that the SP deflection
in the USDW is fully developed, that is, the bed is at least 10 times as thick as
the wellbore, is water saturated, and shale-free. In our example case, we'd use
a value of-43 millivolts.
Remember that SP logs are relative to the salinity contrast of the mud filtrate
and the formation water. Here, the mud filtrate is fresher than the formation
water, and therefore gives a negative value. If the operator had used salt water
mud, Rw would be greater than Rmf and we would get a positive reading for
the zone.
5-20
-------
November 2001
Step 4:
Find
Rweq
DETERMINATION FROM THE SSP
(CLEAN FORMATIONS)
For pfdomlnonHy sodium chloride mud* at follows*
a. If at 73*F (24*C) is greater than 0.1 Qam, correct R_ to formation
temperature using Gen-9, and use Bi r t " 0JL5 Rซr>
b. If R.( ot 75ฐF (24*C) Is less tHon O.I Q*mซ use SP-2 to derive a valua
of at formation temperature.
^weq
STATIC
SP
mV
-ZOO-r
^mfeq /Rwq
A -r
- 43 mv
.a - -
i - -
440^-
{ I )
Essp " ~ Kc 'ofl ~H~
KC"6I+.I33TCF)
Ke" 65 + .24T("C)
Rmfcq
jpi-r
2 0t-
(4)
Recall that Rw is the natural resistivity of the formation water. Rweq is the
equivalent as SP, or spontaneous potential. To convert Rmfeq to Rweq, use
the nomograph. Using a straight edge, align the SP value from the log with
formation temperature to find the ratio of Rmfeq to Rweq. Then align that
ratio with the value of Rmfeq to find Rweq in the right-hand scale.
In our example, SP equals -43 mv and the formation temperature is 99 degrees
F. Aligning these two values gives us a value of 3.9 for the Rmfeq/Rweq
ratio. Align that ratio with our value for Rmfeq (previous slide, 2.6) and we
get a result that Rweq equals .68.
5-21
-------
November 2001
Step 5:
Convert
Rweq
to Rw
0.2 03 as
(Q-m)
1.0 -3 4 1
1.2 as "fresh"
These ehftrtsetsivert equivalent'water nisiftivity, from Chan SP-J toixtual wMCTreststivfty.R^Thcymay
also be used to convert to in jatafc muds.
Uifti lhn solid line* for pnalttmlrmnOy NaO wntm. The dasbtd liina areappnrdmaietbf "average" fr
-------
November 2001
Step 6:
Convert
Rwto
TDS
1 1 I 1 1
126 1SO 200 250 300 350
50 60 70 80 90 100 120 140 160 160:
1 ฆฆ ฆ 1 ป ' ' ป ' i ฆ* * * *ฆ
Temperature (ฐF or *0'
This step is the same as that used for the Resistivity method. Align the paper
with Rw on the vertical axis and the formation temp on the horizontal. The
intersection is read down and to the right on the iso-concentration line.
In this case, as NaCl, we found that Rw equals .68. Using the graph at 99
degrees formation temperature, the corresponding TDS of the zone would be
about 6,400.
As fresh water, Rw equals 1.2, which corresponds to a value of about 3,900
ppm TDS if the zone contained fresh water. Remember that for TDS over
4,000, the true answer probably lies somewhere in between.
5-23
-------
November 2001
Limitations of SP
Method
Accuracy varies with salinity contrast
Bed thickness and shaliness affect SP
Accuracy of Rm/Rmf
USDW components add more error for
SP
Theoretically, the SP method should be more accurate than the resistivity
method, because we don't have to estimate "m" or calculate porosity.
In practice, however, the SP method can be less accurate.
* First, there has to be a good contrast between the salinity of the mud
filtrate versus the formation water.
* Second, bed thickness and shaliness affect the SP log values.
~ Third, the method is dependent on the accuracy with which the rig crew
measured Rmf, the resistivity of the mud filtrate. Even in the case of an
accurate measurement, mud properties are likely to change substantially
as the hole is drilled and tools are run in and out of the well. Rmf
downhole may differ from surface values by 20 percent.
* Last, the presence of calcium and magnesium in USDWs causes a larger
potential error than is found with the resistivity method.
5-24
-------
November 2001
Comparison of
Methods
Resistivity method
- 4,100 TDS as fresh water versus 6,750 as
NaCI
- Must estimate porosity and "m"
SP method
- 3,900 as fresh water versus 6,400 as NaCI
- Accuracy of Rmf and salinity contrast
Our estimates of the salinity in the zone compare reasonably well: 4,100
versus 3,900 as fresh water, and 6,750 versus 6,400 as sodium chloride. Both
methods have drawbacks that affect accuracy. In the case of SP, there are
fewer variables, but changes in Rmf can introduce errors. In the resistivity
method, the log is much more accurate, but you have to know something about
the aquifer or the region to estimate "m," the cementation factor.
What is the real salinity of the zone? Only a chemical analysis would tell for
sure, but you should never consider any log estimate of TDS more accurate
than +/- 10 to 15 percent.
5-25
-------
November 2001
Reviewing TDS
Calculations
Typical errors overstate TDS:
Archie's "m" = 2.15
USDWs as NaCI
SP fully developed?
- Salinity contrast
- Bed thickness and shaliness
Having two people make these calculations independently resulted in differences of only five
percent, but estimates using the same data may differ by several thousand mg/1. Here are the
most common sources of error. Also keep these factors in mind if you need to review the TDS
calculations made by others. These are the essential elements that are commonly omitted or
confused.
~ First, Archie's original paper specified "m" as equal to 2.15. This is indeed true for the
well-cemented sands in the deep-basin oil reservoirs that Archie wrote about. Several
researchers since then, however, find that "m" is variable, and ranges from 1.3 to 2.2.
Using 2.15 for "m" is a common error, usually made by consultants who would like to
overstate TDS. "See, it's not really a USDW1" Beware.
* The second most common error is not considering the composition of USDWs. Failure to
convert Rweq to Rw in the SP method or not using solute multipliers in the resistivity
method treats USDWs as if they were 100 percent sodium chloride, rather than
containing, calcium magnesium, bicarbonate, and sulfate. This error also tends to
overstate the TDS of the aquifer.
~ Third, you must be very aware of the salinity contrast when using the SP method. For
example, many operators in coastal areas use brackish estuary water for mud makeup.
The resulting Rmf salinity makes the development of a valid SP a little shaky in
formations containing less than 10,000 TDS. Even in cases where operators use city
water for mud makeup, development of a valid SP is possible only when there is a true
salinity contrast. Always check the contrast between Rw and Rmf. As the values
approach equality, the SP method becomes less reliable.
What is the net result of these common errors? They can result in overstating USDW salinity
by 100 percent! Know your method and know its drawbacks.
5-26
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November 2001
Well Site
for USDW Protection
Formations free of intersecting faults
and fractures
No wells penetrating into the confining
or injection zones
Injection pressure limited to prevent
fracture creation
There are multiple ways that injected fluids could get into a USDW to
endanger it.
It is important that the formations intended to seal the injection interval from
the USDWs are free of intersecting faults and fractures. If faults or fractures
are present, the injected fluid, introduced into the injection interval at an
elevated pressure, will seek the path of lower pressure and move upward into a
USDW.
The same is true about the presence of other wells within the zone around the
well that is subject to increased pressures as a result of injection activities.
These could be old oil and gas exploration or production wells, or other
injection wells that are not in use. The permit applicant is required to do a
records search for other wells within a set radius around his or her injection
well, and must evaluate all geologic information for the site to provide the
greatest degree of certainty that paths for upward migration to USDWs are
absent.
The injection pressure of the permitted well must be limited such that fractures
are not created or extended. This also ensures protection of USDWs. We will
discuss appropriate operating pressure limitations in more detail in Section 14
of this training module.
5-27
-------
November 2001
Well Site Evaluation
for USDW Protection
Multiple barriers provide additional
protection
If a thorough evaluation is not done and an undiscovered deep well, fault or
fracture system is present, a USDW may be threatened. As has been
documented for years, preventing ground water contamination is much less
costly than remediation. And if an injection well contaminates a USDW, it
may be a long term source of ongoing contamination. The upward migration
will occur as long as the conduit is present and the pressure in the injection
interval is high enough to be a driver.
To ensure safe UIC well injection, multiple barriers are needed to protect
USDWs. The geologic data reviewed as part of the permit application are one
piece in ensuring that the site meets the protective requirements of the
regulations. Construction details, operational procedures and well monitoring
provide additional protection. We will talk about each of these aspects later in
the course. Keep in mind that all those issues come back to ensuring that
injected fluids are not able to make their way into and contaminate a USDW.
5-28
-------
November 2001
Lesson 6
Aquifer Exemptions
6-1
-------
November 2001
Why an Exemption?
All USDWs to be protected except exempted
aquifers
If injection to occur into formation that
technically meets definition, but practically is
not a potential drinking water source,
exemption process available
An aquifer or a portion of an aquifer that otherwise would be considered a
USDW can, based on the Federal definition, be exempted. Certain
limitations on operations, citing, and monitoring may be less stringent or
not applicable in the permitting process if an aquifer is exempted from
consideration as a USDW.
ฐ Why would EPA want to exempt an aquifer from protection? In some
cases, a water bearing formation may technically meet the definition of a
USDW, but the likelihood of it truly being used as a drinking water source
is extremely remote. In practical terms, it may be unusable as a public
water supply. Zones may exist that are significant mineral resources but
meet the USDW definition. Or, an area may have abundant drinking water
resources such that a formation with nearly 10,000 TDS would not be used
as a potable water source.
Without the exemption process, even if EPA acknowledged that a formation
was a USDW in name only, not in practical terms, it still would be
prohibited from receiving any fluid from a UIC well.
In the exemption process, the applicant requests the exemption of the
formation or part of a formation. A specific geographic limit can be placed
on the exemption. The applicant must demonstrate the exemption is
appropriate. The primacy or DI regulator reviews the applicant's request.
In a primacy state, even if the state agrees with the request, it must then be
forwarded to US EPA's Regional office for review and approval or
disapproval.
6-2
-------
November 2001
Basis for Exemption
Criteria for exemptions in 40 CFR 146.4
- Not currently serving as source of drinking water
- Cannot now and will not in future serve as source
of drinking water
- TDS >3,000 mg/l and <10,000 mg/l, and not
reasonably expected to supply public water
system
There are specific criteria that must be met for any portion of an aquifer to
be designated as an exempted aquifer. As listed in 40 CFR 146.4, these are:
> The aquifer does not currently serve as a source of drinking water; and
* It cannot now and will not in the future serve as a source of drinking
water; or
* The total dissolved solids (TDS) content of the ground water is more
than 3,000 mg/l and less than 10,000 mg/l, and the aquifer is not
reasonably expected to supply a public water supply.
6-3
-------
November 2001
Deciding about Drinking
Water Sources
How do I decide if the aquifer cannot now
and will not in the future serve as a
drinking water source?
- Mineral or hydrocarbon resource?
- Depth and location compared to technology
and economics?
- Contamination?
- Subsidence or collapse likely from Class III
UIC mining?
The second criterion listed on the previous slide for an exempted aquifer
requires that EPA determine that the aquifer cannot now and will not in the
future serve as a drinking water source. Note that the rule does not say
supply a public water supply, but rather "serve as a drinking water source."
The regulation provides specific criteria that can be considered in deciding
whether this is the case. The decision may be based on any of the following
four specific situations regarding the aquifer. These situations are listed in
40 CFR 146.4(b)(l)-(4):
^ It is mineral, hydrocarbon or geothermal energy producing, or a Class
II or III UIC well permit applicant can demonstrate it contains minerals
or hydrocarbons in quantity and location that are expected to be
commercially producible;
^ It is situated at a depth or location that makes the recovery of the
groundwater for drinking water purposes economically or
technologically impractical;
* It is so contaminated that rendering the water fit for human
consumption would be economically or technologically impractical; or
> It is located over a Class III well mining area subject to subsidence or
catastrophic collapse.
6-4
-------
November 2001
Procedure for Exemptions
Administrator and Regional
Administrators have authority to approve
exemptions (40 CFR 144.7(b)(2))
Exemptions subject to public input
Information requirements for Class II and
III applicants in 40CFR 144.7(c)
Some exemptions require the Administrator's approval (if they are
"substantial program revisions") while others can be approved by the
Regional Administrator (those that are "non-substantial revisions").
Whether approvable by Headquarters or the Region, the bottom line is that
the exemptions cannot be completed by the Primacy States alone. To
determine what type of revision an exemption request you receive may be,
please be sure to check with your manager and appropriate counsel.
The aquifer requested to be exempted may be identified by narrative
description, illustrations, maps or other means. The aquifer or portion to be
designated is also described in geographic and/or geometric terms (such as
vertical and lateral limits, and gradient).
All exemptions are subject to public input, through the issuance of public
notice and opportunity for public hearings and comment.
A primacy State UIC program may propose to the Administrator to exempt
an aquifer based on the >3,000 mg/1 and < 10,000 mg/1 TDS criterion. If
the State Director submits the exemption in writing to the Administrator
and it is not disapproved within 45 days, that exemption automatically
becomes final (see 40 CFR 144.7(b)(3)).
For designations based on commercially producible minerals or
hydrocarbons, the Class II or Class III applicant is required to submit
information to the EPA to demonstrate the feasibility of the production.
The specific information to be submitted by the applicant is detailed in 40
CFR 144.7(c).
6-5
-------
November 2001
Permitting Ramifications
All identified USDWs are required to be
protected by the UIC program
Exempted aquifers do not receive this
protection
Siting, operational and other permitting
limitations may be less stringent or not
applicable to an exempted aquifer
The designation is a final EPA action
All supporting documentation into
Administrative Record
It is important to realize that all USDWs, even if not specifically identified by name
or location, are to be protected in the UIC program. The exemption that is
designated for an aquifer is an exemption from protection.
Many permitting requirements designed to protect USDWs, then, are no longer
applicable as they relate to the aquifer once the exemption is made. Under 40 CFR
144.16, less stringent well permit requirements may be applied if injection does not
occur into, through or above a USDW. So, in areas where USDWs are at least 1/4
mile from the well, or where the aquifers are exempted, a UIC well may be
permitted less stringently. As we discussed earlier, the whole premise of the UIC
Program is USDW protection - if no USDW is present to protect, then
requirements can be less intense.
If an aquifer is exempted, the exemption applies for all UIC wells, not just those of
a particular class. It is very important to consider the information and ensure that
the aquifer does indeed meet the regulatory criteria and is not subject to protection
as a USDW. The designation as an exempted aquifer is a final action of EPA. As
such, it is subject to the public participation requirements of EPA's procedural rules
and it definitely is not something about which one can later change one's mind. Be
certain that all paperwork supporting the decision is placed in the administrative
record of the permit application.
Many experienced UIC personnel have been involved in aquifer exemptions. If an
applicant identifies the need for an aquifer exemption in a UIC application, the
permit writer should consult with these experienced personnel to ensure that
appropriate information is provided and that the proper procedure is followed.
6-6
-------
November 2001
Lesson 7
Reviewing Local
Geologic Data
32)
DRINKING
WATER
ACADEMY
7-1
-------
November 2001
Injoofion pracwra,
0HVป
Infadion
AraiiAs
Ideal Injection Well
and Site
MMnttl*
SarbUtotifM-UGDW
CtoMag xonr-ttab
CctAtdiqanirUSDW
Ceafehgzmwftnk,
4dtooBป.ซto;
Hftft IIRfSw '
kjMtaMK
MOfrUSOW
*> 10,000 ngATDS
Definitions
A few terms need to be defined to understand the siting and other regulatory requirements of the UIC
rules that relate to geology. In the UIC program, different terms apply to various formations that are
found in the subsurface. The terms relate to whether the formations are allowed to receive any
injection fluids and to various protective barriers intended to prevent contamination to underground
sources of drinking water (USDW).
The injection zone is a geological formation, group of formations or part of a formation receiving
fluids through a well (40 CFR 144.3 and 146.3). The injection interval is that part of the injection
zone in which the well is screened (completed) or in which the waste is otherwise directly emplaced.
* The injection zone as a whole may receive fluids, including indirect emplacement (migration)
but the injection interval is the only part that can be designed for direct placement of the fluid.
* "Injection interval" is a term that only applies to Class I hazardous waste (Class IH - see 40
CFR 146.41(b)) wells in the regulations, but it is often used in other well classes as a
descriptive term.
The confining zone is a geological formation (or group or part of a formation) capable of limiting
fluid movement above an injection zone (40 CFR 146.3). This rock layer (or layers) may have some
fluid migrate into part of it, but the injectate is not intended to move beyond the confining zone over
the entire life of the injection well's operation.
The containment interval (also known as the arrestment interval) is not defined in the regulations.
~ However, 40 CFR 146.62(d)(1) requires that the confining zone for a Class IH well be
"separated from the base of the lowermost USDW by at least one sequence of permeable and
less permeable strata that will provide an added la^er of protection for the USDW in the event
of fluid movement in an unlocated borehole or transmissive fault."
~ This condition must be met unless there is no USDW or the pressure of the injection zone
could not possibly push injected fluids up into a USDW.
7-2
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November 2001
Injection in the U.S.
UIC Class I Deep/High Technology
Hazardous Waste Wells
No HW Wells
I-10 HW Wells
II-20 HW Wells
> 70 HW Wells
Injection wells are known to exist in virtually every State. Class V wells,
which typically are shallow, can be installed almost anywhere. Class I, II and
III injection wells, however, tend to be clustered in specific geologic areas.
These well Classes must be sited in locations that are suitable for receiving the
fluids. The formations must have permeability and thickness sufficient for the
well to accept a volume of fluid that will make the well economically viable.
The formation must not be so brittle that fractures might develop or propagate
during injection to endanger USDWs. Of course, these wells also are sited
based on business need. A Class I well will be located where industrial or
municipal wastes are generated in large quantities and need to be disposed.
Class II wells are going to exist where oil and natural gas production and/or
exploration occur. Class III wells will only be installed if minerals are mined
using injection technology.
The map above shows the distribution of Class I wells in the United States.
7-3
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November 2001
Injection in the U.S.
FL
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Q Virgin Islands
Q American Samoa
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1-100 Wells
BBS 101-5,000 Wells
HI 5,001-25,000 Wells
ฆฆ More than 25,000 Wells
U1C Class n Oil&Gas Wells
The Gulf Coast area, especially Texas and Louisiana, have large geographic
areas that are geologically attractive for siting Class I, II and III wells. Region
6, with 184 Class I wells and more than 75,000 Class II wells has the greatest
number of these wells among the 10 US EPA Regions.
While Region 6 may top the list, Regions 3, 4, 5, 7, 8, 9 and 10 also have a
significant number of these wells. Let's briefly review the geology of the Gulf
Coast and Ohio/Illinois/Michigan, where many injection wells are located.
The above map shows the distribution of Class II wells in the United States.
7-4
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November 2001
Gulf Coast
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About 75 percent of all Class I injection wells are located in the Gulf coast
region of Alabama, Mississippi, Louisiana, and Texas.
Two hundred million years of subsidence and basin-filling in a tectonically
inactive area resulted in over 20,000 feet of alternating marine shales and
clean, deltaic sands. These formations are thick (up to 700 feet) and can be
correlated for hundreds of miles using readily available data from oil and gas
exploration.
High permeability (up to 2 Darcies) in thick sand zones such as the 550-foot
basal Frio formation yields high injectivity but minimal injectate plumes (on
the order of a mile).
Massive marine shales with immeasurably low permeability in the vertical
direction and thicknesses up to 700 feet, such as the Vicksburg shale, ensure
confinement under almost any injection circumstances.
As a further safeguard, the alternating onlap-offlap cycles provide thousands
of feet of additional confining zones and permeable "capture" zones between
the confining zone and the base of USDWs. In addition, the geochemistry of
marine clays makes them ideal candidates for adsorption of both organic and
inorganic wastes.
7-5
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November 2001
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In Region 5, the Mount Simon Sandstone is the basal Cambrian unit in the
Ohio/lllinois/Michigan area, and is commonly used for injection. Other
formations may be used, depending on the fluid to be disposed and the
location of USDWs. The Eau Claire Formation overlies the Mt. Simon, and
may be included in the injection zone of some deep wells.
The Mt. Simon is a high-energy shoreline facies of the northerly transgressing
Cambrian sea (Catacosinos, 1973). It was deposited over the eroded
Precambrian units below. It is a coarse-grained to conglomeratic sandstone,
that frequently has sufficient thickness, permeability and porosity to serve as a
long-term injection interval. The Mt. Simon is as thick as 2,000 feet in
northwestern Indiana, and thins to an effective injection interval thickness of
less than 100 feet in northeastern Ohio. The formation is known by this same
name and is found as a continuous formation in Illinois, Wisconsin, Michigan,
Ohio and Kentucky and is known as the Lamotte Sandstone in Missouri
(Indiana Department of Natural Resources Geological Survey Bulletin 59,
1986).
In contrast to the high permeabilities of the Gulf Coast sands, a permeability
of 300 milliDarcies (0.3 Darcies) is considered quite good for the Mount
Simon Sandstone in parts of Region 5.
7-6
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November 2001
Other Locales
A significant number of injection wells,
especially Class II wells, exist in other
locations
- Appalachian Basin
- Rocky Mountain Basin
- Alaska
- California
Oil and natural gas production in the Appalachian Basin, Rocky Mountain
Basin, Alaska, California, and other locations has created a need for Class II
wells.
The rock characteristics of these areas are very different from the Gulf Coast,
with formations often being much more tight and brittle.
The reviewer of a permit application in any locale must ensure that the
information presented in the application is current and accurate. Only with
accurate geologic information can the permit writer be certain that the well is
properly constructed and operated to protect the subsurface environment that
contains drinking water sources.
Data in the vicinity of the proposed well site is especially important. The
permit reviewer should ensure that data from nearby locations is not
overlooked. It may be helpful to check private data base services, such as the
API database, to acquire the most current and comprehensive data.
7-7
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November 2001
Local Data
Review of data near the well site is
critical
Nearby wells provide wealth of
information
Review of local data must be current
With the variability in geology that occurs from one part of a State to another,
let alone within a Region, it is imperative that the permit application present
all available relevant data regarding local geology.
Other wells may have been drilled near the well site and can be reviewed.
Data may include cores, drill stem tests, well logs, and other well-specific test
results. These data may be used to help determine the depth, thickness,
salinity, and productivity of USDWs; lithologic variations, thickness and
permeability of proposed injection and confining zones; elastic properties of
the injection and confining zones; and other information that is useful in
evaluating the site.
Even for a renewal permit of a currently operating well, the local data must be
checked to ensure it is current. New wells may have been drilled or additional
information collected from an existing well since the time the original permit
was developed. This new information may cause EPA to apply different
conditions to the renewal permit compared to past permits.
7-8
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November 2001
Well Site Evaluation
for USDW Protection
Formations free of intersecting faults
and fractures
No wells penetrating into the confining
or injection zones
Injection pressure limited to prevent
fracture creation
There are multiple ways that injected fluids could get into a USDW to
endanger it. The review of geologic data helps ensure that natural conduits do
not exist that may endanger a USDW.
It is important that the formations intended to seal the injection interval from
the USDWs are free of intersecting faults and fractures. If faults or fractures
are present, the injected fluid, introduced into the injection interval at an
elevated pressure, will seek the path of lower pressure and move upward into a
USDW.
The same is true about the presence of other wells within the zone around the
well that is subject to increased pressures as a result of injection activities.
These could be old oil and gas exploration or production wells, or other
injection wells that are not in use. The permit applicant is required to do a
records search for other wells within a set radius around his or her injection
well, and must evaluate all geologic information for the site to provide the
greatest degree of certainty that paths for upward migration to USDWs are
absent. We'll talk in more detail about these man-made conduits and how an
applicant may find them later in this course.
The injection pressures applied within the permitted well must be limited such
that fractures are not created or extended. This also ensures protection of
USDWs. We will discuss appropriate operating pressure limitations in more
detail in Section 14 of this training module.
7-9
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November 2001
Well Site Evaluation
for USDW Protection
Multiple barriers provide additional
protection
If a thorough evaluation is not done and an undiscovered deep well, fault or
fracture system is present, or appropriate containment is absent due to the
lithology of the area, a USDW may be threatened. As has been documented
for years, preventing ground water contamination is much less costly than
remediation. And if an injection well contaminates a USDW, it may be a long
term source of ongoing contamination. The upward migration will occur as
long as the conduit is present and the pressure in the injection interval is high
enough to be a driver.
To ensure safe UIC well injection, multiple barriers are needed to protect
USDWs. The geologic data reviewed as part of the permit application are one
piece in ensuring that the site meets the protective requirements of the
regulations. Construction details, operational procedures and well monitoring
provide additional protection. We will talk about each of these aspects later in
the course. Keep in mind that all those issues come back to ensuring that
injected fluids are not able to make their way into and contaminate a USDW.
7-10
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November 2001
Geologic Data
Requirements
Attachment F for Class I and Class III
wells
- Maps and cross-sections detailing local
geology
- Generalized cross-sections and map of
regional geology
Attachment G for Class II wells
- Descriptive data for injection and confining
zones
Attachment F must be in a permit application for a Class I or Class III
injection well. This Attachment is required to include both maps and cross-
sections detailing the geologic structure of the local area. The lithology of the
injection and confining intervals must be shown in detail on these maps and
cross-sections.
Class II injection well permits, on the other hand, are required to include
Attachment G. Maps and cross-sections do not have to be included. Instead,
geologic data for the injection and confining zones are to be submitted. This
includes a lithologic description for both zones, geological names for the
formations included in the injection zone and confining zone, and the
thickness, depth and fracture pressure of each of these formations.
7-11
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November 2001
Injection Well Site
Evaluation
Siting requirements differ by well type
Purpose of reviewing site-specific
geologic and injectate information
- Ensure minimum siting criteria are met
- Determine the interaction between the
subsurface and the injectate
- Determine need for site-specific
requirements
Siting requirements differ by well class and type. Regulations for Class I
hazardous waste (Class IH) injection wells have the most stringent siting
requirements, and Class V have the least stringent. As with all injection
activities, a well is not allowed to contaminate a USDW.
The permit writer's responsibility is to review the information in the permit
application in order to establish permit conditions that ensure that the non-
endangerment standard and all other applicable requirements will be met. Site
evaluation is one important aspect of this review.
As we have seen, the permit application provides site-specific geologic
information. The permit writer must review it to ensure that the minimum
siting criteria are met. He or she may need to impose additional requirements
if questions arise as a result of the review process (such as collecting seismic
data or placing operating restrictions on the well) or may deny the permit if the
siting does not meet the standards.
7-12
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November 2001
Class I: Siting Criteria
Class I NH (40 CFR 146.12)
- Protect USDWs
- Inject below lowermost USDW
Class I nonhazardous (Class I NH) injection wells inject below the lowermost
USDW within 1/4 mile of the wellbore, by definition (see 40 CFR 144.6(a))
and by the regulatory siting requirement (40 CFR 146.12(a)).
The permit writer will evaluate the information submitted to make sure that all
USDWs are properly identified, that any risks posed to USDWs by operation
of a Class I NH well are adequately determined and addressed by the
application, and that the geology of the area is characterized adequately to
allow the permit writer to determine appropriate and protective construction
and operating requirements in the permit. For a new well construction permit
(permit to drill), the permit writer needs to determine if EPA needs additional
information to establish operating conditions in an operating permit. The
permit to drill should be carefully written to ensure that any additional site-
specific geologic data will be collected during the drilling and construction of
the well.
7-13
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November 2001
Class I H: Siting Criteria
40 CFR 146.62
Injection zone: permeability, porosity,
thickness and areal extent to prevent
migration into USDWs
Confining zone
- Laterally continuous and free of faults or fractures
- At least one formation capable of preventing
vertical fracture propagation
At least one sequence of permeable and less
permeable strata (containment interval)
between confining zone and base of
lowermost USDW or no USDW
The injection zone of a Class IH well must have sufficient permeability,
porosity, thickness and areal extent to prevent migration into USDWs.
The confining zone must be laterally continuous and free of faults or fractures,
and must contain at least one formation capable of preventing vertical fracture
propagation if the fracture pressure of the injection zone were to be exceeded.
The containment interval (arrestment interval) we discussed earlier also is
required to be present.
Significant site-specific information is required to ensure all these
requirements are met, and modeling is conducted to depict various impacts of
the well's operation over its anticipated operating lifetime. Modeling training
for Class I wells is not included in this course. However, the process is very
important in assuring that Class I hazardous waste injection wells wells are
sited and operated safely. If you are responsible for reviewing models, you
may want to seek additional training on that subject.
As discussed for Class I non-hazardous injection wells, if the permit to drill
application lacks some geologic details that will be necessary to establish
operating conditions for the well, the permit to drill should specify what
additional data needs to be collected. The permit writer must always look
ahead in this situation, to ensure that an opportunity to collect essential data is
not missed, since many types of data cannot be collected once the casing is set
in the well.
7-14
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November 2001
Classes II, III and V:
Siting Criteria
Class II (40 CFR 146.22(a))
- Separated from any USDW by a confining
zone
Class III and Class V (40 CFR 144.12)
- Subject only to non-endangerment
provision
Class II wells must be sited so that they inject into a formation that is
separated from any USDW by a confining zone free of known open faults or
fractures within the designated area of review. This requirement is found at 40
CFR 146.22(a).
No specific siting requirements are listed in Subpart D of 40 CFR Part 146 for
Class III wells. These wells are sited in a variety of geologic locales and
situations in order to extract minerals from the subsurface. The regulations
concentrate more on proper construction, operation and monitoring. However,
the permit review process includes a detailed geologic review as we discussed
earlier. If the data indicate that a well's presence would threaten USDWs,
then the permit writer must detail the facts and present them to the applicant in
the form of a comment letter or Notice of Deficiency, in light of 40 CFR
144.12. The applicant may need to collect additional data or conduct different
tests in the well. As with any well type, if EPA determines in the end that the
well will endanger USDWs, then the Agency has to deny the permit. (The
procedural process for Agency permitting actions will be discussed in detail
later in the course.)
Well construction requirements must be included in the permit to ensure
USDWs are adequately protected during the Class III project's operation (see
40 CFR 146.31).
Similarly, the rules for Class V wells do not include siting criteria. Instead,
the permit writer focuses on overall protection of USDWs, and must base a
permitting decision on that standard.
7-15
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November 2001
Other Non-UIC Siting
Issues
RCRA regulatory requirements for
hazardous waste
Source water protection or wellhead
protection area limitations
Zoning restrictions
Other Federal or State regulations or local ordinances may affect the siting of
an injection well. While the UIC program will not generally write them into
the permit explicitly, permit writers should be aware of them since these issues
likely will be raised by the affected public. They include:
* The Resource Conservation and Recovery Act (RCRA) regulates
treatment (including filtration) and storage of hazardous waste. Under
RCRA, siting criteria include limitations on locating near floodplains and
seismic areas. For certain types of wastes, setbacks from property
boundaries are specified for storage and accumulation. These are just a
few examples of limitations that RCRA may impose on siting a
hazardous waste injection well or facility. Such permitting overlaps
demonstrate the importance of reviewing other permits that are
applicable to the facility (see Lesson 3.0-Existing Permits) and
coordinating with other program personnel so EPA's actions for the
facility are consistent.
* If an injection well is to be sited in an area that has an established Source
Water Protection Area or Wellhead Protection Area in place, limitations
may be placed on the ability to install the well. The local governing
authority would implement these restrictions.
* Zoning may prohibit the installation of various kinds of facilities,
including injection wells. Again, the local governing authority will
exercise any zoning restrictions regarding the site.
7-16
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November 2001
Sources of Data
USGS
State geological survey
Other regulatory programs
Academic sources
The U.S. Geological Survey (USGS) is a resource for both regional and local
geology. The State geological survey can provide information regarding
regional and local geology, well logs and records and historic information on
drilling and mineral resources in the area.
Other regulators may be able to provide information of value as well. Check
to see if other classes of wells have been drilled and permitted in the area, if
the drinking water program has information relevant to USDWs, and if any
special geologic studies have been required for siting of hazardous waste or
solid waste facilities.
Academic sources can provide extremely current and useful information.
Check with universities and colleges in the area to see if a PhD or Master's
student has studied relevant geologic issues for the area. Of course, the
Internet can provide helpful resources from academic and government sources
as well.
7-17
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November 2001
Summary of Geologic
Review
CHECK SOURCES VERIFY DATA!
Keep good records of communications
with other agencies and departments,
additional data submitted by applicant in
response to comments, all letters, e-
mail and telephone logs
When it comes to the geologic data, be absolutely certain that generalizations
are not inappropriately applied to the site that could affect the geologic
characteristics that make the site suitable for injection well siting. Poor siting
can have a huge, long term effect on USDWs.
Always take the time to check data sources and verify the information
presented. Review the references used by the applicant to see if recent
publications and information were incorporated. A few short e-mails, faxes or
notes to other Federal or State personnel can help you ascertain if additional
relevant facts need to be reviewed.
Ensure that your communications with others regarding confirmation of the
data are carefully recorded in the administrative record, along with any
additional data the applicant submits or you discover in your review. All the
critical information that is used to support the Agency's action on the
application must be documented in the record so the basis of the decision is
clear.
7-18
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November 2001
Lesson 8
Area of Review
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DRINKING
WATER
ACADEMY
The Area of Review of a well may be considered the "Area of Most Detailed Study," or the
"Area of Greatest Concern" regarding a UIC permit.
A primary concern of the UIC program is the potential for waste excursion from the confining
zone due to the presence of conduits. Conduits may be natural or man-made. Natural conduits
include transmissible faults or fractures that penetrate the confining zone, whereas man-made
conduits are wells or shafts. These wells may be abandoned wells that were poorly plugged (or
not plugged at all), or active wells that were not properly cemented. The pressure increase in the
injection interval can force waste (or saline formation fluids) up these conduits and into USDWs.
Several high-profile examples of this phenomenon caused Congress to specifically include AoR
issues in SDWA.
The original 1981 UIC regulations, as well as the current regulations, provide for analysis of the
area of review (AoR) as a permit requirement for all well classes. The radius of the area of
review may be a fixed radius, or it may be calculated using well-specific data. Most States use a
fixed radius for most well classes, ranging from % mile for Class II to 2 'A miles for Class I
Hazardous. Even if a fixed radius is mandated, however, it is very important that an analysis be
undertaken to determine the suitability of the fixed radius to the injection operation in question.
The basic principle of a calculated AoR is that of endangerment. Endangerment occurs when the
pressure increase due to injection has the potential to cause a column of formation fluid in a
conduit to extend above the level of the base of a USDW. Imagine a glass U-tube half-full of
water. If one blew on one end (adding injection pressure), the water level in the opposite side of
the U-tube would rise. If the level rose high enough to overflow the open end, you would have
"endangerment" on the laboratory floor, or, in the subsurface, the potential for movement of
saline or waste fluids into USDWs.
There is no standardization of AoR techniques among the different Regions and States, so each
may use a slightly different method. Nevertheless, this discussion will identify the key
parameters necessary for any AoR analysis, and will provide the math and details in these notes,
so that you can try a method if you choose. We will also go over a typical AoR attachment later
in the program.
You may also want to refer to the UIC Technical Work Group's paper summarizing approaches
to the AoR analysis (A UIC Program Summary of Regional and State Implementation of the Area
of Review, March 17, 1998. http://www.epa.gov/r5water/uic/aorsum.pdf).
8-1
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November 2001
Section Outline
AoR requirements
Mechanics of subsurface injection
Components of injection pressure
Fracturing and fracture gradient
Endangerment
AoR calculations
Exercise: Graphical method
Discussion: AoR issues
8-2
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November 2001
Attachment A
"Give the methods and, if appropriate,
the calculations used to determine the
size of the area of review (fixed radius
or equation).
The area of review shall be a fixed
radius of 1/4 mile from the well bore
unless the use of an equation is
approved in advance by the Director."
Here are the instructions for Attachment A, The Area of Review:
"Give the methods and, if appropriate, the calculations used to determine the
size of the area of review (fixed radius or equation). The area of review shall
be a fixed radius of 1/4 mile from the well bore unless the use of an equation is
approved in advance by the Director."
8-3
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November 2001
AoR Requirements
Attachment A: AoR Methods
- Calculations to determine size of AoR
- % mile unless calculation approved
Attachment B: Maps of AoR
- Location of all wells, faults, and surface
features (in public record)
Attachment A describes Area of Review methods. The applicant must give the methods and, if
appropriate, the calculations used to determine the size of the area of review (fixed radius or equation).
The area of review is a fixed radius of 1/4 mile from the well bore unless the use of an equation is
approved in advance by the Director.
Regarding the choice of a fixed radius, 40 CFR 146.6 also says:
* For applications for well permits under ง 122.38 a fixed radius around the well of not less than 1/4
mile may be used;
~ For applications for area permits under ง 122.39 a fixed width of not less than 1/4 mile for the
circumscribing area may be used. In determining the fixed radius, the following factors must be
taken into consideration: chemistry of injected and formation fluids; hydrogeology; population
and ground-water use and dependence; and historical practices in the area.
Attachment B contains maps of the well, area, and area of review. The applicant must submit a
topographic map, extending one mile beyond the property boundaries, showing the injection wells or
project area for which a permit is sought and the applicable area of review. The map must show all
intake and discharge structures and all hazardous waste treatment, storage, or disposal facilities. If the
application is for an area permit, the map should show the distribution manifold (if applicable)
applying injection fluid to all wells in the area, including all system monitoring points. Within the area
of review, the map must show the following:
* Class I - The number, or name, and location of all producing wells, injection wells, abandoned
wells, dry holes, surface bodies of water, springs, mines (surface and subsurface), quarries, and
other pertinent surface features, including residences and roads, and faults, if known or suspected.
In addition, the map must identify those wells, springs, other surface water bodies, and drinking
water wells located within one quarter mile of the facility property boundary. Only information of
public record is required to be included in this map;
^ Class II - In addition to the requirements for Class I, the applicant must include pertinent
information known to the applicant. This requirement does not apply to existing Class II wells;
and
* Class III - In addition to requirements for Class I, the applicant must include public water
systems and pertinent information known to the applicant.
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November 2001
AoR Requirements
40 CFR 144.55
Construction details for all wells in AoR that
penetrate the injection zone
40 CFR 146.14 a.3
description of each well's type, construction,
date drilled, location, depth, record of
plugging and/or completion, and any
additional information the Director may
require.
Applicants for Class I, II (other than existing), or III injection well permits
must identify the location of all known wells within the injection well's area of
review that penetrate the injection zone, or in the case of Class II wells
operating over the fracture pressure of the injection formation, all known wells
within the area of review penetrating formations affected by the increase in
pressure.
40 CFR 146.14(a)(3) requires that the applicant provide a description of each
well's type, construction, date drilled, location, depth, record of plugging
and/or completion, and any additional information the Director may require.
For wells that are improperly sealed, completed, or abandoned, the applicant
must also submit a plan to prevent movement of fluid into underground
sources of drinking water (corrective action). We will discuss corrective action
in detail later in the day.
8-5
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November 2001
Class I requirements
The number, or name, and location of all
producing wells, injection wells, abandoned
wells, dry holes, surface bodies of water,
springs, mines (surface and subsurface),
quarries, and other pertinent surface features,
including residences and roads, and faults, if
known or suspected. In addition, the map
must identify those wells, springs, other
surface water bodies, and drinking water
wells located within one quarter mile of the
facility property boundary. Only information of
public record ...
8-6
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November 2001
Class II and III Requirements
-II: In addition to the requirements for
Class I, the applicant must include
pertinent information known to the
applicant. This requirement does not
apply to existing Class II wells
-III: In addition to requirements for Class
I, the applicant must include public
water systems and pertinent information
known to the applicant.
Class II: In addition to the requirements for Class I, the applicant must
include pertinent information known to the applicant. This requirement
does not apply to existing Class II wells; and
Class III: In addition to requirements for Class I, the applicant must
include public water systems and pertinent information known to the
applicant.
8-7
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November 2001
Radius of the AoR
40CFR 146.6:
AoR determined by either:
- Fixed radius not less than % mile
-Zone of Endangering Influence (ZEI)
The area of review for an injection well must be determined according to either:
* Fixed radius around the well of not less than 1/4 mile; or
* Zone of endangering influence, within which the pressures in the injection zone may cause the
migration of the injection and/or formation fluid into an underground source of drinking water.
With a fixed radius the Director may specify an area between % mile (common in Class n permits) and the
2 Vi miles used for most Class I-Hazardous wells. The "Zone of Endangering Influence" concept, however,
is based on the actual geologic and hydraulic properties of a specific injection zone and the proposed
operating characteristics of the injection well. A prudent permit writer will always consider the AoR from
both perspectives.
The Zone, or ZEI as some call it, is an analysis of the pressure effects of injection compared to the
hydrogeologic environment of the site. Up until now, we have discussed the macro aspects of underground
injection: wells and confining zones and so on. This section will consider the role of the micro aspects of
injection, that is, the dynamics of adding injection volume to a system that is already full, in that it is
saturated with other fluids. We can describe deep underground injection as emplacement of fluids into a
closed, or at least partially-closed, system. The dynamics of adding injected volume to a closed hydraulic
system that is already "full" creates an increase in pressure within the system, just like blowing more air
into a balloon. In an injection zone that is effectively confined, this increase in pressure is not usually
harmful unless the balloon pops, that is, unless the pressure exceeds the rupture limits of the confining
zone. But in the case where the balloon has a leak, or an injection zone has a potential upward conduit like
an abandoned well, the injected fluid can escape, possibly into a USDW. So, in a nutshell, the ZEI analysis
estimates the amount of pressure we will be putting into the balloon, and the AoR analysis looks for the
leaks.
Our discussion, while based on theoretical concepts, is grounded in the practical role that injection
dynamics plays in the UIC permitting process. An understanding of the basics of injection supports the
entire area of review process, as well as a permit writer's analyses to develop permit limitations for
injection rate and volume and potential for hydraulic fracturing. There are complex equations presented on
a few of the following slides. They present the basic steps and detailed math for these analyses, however,
so that you can use these as reference materials in the event you have to perform the steps yourself.
8-8
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November 2001
Components of
Injection Pressure
Existing lithostatic and hydrostatic
pressure
Darcy friction losses
Displacement resistance
In order to understand the principles and practices involved in permitting and area
of review analysis, we must first examine the mechanics of subsurface injection.
Injection implies the introduction of fluids into the porous network of a rock or
sediment layer. Fluid injected into a subsurface reservoir does not flow into empty
voids; the injection process must displace the fluids that are already there, usually
saline water. The pressure necessary to effect this displacement consists of three
components: the existing formation pressure; the Darcian head loss that must be
overcome when pushing fluid into a porous, granular medium; and the resistance to
displacement.
Existing formation pressure can be caused by a combination of rock overburden,
the weight of the saturated fluid-column (hydrostatic pressure), the temperature at
depth, the presence of gas, and chemical reactions within the system. While the
existing subsurface pressure varies considerably among geologic environments,
almost all injection reservoirs approach nominal lithostatic conditions, that is,
containing less than 1 psi per foot of depth.
The friction losses that must be overcome are a function of permeability, and are
described by Darcy's Law. In its simplest form, Darcy's Law shows that injection
pressure is a function of injection rate and formation transmissivity (i.e., thickness
times permeability). For a given injection rate, a highly transmissive formation will
present lower friction losses than will a less-transmissive formation. That is, the
lower the transmissivity the higher the injection pressure required for emplacement
at a given rate. The effective porosity of the rock affects the amount of fluid that
can be emplaced, whereas the effective permeability of the rock affects the rate at
which fluids may be emplaced.
8-9
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November 2001
Fluid Injection
Fluid is injected into saturated pores
- Native water is displaced (open system)
- or
- Native water is compressed and system
expands (closed system)
Injection reservoirs should be closed
systems
The resistance to displacement is, in a Newtonian sense, the reservoir pushing
back. We mentioned that subsurface injection takes place into a "full"
reservoir, that is, the pores are already saturated with native saline water.
During injection, space is created for the injection fluid by two possible
mechanisms:
^ The receiving formation is part of an open system, and native water is
displaced elsewhere; or
* The reservoir is a closed system, and space is created by compressing the
native water and aquifer skeleton, as well as expanding the system
(similar to blowing air into a balloon).
All injection reservoirs are (or should be) closed systems. Although water is
generally considered a non-compressible fluid, some slight compression does
occur (3.1 x 10"6 lb/in2 at subsurface temperature). Similarly, the "elasticity"
of the rocks allows very slight compression of the reservoir rock skeleton
and/or expansion of the system, on the order of 3.2 x 10"6 lb/in2 for typical
sand injection reservoirs featuring 30 percent porosity. In simple terms, every
psi of injection pressure (in excess of existing formation pressure) creates
0.0000065 square inch of space for injectate. This may be a very small
amount, but when applied to the immense volume and area of a reservoir
system, large volumes of fluid storage may be created by injection pressure.
Oilfield applications refer to this phenomenon as the "compressibility factor,"
whereas in ground water usage it is called the "storage coefficient."
8-10
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November 2001
Delta p (A p)
Matthews and Russell (1967) show that
pressure increase is greatest at the well, but
decreases dramatically (log) with distance
Ad = 162.6 Q u flog k t -3.23]
k b 0 nCr2
The injection of fluid into a subsurface reservoir is accomplished by increasing pressure within the
system. The pressure increase is greatest at the wellbore and decreases away from the wellbore (i.e.,
into the injection formation). The effect is the mathematical opposite of the cone of depression in a
pumping well. The cone of impression created by an injection well reflects highest pressure at the
well, decreasing logarithmically with distance from the well. The amount of injection pressure
required for emplacement and the distance to which it extends into the formation depends on the
properties of the injection fluid and the formation, the rate of fluid injection, and the length of time the
injection has been going on.
The most common mathematical expression for a single well injecting to an infinite, homogenous and
isotropic, non-leaking aquifer was developed by Matthews and Russell (1967).
delta p (the increase in pressure) = 162.6 Q (|i) / k b * [ (log k t / |iC r2) - 3.23 ], where:
^ A p = pressure change (psi) at radius r and time t
~ Q = injection rate (bbl/day)
* H = injectate viscosity (centipoise)
* k = average reservoir permeability (millidarcies)
* b = reservoir thickness (ft)
^ t = time since injection began (hrs)
~ C = compressibility or storage coefficient (sum of water/aquifer compressibility and reservoir
expansion) (psi1)
* r = radial distance from wellbore to point of investigation (ft)
~ = average reservoir porosity (decimal)
It's interesting to see what REALLY matters in this analysis. In the second half of the equation, kt
over r2 usually a big number over a decimal, and the log result is usually a number between 6 and
25. Conversely, injection rate (Q) and transmissivity (Kb) are the major factors in delta-p. Similarly,
as k decreases over time (due to precipitates and solids), then delta-p will increase (or Q will have to
decrease).
8-11
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November 2001
Ap and Semi-Log Plot
- 1,000*
t - W^SWJfttfhMdabMvn mbnol Ofl -981oompjrrttotetf sjrac?
t .fw --
::i
Matthews and Russell's equation shows that delta-p declines logarithmically with distance from the
wellbore. If we assume homogeneous and isotropic conditions in the injection interval, the pressure
surface will describe a straight line on semi-log graph paper. We only need to solve for two values
of "r" using Matthews and Russell, plot these points on semi-log paper (vertical axis is arithmetic
depth and horizontal is log distance "r"), and connect the dots to describe the pressure increase
"delta-p" at any distance from the well.
Using r=10 and r=100 feet, we calculate corresponding Ap as 104.1 psi (r=10) and 79.3 psi (r=100).
These values represent the pressure increase (over existing formation pressure) due to injection of 50
gpm for 20 years. When plotted on semi-log paper, these values describe a straight line. Because
delta-p values at any point "r" are additive, we can add the delta p values to the existing formation
pressure, shown here as "P". Note that substitution of different values for injection rate (Q) or
aquifer transmissivity (k or b) will provide lines of differing slope on the semi-log graph, whereas
different "t" values will result in a family of lines of parallel slope.
8-12
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November 2001
Analysis of Formations
Formation pressure eventually
equalizes when injection stops and
pressure dissipates
Pressure buildup and equalization are
unique in each formation, allowing for
analysis of formation properties
When injection ceases, the pressure begins to dissipate to lower-pressure areas
of the system (i.e., the cone begins to flatten). Eventually, at a rate
proportional to buildup, the formation pressure will equalize to a higher, post-
injection formation pressure.
As we have seen, injection into a formation produces a pressure buildup and
equalization that are unique to that formation's geological properties.
Conversely, that phenomenon is also the basis of pressure transient analysis:
the analysis of pressure buildup or dissipation in a well allows us to solve for
the unique properties of the formation.
The most common uses of the equation of Matthews and Russell are to
determine the allowable injection pressure of a well and to assess the radius of
endangerment for area of review studies.
8-13
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November 2001
Bottom Hole Pressure
Bottom-hole pressure during injection
(BHPI) consists of
- A p (injection pressure at some Q) plus
- Weight of the fluid column
Height of fluid x density, e.g.,
4000 ft @ .4416 psi/ft = 1766 psi
BHPI also expressed as gradient (psi/ft)
E.g., 1940 psi + 4000 ft. = 485 psi/ft
We have previously considered the minimum pressure necessary for
emplacement of fluids into the reservoir. It is also important to consider this
pressure as the bottom hole pressure, or BHP, which also includes the weight
of the fluid column. The components of BHPI include delta-p (the injection
pressure), the weight of the fluid column in the tubing, and certain friction
losses at the injection face that we call "skin" losses. Unless you have a
documented test of skin losses, it's best to ignore them for most BHPI
calculations.
The weight of the fluid column equals the height of the fluid column times the
density gradient of the fluid. Charts and conversion tables allow you to
convert units to density gradient as psi per foot using traditional measurements
such as grams per cc, pounds per gallon, specific gravity, or even TDS
concentration.
Most analysts also express BHPI is as a BHPI gradient, which is BHPI divided
by the depth of the injection zone. The BHPI gradient for this example would
be 1940 psi divided by 4000 feet, or 0.485 psi per foot.
BHP can be estimated as we have done, or directly measured in the field using
a pressure sensor. You could also work at this 'backwards' in the field if you
needed to, by observing the operating well-head pressure. The problem with
this method is that WHIP (well-head injection pressure, also called SIP for
surface injection pressure) also includes friction losses in the tubing and skin
losses downhole. In some Class I wells, these losses can total hundreds of psi,
because of pore-plugging by chemical waste reactions.
8-14
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November 2001
Fracture Gradient
Injection pressure can not exceed the
fracture pressure
- Of the injection zone (Class I), or
- Of the confining zone (Class II)
Fracture pressure is unique for every
formation and time
One of the primary objectives of an AoR review is to assess the potential for hydro-
fracturing of the injection and confining zones. Hydro-fracturing occurs when
injection pressure (BHPI) exceeds the lithostatic and hydrostatic forces that confine
the pore spaces. When this pressure is exceeded, the pores are forced apart
hydraulically, just like your car is forced apart from the garage floor by the action of a
hydraulic jack when fluid pressure overcomes the downward force of gravity. In
extreme cases, hydro-fractures can cause breaches of the confining zone, and allow
wastes to escape and endanger USDWs. UIC regulations (40 CFR 146.13(a)(1))
prohibit Class I wells from exceeding the frac pressure of the rocks of the injection
zone, whereas Class II wells must not exceed the frac pressure of the confining zone
(40 CFR 146.23 (a)(1)). Many Class II wells are purposely fractured to enhance
injection or production permeability in the injection zone, but fractures are prohibited
from penetrating the confining zone.
Hydro-fracture pressure is unique for every formation, and is related to the
formation's depth, elastic modulus, overburden and fluid pressure, geologic age, and
the sand/shale ratio. The fracture pressure can change with increasing (or decreasing)
formation pressure, due to injection or production. In other words, a fracture pressure
measured early in the life of a well may not be valid after continuous injection for a
number of years. Hydro-fracture pressure information for a given area can be found in
the literature, measured directly by a drill-stem or step test, or estimated using several
possible methods.
Fracture pressure is usually expressed as the fracture gradient, in psi per foot, by
dividing the fracture pressure by the well depth. This allows test results or regulatory
standards to be applied to different wells. Frac gradients can vary from 0.65 psi per
foot for poorly-consolidated sand zones, to over 1 psi per foot in the hard rocks of the
Mid-continent and Appalachian regions.
8-15
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November 2001
Fracture Pressure
Finding fracture pressure
- Published data (oil and gas industry)
- Measured downhole using injection test
- Estimated
When considering published data from the oil and gas industry or the scientific
literature, it is important to remember that injection wells usually operate in an
environment markedly different from the oil wells that are the usual subjects
of published research. Injection well use is typically at shallower depth (less
than 7000 feet), in normally pressured, water-saturated formations of high
permeability and porosity, in areas free of active faulting and tectonic activity.
Published values for oilfield fracture gradients are usually derived from deep
production zones and overstate the true fracture gradient in shallower
formations.
Fracture gradients can also be measured, using either a specific test in the
subject well, or using industry or published data derived from fracturing
procedures.
8-16
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November 2001
Hydraulic Fractures
Planar, two lobes centered on wellbore
Most hydraulic fractures are planar, like a sheet of paper. The fracture grows
from a tiny crack that occurs when rock grains are forced apart by hydraulic
pressure. Fractures grow in opposite directions away from the wellbore,
oriented to the direction of earth stresses. Hydraulic fractures prefer to grow
upward first, because the overburden stress is less and because delta-p is
highest near the wellbore. When the fracture has grown as high as it can, it
turns and grows in the horizontal plane. Fractures grow, or propagate from
one pore to another, but, in the process, hydraulic energy is leaked-off in
directions away from the direction of propagation, and less hydraulic energy is
available to fracture the next pore in line. The amount of leak-off is a function
of permeability; so for equal pressure, fractures can grow farther in less-
permeable formations.
Commercial fractures are made by using a gelled fluid that can't leak off,
which tends to focus the hydraulic power into propagating the fracture. To the
contrary, in an underground injection environment, the clear fluids injected are
very poor at propagating fractures, and unless the injection pressure is extreme
(or the injection zone is very impermeable), it's not likely that the fracture will
grow very high or far.
The fracture will continue to grow until the hydraulic energy is insufficient to
fracture the next pore in line (in the case of a homogeneous medium) or until it
reaches a rock layer which exhibits higher elastic properties, such as a shale.
The hydraulic energy necessary to fracture a shale confining zone is extreme,
and is probably not even possible using the typical pumping capacity available
at most UIC sites.
8-17
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November 2001
Step Testing and Frac Logs
8000
1000
\
\
\
\
0
0
8
10
10
tt
TIME - MINUTES
In a step test, injection pressure is increased until the formation breaks down. These tests are usually
required for a Class I Hazardous permit application, especially in Region 5. For other wells, the most
common information available is from a nearby hydraulic fracturing procedure. Data from these
procedures is usually available from service companies who perform the procedures (such as Halliburton)
or from State agencies (given to operators to allow planning for blowouts). In either case, a step test and
fracture log provide the same information, and the terms and solutions are the same. This example is a
log of a fracture procedure. Ignore the dotted line, but concentrate your attention on the down-hole
pressure.
P-zero is the initial hydrostatic pressure in the formation plus the weight of the fluid column (BHP).
Injection pressure is increased until breakover is observed, labeled "Pc" on most logs. Once the fracture
pressure has been exceeded and a flowpath is created, continued injection into the fracture is easier as the
fracture is being extended. This phenomenon is labeled "Pp" and is known as flowing pressure. Pf is
especially significant, in that once injection pressure has exceeded a threshold fracture-pressure value,
subsequent injection into the fracture requires significantly lower pressure. Depending on the elastic
properties of the formation, the initial fractures may never heal, and the effective fracture gradient is now
lowered. In semi-consolidated formations, however, fractures can heal, and the original breakdown
pressure must again be exceeded for subsequent fractures.
When pumping is stopped, the well stabilizes at a value known as the "instantaneous shut-in pressure," or
ISIP, labeled Ps on this slide. This pressure is considered by most researchers to be equal to the least
principal earth stress in the vicinity of the well.
Many frac logs are recorded as surface pressure (always check the log header or P-zero first). For
surface-recorded logs, we would need to add the weight of the injection fluid column to ISIP to get the
true 'Fracture pressure' for the new injection well. This log is recorded as 'down-hole pressure', but
many fracture jobs use light fluids (such as methanol) or the fluid level is not to surface when P-zero is
measured. So for bottom-hole frac logs, subtract P-zero from log-ISIP for a true ISIP pressure, and then
add the weight of the proposed injection fluid column.
Because of the "Pf" phenomenon and the fact that some fractures never heal completely, many regulators
avoid fracture-testing every well, and for setting permit limitations rely instead on tests of similar wells or
on estimates of the fracture gradient.
8-18
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November 2001
Estimating Fracture
Gradient
Three principal stresses
- Overburden
-Tensile
- Compressive
Hydro-fracture pressure for a given formation can be measured directly by a
frac log or step test, or can be estimated using several methods. Most
estimation methods require specialized tests of rock properties (such as
Young's Modulus), or may be valid only for certain depths or geologic
provinces. It is possible, however, to develop a simple estimation logic using
published data and the method of Hubbert and Willis.
There are three principal stresses acting at any point in the earth's crust:
vertical overburden stress, and horizontal tensile and compressive stresses.
The tensile and compressive stresses are, as opposites, oriented perpendicular
to each other. A practical way to express that relationship is to measure their
effects at any point in the subsurface: we can define vertical stress as the rock
overburden pushing down, and describe the relationship of tensile and
compressive forces as the two, perpendicular directions of least and most
horizontal stress.
8-19
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November 2001
Hubbert and Willis (1972)
Fracture orientation perpendicular to
least principal stress
Fracture gradient is usually from 0.64 to
0.73 psi/ft in typical oil sands
More for shale-rich, hard rock, or thrust
areas (up to 1.0 psi/ft)
Hubbert and Willis (1972) are most famous for proving that fracture
orientation is perpendicular to least principal stress, (remember that hydraulic
fractures are planar and are oriented in a particular direction), when the least
principal stress is vertical, that is, the overburden is small, then fracture
orientation will be horizontal. That is the usual case for shallow wells, usually
less than 1,000 feet in depth. When the least principal stress is horizontal,
fracture orientation will be vertical. That is the case for deeper wells.
The method of Hubbert and Willis also postulates that the fracture pressure
gradient is dependent on the overburden, the pore-pressure gradient, and the
rock frame stress. In typical oil-exploration basins that feature normal
faulting, they found that the least stress is probably horizontal and from 1/2 to
2/3 the effective pressure of the overburden. Using these assumptions and
data for overburden in many regions, Hubbert and Willis found that the
fracture pressure gradient probably ranges from 0.64 to 0.73 psi per foot.
Published data from other literature sources generally agree with the postulate
of Hubbert and Willis (if we consider the geologic conditions typical of
injection wells). Test data in the field, however, has shown frac gradients
approaching 0.85 psi/ft for shale-rich sections, and in hard-rock environments
that feature thrust faulting, gradients can approach 1.0.
8-20
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November 2001
Area of Review
Calculations
Endangerment
- Pressure increase has the potential to
cause a column of formation fluid in a
conduit to extend above the level of the
base of a USDW
Suggested method in 40 CFR 146.6
Even if a fixed radius is used for the Area of Review, a prudent permit writer
should always require some analysis of endangerment. One method for
calculating the Zone of Endangerment is contained in the regulations at 40
CFR 146.6.
Remember that almost every calculation and estimation method in
hydrogeology or petroleum engineering is subject to the DePuit assumptions
that make hydrologic calculations possible. These assumptions include fully-
penetrating wells, homogeneous and isotropic reservoir properties, and
constant values at every distance and in every direction, as well as many
others. These simplifications will work in almost every case, but if you
suspect a highly compartmentalized or fractured reservoir, the only alternative
to estimation is problem-specific downhole testing and a healthy degree of
caution.
8-21
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November 2001
40 CFR 146.6
r = (2.25 KHtJK
S10x
- where
X = 4tiKH (hw - hb0 x SpGb)
235
Where:
r=Radius of endangering influence from injection well (length)
k=Hydraulic conductivity of the injection zone (length/time)
H=Thickness of the injection zone (length)
t=Time of injection (time)
S=Storage coefficient (dimensionless)
Q=Injection rate (volume/time)
h^Observed original hydrostatic head of injection zone (length) measured from the base of the
lowermost underground source of drinking water
h^Hydrostatic head of underground source of drinking water (length) measured from the base
of the lowest underground source of drinking water
Sp Gb=Specific gravity of fluid in the injection zone (dimensionless)
p=3.142 (dimensionless) The above equation is based on the following assumptions:
> The injection zone is homogenous and isotropic;
* The injection zone has infinite area extent;
> The injection well penetrates the entire thickness of the injection zone;
> The well diameter is infinitesimal compared to "r" when injection time is longer than a few
minutes; and
> The emplacement of fluid into the injection zone creates instantaneous increase in
pressure.
40 CFR 146.6 (c) states that, "If the area of review is determined by a mathematical model
pursuant to paragraph (a) of this section, the permissible radius is the result of such calculation
even if it is less than one-fourth (1/4) mile."
Note that these are ground water-type units.
8-22
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November 2001
Area of Review
Calculations
Ap= 162.6 Q u Moa k t -3.23]
k b O nCr2
Ap declines logarithmically with distance;
straight line on semi-log plot
The primary villain in our endangerment analysis is the quantity we discussed earlier, delta-p.
Remember that delta-p is shorthand for the pressure increase in the injection zone at radius "r" due to
injection of volume "Q" for time "t." The Matthews and Russell equation is formatted for oil-field
units, and forms the basis for several types of ZE1 analyses.
The most important thing to remember is that delta-p declines logarithmically with distance from the
wellbore - note that "r" in the equation is a log function. This means that delta-p, and the associated
potential for USDW contamination, would be highest nearer the wellbore.
Another interesting use of the log relationship is that we can make plots of delta-p with distance, and
the points describe a straight line on log paper.
8-23
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November 2001
Example: Injection
Pressure
Well depth: 4000 feet
Thickness of interval (b): 50 feet
Porosity (): 30 percent
Permeability (k): 400 md
Injection rate (Q) = 1700 bbl/day
Viscosity (|j) = 0.90 centipoise
Duration of injection (t) =10 yr=87,600 hours
Effective well radius (r) = .292 ft
System compressibility(C) = 6.5 x 10'6 psi-1
Well tubing = 2.375"
Injectate specific gravity = 1.02
Consider this example: use Matthews and Russell to determine delta-p for the
following well.
Depth to injection interval: -4000 feet
* Thickness of interval (b): 50 feet (measured or estimated from logs)
* Porosity (phi): 30 percent (measured or estimated from logs)
* Permeability (k): 400 md (measured or estimated from logs)
^ Injection rate (Q) = 1700 bbl/day
* Viscosity (mu) = 0.90 centipoise @ 100ฐ (measured or estimated from
chart)
~ Duration of injection (t) = 10 years = 87,600 hours (life of permit)
^ Effective well radius (r) = .292 ft (casing diameter is 7 inches)
* Reservoir compressibility or "storage" (C) = 6.5 x 10"6 psi"1 (estimated
from chart)
* Well tubing = 2.375" steel
* Injectate specific gravity = 1.02 (.44 psi/ft, from conversion chart)
~ Existing formation pressure: 1795 psig @ 4000 feet (measured)
8-24
-------
November 2001
Step 1: Injection
Pressure
Ad = (162.6) (1700) (.90) x
(400) (50)
[ log (400) (87600) 3.23]
(.30) (.90) (.0000065) (.292)2
A p = 138.6 psi at the injection face (10 yrs)
= 142.3 psi (20 years = 175,200 hours)
Refer to Handout #8-1
At the injection face (r = casing radius) and considering the lifetime of the
well (20 years), we can calculate the necessary injection pressure:
Delta-p (psi) = (162.6) (1700) (.90) x [ loe (400) (87600) - 3.23 ]
(400) (50) (.30) (.90)
(.0000065) (,292)2
Delta-p = 138.6 psi at the face of the injection interval
This is the injection pressure at the formation face required after 10 years'
service that is necessary to emplace 1700 bbl per day (about 50 gpm) into the
example formation.
If we perform the calculation for a 20-year well lifetime (175,200 hours), we
would find that delta-p equals 142.3 psi. It's interesting to see that the primary
pressure increase occurs in the early phase of injection, whereas the pressure
increase is less during later phases. The reason for this phenomenon is that in
later phases the 'compressibility factor' is being applied to a larger-and-larger
area of the reservoir, and the pressure increase at the well is proportionally
less.
8-25
-------
November 2001
Ap and Semi-Log Plot
r = \ffXJ
0 = 3ffl?5tfhfidibo*,i|.ซtBval 0fl-9B>amaediDafi>cytje
|.
i i
In the previous example, we considered increases in delta-p at the formation face, i.e., "r" = casing
radius. It is also possible, however, to specify any other distance "r" from the wellbore, and
consider delta-p buildup at distances outside the wellbore.
Matthews and Russell's equation shows that delta-p declines logarithmically with distance from the
wellbore. If we assume homogeneous and isotropic conditions in the injection interval, the pressure
surface will describe a straight line on semi-log graph paper. We only need to solve for two values
of "r" using Matthews and Russell, plot these points on semi-log paper (vertical axis is arithmetic
depth and horizontal is log distance "r"), and connect the dots to describe the pressure increase
"delta-p" at any distance from the well. Don't use a wellbore calculation as one of the points on this
analysis - without a skin test you may not be able to estimate the effective well radius (Refer to
Handout #8-2).
Assuming the 20-year lifetime of the well and using r=10 and r=100 feet, we calculate
corresponding Ap as 104.1 psi (r=10) and 79.3 psi (r=100). These values represent the pressure
increase (over existing formation pressure) due to injection of 50 gpm for 20 years. When plotted
on semi-log paper, these values describe a straight line. Because delta-p values at any point "r" are
additive, we can add the delta p values to the existing formation pressure, shown here as "P". Note
that substitution of different values for injection rate (Q) or aquifer transmissivity (k or b) will
provide lines of differing slope on the semi-log graph, whereas different "t" values will result in a
family of lines of parallel slope.
This method can also account for injection conditions that are NOT homogeneous and isotropic.
Here is how we can adjust the key elements of the equation.
~ Variable injection rate: define average injection rate using volume-to-date divided by time
period.
* Two or more injection wells: if nearby, treat as one well with combined injection rate; if not,
delta- p for each well is additive at a particular location (e.g., site of potential conduit, different
"r" for each well).
* Presence of a pumping well: solve for a negative delta-p at the pumping well and subtract from
delta-p at radius r.
> Change in reservoir properties with distance (k, b, phi): Solve for straight line solution for
nearest properties; at distance of change, solve for two new delta-p data points, with both r
greater than change distance; plot as straight line intersecting first line; each line has different
slope.
8-26
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November 2001
Analyzing the Zone of
Endanaerment
Analysis needs to account for three
elements
- Changes in formation properties with
distance
- Differences in water density
- Downward pressure from the USDW
There are several methods proposed for calculating the zone of endangerment,
including the equation first presented in the 1981 UIC regulations (40 CFR
146.6(a)(2)). Most calculation methods usually neglect three critical elements,
however: changes in formation properties with distance, differences in water density,
and the counter-endangerment, downward pressure exerted by the USDW.
Consider an example:
> Pressure increase due to injection causes a column of water to rise in an open hole
to a level equivalent to 10 feet of head above the base of a USDW. Considered at
the USDW base, the formation fluid is exerting an upward potential equal to 10
feet of hydrostatic head, relative to brine density.
* However, if the USDW is 200 feet in saturated thickness, the USDW, at its base,
is exerting simultaneously a downward potential equal to 200 feet of hydrostatic
head, relative to freshwater density.
* Any movement of fluid is in response to gradient or potential, and the gradient in
this case is downward. The USDW water will move (or attempt to move)
downward into the injection interval.
* Only when injection pressure can overcome this downward gradient can there be
the potential for upward movement, or endangerment.
One easy method for analysis of the zone of endangerment is the graphical method
used by Region 6 (Browning, 1978).
8-27
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November 2001
Graphical Method
Step 1: Plot "cone of impression" in
space
Solve A p for two V values Add Ap to
existing formation pressure
(A) Convert "psi" to "feet of head" using
gradient
(B) Add "feet of head" to (-) depth, and plot
on semi-log graph
Step 1: Plot cone of impression in space. The pressure change in the injection
interval at any distance from the well may be calculated using the Matthews and
Russell equation. Correct the analysis for changes in reservoir properties with
distance or the presence of an offset injection or production well, if necessary.
Delta-p is additive to the existing formation pressure before injection commenced (P).
Add P and A p (psi), and convert to feet of head by dividing each by the density
gradient of the formation fluid (psi/ft).
* (A) (previous slide) For our example well, we found that P + delta-p = 1795psi +
104.1 psi for r=10 feet, and 79.3 psi for r=100 feet. The specific gravity of the
formation fluid is 1.07, or 0.46 psi/ft gradient (from conversion chart). Convert
(P + delta-p) to feet of head of formation brine: 1899.1 psi / .460 = 4128.5 ft of
head @ r=10 feet, and 1874.3 psi / .460 = 4074.6 feet of head @ r=100 feet.
* (Bl) Consider the height of the fluid column by adding these values to the
(negative) depth of the injection interval. Relate to the injection interval depth by
adding to the (negative) depth value: -4000 ft of depth + 4128.5 ft of head =
+128.5, or a column 128.5 feet above land surface, at r=10 feet. For r=100 feet, -
4000 + 4074.6 = +74.6.
* (B2) Plot these values as a straight line on the semi-log plot discussed earlier,
substituting "feet (head or depth)" for "psi" on the vertical (arithmetic) axis.
This plot shows the pressure surface within the injection interval as it exists in space,
measured as feet of head of formation brine above the top of the injection interval.
8-28
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November 2001
Example Graph
)
This is the graph of the example well that we showed earlier.
* Note that P, the existing pressure in the injection interval, is converted
from "psi" to "feet of head of formation brine" by dividing by the density
gradient of the brine, .460 psi per foot.
* The pressure increase due to injection after 20 years (delta-p) was solved
for two points (r=10 and r=100) and plotted as a straight line on the semi-
log plot.
^ Delta-p is additive to the existing formation pressure, and is also
converted to "feet of head of formation brine."
Remember that these values can be adjusted for changes with distance from
the wellbore.
~ For example, a second injection well located at r=1000 could be solved
for a delta-p curve and plotted (a pumping well would use a negative
delta-p).
~ The delta-p values are additive at all r's, and a new cone, characterized by
distinct, intersecting slopes, is created.
~ Similarly, if P was found to decrease due to formation "dip" into the
subsurface, then P would describe a line of decreasing slope, and delta-p
would be additive to that.
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November 2001
Graphical Method
Step 2: Compare P + A p to P1a, the
density-adjusted pressure surface of the
USDW
(A) Calculate the height of the USDW water
column (P1)
(B) Adjust density (USDW / formation gradient)
(C) Add to (-) depth of USDW base and plot
Intersection is radius of endangerment
Similarly, some pressure (PI) exists at the base of the lowermost USDW,
which corresponds to the weight of a column of water in a well that fully
penetrates the USDW. Therefore, the second step of the method involves
plotting the pressure surface of the USDW in space, and comparing it to that
of the injection interval at a point of reference.
Step 2:
* (A) Calculate the height of a column of water that would exist in a well
fully penetrating the USDW section (PI). In most cases, data is available
(or can be estimated) concerning the depth to water (for unconfmed
aquifers) or surface pressure (for artesian aquifers). Consider the height
of the column as measured from the base of the lowermost USDW.
^ (B) Convert that value into "feet of head of formation brine" by
multiplying the height of the USDW column (PI) by the additional
density gradient of the formation fluid you used in Step IB, compared to
the density gradient of fresh water (.434).
* (C) For example, consider that a USDW exists from the surface to a depth
of 400 feet. The lowermost USDW is a confined, artesian aquifer, and
the water level measures 26 feet above surface. Therefore, PI equals
about 426 feet. Using the density gradient of the formation fluid (.460)
compared to that of the fresh water column (.434), we find that, as feet of
head of formation brine, PI a equals 426 x .434/.460 = 401.9 feet.
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November 2001
The pressure surface of the USDW is measured or estimated as the height of a column
of water in a fully penetrating well. In this case, we specified a confined, artesian
aquifer with a water column equivalent to 126 feet above land surface, or 426 feet. To
use this value on the same graph as the other values, we must convert this value to
"feet of head of formation brine." To convert from psi, divide by the density gradient
of the brine, in this case .460. To convert directly from "feet of USDW head,"
multiply by the ratio of density gradients: .434 (fresh water) over .460 (brine). Add
this value to the (negative) depth value of the USDW base, and plot this value that we
call PI a, or PI, adjusted. The intersection of the Ap and Pla lines denotes the radius
of the zone of endangerment.
Remember, if there were a pumping well in the USDW at distance r=1000, we could
perform a "negative Q" solution for the Matthews and Russell equation, and plot as
"negative delta- p" or cone of depression, that is, subtract the negative values from the
Pla of the USDW injector. Note that the Pla line would change to a downward slope,
and the radius of endangerment would be much larger.
We have performed an analysis of hydraulic potential considered at the base of the
USDW. This analysis of flow/no flow could also be performed using another depth
reference, such as the base of surface casing, depth of a cement plug, etc.
We used an example which features a measurable radius of the zone of endangerment
(i.e., intersection of the pressure surfaces on the graph). There may also be cases in
which there is no zone of endangerment (i.e., the Pla surface is higher/greater than
that of the injection interval) or cases where the zone of endangerment is infinite (P+
delta-p is greater than Pla at all values of r).
8-31
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November 2001
Short Method
Use as a check for %-mile radius
1) BHP+Ap (@1320ft.) \ density gradient
1795+51 / .460 = 4014 feet of head
2) Subtract (well depth - depth to USDW)
4014 - (4000 - 400) = 414 feet of head @usdw
3) USDW saturated thickness x density ratio
400 feet x .433/.460 = 377 feet of head @usdw
4) Compare 2 and 3
If 2>3, %-mile AoR radius too small
If 2<3, AoR OK
414>377:1/4-mile AoR not enough
You can use a 'short' method to check for the applicability of a particular AoR
radius, usually the lA mile default radius. Use a measured or estimated BHP,
and solve delta-p for a radius of 1320 feet (1/4 mile). In the example case, the
value is 51 psi. Add BHP and delta-p, and divide by the density gradient, in
this case, .460 psi per foot. That gives us an upward gradient of 4014 feet of
head.
We must consider endangerment at the base of the lowermost USDW,
although you could also use any other point of reference, such as the top of
cement of an offset well. From the value in step 1, subtract the depth to the
base of the USDW from the well depth, in this case, 3600 feet. The result is
the upward gradient considered at the base of the usdw, or 414 feet of
UPWARD head.
For step 3, adjust the saturated thickness of the usdw by the ratios of density-
gradient, in this case, 400 feet times .433 divided by .460. The answer is the
downward gradient at the base of the usdw, or 377 feet.
Now compare 2 and 3. If the upward gradient is larger than the downward
gradient, endangerment is indicated and your lA-mile AoR radius is too small.
If 2 is less than 3, lA mile is sufficient. In this case, the upward gradient (414
feet) is greater than the downward gradient (377), which indicates that the
default radius is not appropriate for this example. If you want to know how
big the endangerment radius is, you have to do the extended analysis.
8-32
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November 2001
AoR Issues
Some States use "mud gradient"
calculations
- Piston-displacement of .8 psi/ft mud column
- Grossly understates radius of endangerment
Most oil wells and Class II wells feature
minimum long-string cement, and short
surface casing
- If injection interval offset, pathway to USDW
Remember that any analysis for endangerment assumes a worst case scenario:
instantaneous communication between the injection interval and the USDW
through an open hole. This is unlikely for two reasons: 1) unless the abandoned
wellbore is cased, pressure will leak off into intervening permeable layers, and 2)
the presence of mud or other fluids in the abandoned wellbore will delay or
prevent communication. Some State agencies use a calculation that incorporates a
"mud gradient" of up to .8 psi/ft, that is, includes the weight (or gradient) of a
column of mud in the abandoned hole. Unfortunately, these calculations imply
that a mud column must be literally increased to the level of the USDW before
flow will take place. This piston-like displacement of the mud column is highly
unlikely, and laboratory studies show that flow in mud occurs through wormholes
(wet mud) and shrinkage discontinuities (drier mud), and along the borehole
boundary. The use of the mud gradient equation unfortunately results in grossly
understated zones of endangerment.
A common scenario in Class I and II involves the presence of active or plugged
production wells that were not fully cemented. Almost all production wells and
the vast majority of Class II wells do not feature complete cement of the long-
string casing, but rather feature cement that extends as little as 100 feet above the
top of the injection interval. The balance of the long-string/borehole annulus is
filled with diluted drilling mud, or whatever fluid was in the borehole at the time
of cementing. If this uncemented casing is opposite the injection interval, flow
can occur along the outside of the uncemented long-string casing. Note also that
all production wells (and most Class II injection wells) feature surface casing that
does not extend to the base of USDWs. This situation provides a pathway directly
from the injection interval into USDWs.
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November 2001
Review Essentials:
Radius
Well class requirements
- Class 2: 1/4 mile or area permit
- Class III: area permit?
-Class I: 2to2.5miles+
Endangerment?
- Class II in existing project: 1/4/ mile
- New Class II D project: short method
-Class I or IID-commercial: full analysis
Here is a partial list of the steps to take to review an AoR attachment for a
permit application.
First, what class of well are we dealing with? Most UIC programs will
automatically specify the V* mile fixed radius for Class II wells, with the
notable exception of Class D-D commercial. Furthermore, most Class II wells
are probably a part of an existing area permit, and no further analysis is
necessary (assuming the well meets the conditions of the previous area
permit). Most programs also use area permits for Class III wells also. If you
are reviewing a new area permit, remember that the AoR analysis extends 1/4/
mile from the project boundary. Class I wells and Class II-D commercial
wells usually default to a 2 or 2.5 mile radius.
Regardless of fixed radii or the usual practices or policies in your program,
you have to ask yourself: does this well pose a threat of endangerment? If
you have even a suspicion, perform an analysis like the one shown here, or
some other method. It is not likely that a Class II well in an existing field is
really going to endanger anything that wasn't already endangered in the past;
you can usually feel safe in allowing the Vi mile radius. But for new Class II
projects or II-D wells in a new disposal zone, at least consider the short
endangerment analysis. For Class I wells and IID commercial wells, apply
some analysis as a rule. In fact, never permit ANY Class I well without a
complete endangerment analysis.
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November 2001
Review Essentials
List of wells
- Public information versus search
Construction and cementing data
Corrective action in later section
Once you have answered the questions of endangerment and established an
appropriate radius, these are the next things to look for.
The operator will provide a list of wells that penetrate the injection zone. For
Classes II and III, the operator can use "information from the public record."
For Class I wells, however, the operator should look outside the typical API
and "Oil Scout" reports, but check directly with the State oil and gas agency,
county records, etc. In cases of known endangerment, some programs have
required operators to conduct landowner interviews or geophysical
investigations.
Regardless of whether or not you have defined endangerment, make a graph of
the depths of wells that the operator has identified in the AoR. Better yet,
instruct the applicant to provide you with a graph as a visual aid in your
analysis. Better still, if you have done the graphical analysis we did as an
exercise, you can plot the well depths and construction right on the graph.
~ Make a depth versus distance plot and lay out the injection and confining
zones and the base of USDWs. On that graph, plot the wells in the AoR,
using distance from the injection well and depth. Note any important
construction details on the plot, like top of cement or location of plugs.
> Corrective action may be necessary to deal with wells in the AoR that
might serve as conduits. We will cover corrective action in another
section.
8-35
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November 2001
Lesson 9
Maps of Well and
Area of Review
m)
DRINKING
WATER
ACADEMY
All Class I, II and III well permit applications are required to have an
Attachment B. This attachment is a topographic map that extends one mile
beyond the property boundaries of the injection well facility. It is up to the
EPA to decide if this map will be required for a Class V injection well permit.
Certainly, deeper, more high tech Class V wells that inject under pressure
should be required to submit this information. For Class V wells that are
gravity fed, the necessity and appropriateness of submission of this map
should be based on site-specific data that indicates the likelihood of the
injection well having an impact for any distance away from the well itself.
For instance, even a gravity fed well that receives a relatively constant flow
of one-half to one GPM can impact a highly permeable aquifer for some
distance.
The following things must be illustrated on the map for the facility, according
to 40 CFR 144.31(e)(7). Again, the extent of requirements for a Class V well
permit will be site-specific and this list may be altered for this well class only.
* Injection wells or project area (for area permit);
* All intake and discharge structures;
~ All hazardous waste treatment, storage or disposal facilities (TSDFs);
and
* For area permits, the Attachment B instructions require the operator to
illustrate the distribution manifold for the wells and all system
monitoring points.
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November 2001
Purpose of Attachment B
Visual depiction of potential migration
conduits
ID other operations and land uses that
may impact or be impacted UIC facility
The purpose of the map for the AOR is to provide a visual depiction of the
facility and potential conduits for upward migration of injection fluids.
It also provides a visual depiction of nearby land uses and operations that
could be impacted by, or could cause impact to, the UIC facility. This
information will not necessarily cause the UIC program to refuse to issue the
permit, since proximity of homes, schools, and other land uses are not
considered in the UIC statutes and regulations. However, if multiple
receptors are located close to the facility, this may cause you to add
conditions to the permit, especially if there are drinking water wells nearby.
Also, the information about nearby land use is helpful so you can anticipate
public concerns. If the well is in a very rural area, it is less likely to prompt
significant public concern compared to a UIC well being permitted in or very
near a residential area, for instance.
9-2
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November 2001
Information in the AOR
Producing, injection and abandoned
wells
Dry holes
Surface water bodies
Mines and quarries
Residences and roads
Known or suspected faults
From here it gets a little more complicated. The entire list of items required
is on page 4 of the permit application. Essentially, all types of wells, all
mines and quarries, and all surface structures within the AOR (e.g., houses,
roads, faults that extend to the surface, manufacturing facilities,) must be
identified.
Within 1/4 mile of the facility boundary, all wells, springs, surface water
bodies and drinking water wells must be specifically identified.
The specific requirements of the application form are different among the
three well classes, so refer to the directions for Attachment B when reviewing
the application.
For facilities in populated areas, a significant amount of information may be
included in the list above. The good news for the applicant is that the
requirement is limited to publicly available information, so no field
verification is required.
9-3
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November 2001
Frequent Omissions
Map doesn't extend one mile from
property boundaries of the source
Facility features are out of date
Locations of drinking water supplies not
consistent with PWSS program records
Map scale is not meaningful
When reviewing the map, you should be aware that it is not uncommon for
this seemingly simple requirement to be a stumbling block to some operators.
The map may not be prepared for a wide enough area. For a larger project,
the applicant may be concerned that extending one mile beyond the boundary
of the project is onerous. But it is the regulatory requirement, so that is the
size map that must be submitted.
The facility details may not be up to date, so review those and discuss
questions with the applicant.
Check with your PWSS counterpart to see if all public water supplies have
been identified in the appropriate area.
While a large enough map may be submitted, is it at a scale that is
meaningful and legible? If not, request that it be resubmitted so that you can
use it for your review.
9-4
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November 2001
Administrative Record
Comments issued to and responses
received from applicant
Ensure any map updates are inserted
into the application to replace prior
versions with omissions or errors
As with all portions of the permit, any comments issued by EPA to the
applicant, and any responses received from the applicant, regarding changes
to application pieces such as the AOR map, must be placed in the
administrative record.
Also, make sure that any updated maps or data supporting the map are
inserted into the application. It is not uncommon for replacement maps to be
set aside, and issues one thought were resolved crop back up again. Paper
and data management is critical to having a complete and accurate
administrative record.
9-5
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November 2001
Lesson 10
Corrective Action
Plan and
Well Data
We have talked about the AOR and defined it. However, a complete AOR
analysis considers the relationship between pressure surfaces that co-exist in
time and three-dimensional space. That is why a well owner or operator has
to look for potential natural or man-made conduits in the area of review.
This information must be submitted in Attachment C of a UIC Permit
Application.
In this section, we will talk about what the regulations require for the
analysis, what information needs to be evaluated, steps that an owner or
operator can take, and how the permit writer evaluates a plan for dealing
with potential conduits within the AOR.
Please be aware that Corrective Action (CA) is defined differently in the
hazardous waste regulations under RCRA compared to what we will discuss
in this section. Additional CA requirements may apply to a Class IH site as
imposed by a RCRA permit. This section of the course deals strictly with
CA requirements of the UIC rules. The UIC Program Guidance #45, entitled
Interim Guidance Concerning Corrective Action for Prior and Continuing
Releases, April 9,1985, describes how EPA implements CA requirements of
RCRA for injection wells. The overlap between SDWA and RCRA CA can
be complicated. If you become involved in evaluating a Class IH permit
application, you should discuss this issue with a permit writer who
understands the limits of the UIC requirements and the overlap with the
RCRA requirements.
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November 2001
Purpose of Requirement
Integrity of UIC system is dependent on
proper containment
Wells needing CA are likely vertical
migration conduits, causing
contamination
EPA need conduits ID'ed and must
ensure proposed measures are
adequate to protect USDWs
We have discussed previously how important the concept of USDW protection is to the
UIC Program. Conduits that can allow fluids to migrate upward into a USDW include
naturally occurring faults, natural or induced fractures, shafts from mining or other
operations, and other wells. The corrective action plan requirements of the UIC regulations
focus on other wells that exist in the AOR. Siting requirements are intended to address the
other types of conduits.
The integrity of the whole UIC well system concept is based on the absence of vertical
conduits to USDWs. Proper containment will not exist if unidentified conduits exist within
the area where changes in pressure will drive fluids upward into USDWs.
EPA needs to be aware of any identified conduits, have the authority to review data on the
conduits, and ensure that all have been properly identified and addressed.
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November 2001
Evaluation of Wells in
APR
Well types to be reviewed
- Active production
- Other active injection
-Temporarily abandoned
- Permanently abandoned
Wells that need to be evaluated may be abandoned wells that were poorly plugged (or not
plugged at all), active wells that were not properly cemented, or temporarily abandoned
wells that could pose a risk due procedures used. The pressure increase in the injection
interval can force waste (or saline formation fluids) up these conduits and into USDWs.
Several high-profile examples of this phenomenon caused Congress to include UIC issues
in their consideration of SDWA.
Depending upon the depth of the injection well being permitted, types of wells may include
oil or natural gas production, water producing wells, or other injection wells of any Class.
The corrective action rules are located in 40 CFR 144.55,146.7, and 146.64 (for Class IH
wells). The requirements for Class II wells are a little different from those for Classes I and
II, but the essential concept is the same.
The search is limited to reasonably available data, as stated on the instructions for the
Federal UIC Permit Application. In some unusual circumstances, field work may come into
play. However, the review generally is based on records available to the public.
10-3
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November 2001
What is the
Requirement?
UIC regulations require three steps
- Identification of certain wells in AOR
- Determining which of the wells need
corrective action
- Developing and submitting a plan for the
action
First, wells that may allow migration of fluids into USDWs must be identified. For Class I
and Class III wells, all known wells in the AOR that are completed into the injection zone
of the well being permitted must be identified. This requirement also applies to Class II
wells that were drilled after April 1983 (when the rule was first effective). Permit
applications for Class II wells that are operating over the injection formation fracture
pressure must identify all known wells within the AOR that penetrate formations affected
by the increase in pressure. Some of the wells may be identified on the map of the AOR,
but maps are not always current. Because of this, a search needs to be conducted beyond
the information presented on the topographic map. In addition to a map, the applicant must
provide tabulated details of all the wells that lie within the AOR or zone of endangering
influence and penetrate the injection zone.
For each well that is identified as being completed at the depths listed above, the applicant
then has to review the well records to evaluate how the well was constructed and, if it is
abandoned, how it was plugged. Construction and/or plugging records need to show that
the well is not a potential conduit. This means the cement or well log records need to show
that cement is present in sufficient amounts and with proper placement behind pipe to
prevent upward fluid movement. For plugged wells, a sufficient number of plugs at
appropriate depths need to be in place to prevent fluid migrating upward to a USDW.
If the applicant discovers that some wells exist that have not been properly plugged, or
perhaps never were plugged, that temporary abandonment procedures are not adequate, or
that construction records indicate that cement placement is not adequate to protect USDWs,
the applicant has to submit a CA plan to deal with these wells.
The CA plan is reviewed by EPA and must be determined to be "adequate."
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November 2001
CA Plan Evaluation
What is being injected and how much
Native fluids and injection by-products
Potentially affected population
Geology and hydrology
Injection history
P&A records and procedures
Hydraulic connections with USDWs
The regulations list nine factors that need to be considered when determining if a CA plan is
"adequate." The list is found at 40 CFR 146.7. Additional items must be considered for a Class IH
CA plan, as listed in 40 CFR 146.64. We will focus on the basic requirements in this course. You
should review 40 CFR 146.64 if you are involved with a Class IH well.
First, you need to consider the character and quantity of the fluid being injected. Generally
speaking, larger volumes injected 24 hours a day will pose greater risk than a small stream injected
intermittently, since the larger volume will cause larger subsurface pressure increases. However, we
reiterate that a site-specific analysis needs to be completed, as geologic conditions can change
significantly from site to site, affecting the Ap that determines whether endangerment will occur.
Also, different fluids pose varying risks to USDWs, so fluid composition needs to be considered.
The nature of the native fluids or by-products of injection need to be evaluated. Not only injected
fluids, but native formation fluids and those substances created by interaction of the injectate and
native formation fluids may migrate through an artificial conduit.
The potentially affected population is evaluated to see if sensitive populations exist, and how many
people may be affected if a conduit is present.
Geology and hydrology must be evaluated, since the characteristics of the injection formations,
confining layers and USDWs vary so greatly from one site to another.
The history of the injection operation must be examined. If the well subject to permitting has been
operating for a significant amount of time and the applicant can show that no migration has occurred,
this needs to be considered. Also, the historic operating pressures of the operation need to be
considered.
Well completion and plugging records help the Agency evaluate what is present in the subsurface.
An evaluation of procedures that were used when an existing well was plugged helps you decide
whether you can have confidence in the plugging job that is in place.
Hydraulic connections with USDWs are critical, for obvious reasons.
10-5
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November 2001
Sources of Information
Historic maps and aerial photographs
Oil, gas and water well drilling records
Well logs and completion records
P&A permits and records
Field survey for problematic wells
Where can the applicant or the permit reviewer find the information needed? The State
historical society or other repositories of historical information may be able to provide
information on historic drilling practices in a given county or township. Historic maps,
aerial photographs, and other publications often are available from this source as well.
The State Geological Survey usually retains records of well drilling activities, including
well logs and completion records from across the State. The records may be available in
any number of record formats, from electronic access to plain old-fashioned paper.
Historic procedures used in plugging and abandoning wells may be available from
agencies that issued permits or approvals for closing a well. Permits and records of well
closures are available from the agencies that regulate the various well types, State
Geological Survey, and/or the State historical society.
Occasionally, one or two wells may turn up that are problematic, where their status is
uncertain. A field survey can be conducted to locate and evaluate these wells if
necessary. Generally, this will not be necessary.
Let's assume that the publicly accessible information has been located and reviewed, and
these data indicate that one or more wells exist that pose a risk to USDWs. Perhaps a
well was not plugged prior to abandonment. This means there may be a way for fluids to
move upward into a USDW as a result of the injection operation being considered in the
permit application.
10-6
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November 2001
Corrective Action
Potions for Operations
Reduce ap
Monitoring
Remedial cementing
Plugging or re-plugging
What now? It is best to work with the operator and guide his response
regarding what can and can not be done to mitigate or eliminate the
endangerment, especially if the operator is not experienced in dealing with
these issues.
As we have shown previously, the driving force of endangerment is A p. If
the operator can reduce the effective A p in the injection interval, the
operator may be able to operate without restrictions. Remember the analysis
for WHIP and the elements of the delta-p equation. The methods include:
* Lowering the injection rate;
* Reducing the viscosity and/or specific gravity of the waste;
* Eliminating friction in the tubing (for example, using bigger tubing)
and friction losses in the completion (installing a gravel pack or more
perforations);
* Increasing permeability in the endangered radius (for instance using
acid treatments); or
* Increasing the thickness of the injection interval by perforating more of
the section.
In most cases, one or more of these modifications will mitigate
endangerment. Of course, any of these modifications or limitations need to
be addressed in the permit language.
In many process operations, however, modifications to the injection scheme
are not possible, and further corrective action is needed.
10-7
-------
November 2001
Corrective Action Options
for Existing Wells
Monitoring in the injection interval
Remedial cementing
Plugging offset wells
If the endangerment involves an unplugged well or point source, a common form of
corrective action is the use of a monitoring well completed in the injection interval. The
well should be located between the injection well and the unplugged well, nearer to the
latter. The permit would establish an action level A p value for the monitoring well, or
sampling for the arrival of the waste front. In either case, the action level standards can
not be exceeded, and signal the closure of the well. Although monitoring wells are
effective, make sure that the well is also capable of internal and external MI testing.
Other forms of monitoring may be implemented as well, such as visual observations.
UIC Program Guidance #23, Corrective Action Requirements, July 27,1981, provides
EPA policy on specifying monitoring requirements under the CA rules for UIC wells.
Remedial cementing is a common method of corrective action, especially for Class II
projects. In many cases, a relatively shallow disposal zone in a field featuring a deep
production zone will expose the uncemented portion of partially-cemented long-string
casings of the producing wells. In this case, if A p remedies are not available, operators
will squeeze-cement all producing wells along the interval exposed to Class II injection.
This is common in many fields, where only shallow zones offer the permeability to
accept the volume of produced water. Squeeze-cementing is not a cure-all for repairing a
poorly cemented well, but it is usually effective in preventing upward migration along
uncemented casing.
Plugging offset wells is an effective method of corrective action. Casing must be pulled
from the wells, however, so that a wall-to-wall plug can prevent upward migration
outside the casing. Re-entering poorly plugged wells can be a technical challenge and
immensely expensive. It is very difficult to measure the effectiveness of these
procedures, because deviated boreholes and other problems can cause more trouble than
the original unplugged well would have. Use this option very sparingly, as there are no
guarantees or measurements of success.
5 10-8
-------
November 2001
When is the USDW
Protected?
Site specific
May require combination of responses
EPA is responsible for determining
protection is adequate
Evaluate all options - what are success
measures?
As you can see, the decision about what level of CA is needed is definitely site-specific.
The actions taken for a given permitting project may require anything from no action at
all to multiple CA steps.
The regulations allow EPA to decide what is adequate, given the variety of factors that
are listed in the rules that must be considered for CA. It is important to evaluate all
options, and ensure that you have a means of measuring the success of the selected
options. Otherwise, you cannot know if the USDW is being protected or not.
For a permit renewal application, it is important to ensure that the applicant has contacted
appropriate agencies and updated recent drilling and other information so that EPA can
have confidence that no new conduits are present.
As with all portions of the application review, document your decisions in the
administrative record, and make sure that any updated plan submissions are inserted into
the application.
10-9
-------
November 2001
Lesson 11
Construction,
Cementing,
and Cement
Calculations
DRINKING
WATER
ACADEMY
This section will discuss the processes of well construction and cementing, as
they apply to permit analysis.
Construction and cementing standards and oversight form the basis for
injection well regulation under the UIC program. Most of the immediate
threats to USDWs originate with poor construction and cementing practices.
Regions and States witness some of the construction and cementing
procedures for many Class I wells, but few Class II and III procedures are
witnessed. In most cases, the operator proposes a well design and reports the
results of construction to the UIC primacy agency. Permit standards and
conditions that are technically correct and appropriate for each well class and
geologic environment ensure that USDWs are protected.
In this section, we will consider the technical aspects of reviewing a
construction program. Later today, we will also review an actual
construction program, step by step.
You may also want to refer to two papers by the UIC Technical Work Group:
* Use of Annulus Additives to Address Leaks in Deep Injection Wells
(http://www.epa.gov/r5water/uic/issue5.htm); and
* Cementing Requirements in Direct Implementation Programs to
Achieve Part II of Mechanical Integrity in Class II Injection Wells
(http://www.epa.gov/r5water/uic/cement.pdf).
11-1
-------
November 2001
Attachments L and M
Attachment L: Construction procedures
Attachment M: Construction details
Construction standards are contained in 40 CFR 146.12 for Class 1,40 CFR
146.22 for Class II, and 40 CFR 146.32 for Class II.
These standards are addressed in a permit application in Attachments L and
M.
Attachment L requires the applicant to discuss the construction procedures to
be utilized. This should include details of the casing and cementing program,
logging procedures, deviation checks, and the driving, testing and coring
program, and proposed annulus fluid. The permit applicant must submit
justifying data if requesting to use an alternative to packer for Class I.
Attachment M requires the applicant to submit schematic or other appropriate
drawings of the surface and subsurface construction details of the well.
11-2
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November 2001
Performance Standard
All Class I, II, or III injection wells
shall be cased and cemented
to prevent movement of fluids
into or between
underground sources of drinking
water.
The absolute goal of the UIC program is to prevent injection from putting
anything whatsoever into a USDW. It is easy to find agreement that fluid
should not move "into" a USDW. But the regulations have always specified
that movement is also prohibited "between" USDWs; for example, 7,000
TDS waters flowing into 1,000 TDS waters.
The only problem with "between" is that it requires 100 percent cementing of
the casing. The vast majority of Class II wells do not feature complete
cementing, and many State programs do not always require complete
adherence to the principle of "between." Keep this in mind when reviewing
permits issued by many State agencies.
11-3
-------
November 2001
Injection
Well
Components
A typical injection well is composed of several key components, and best fits the description of a
pipe-within-a-pipe-within-a-pipe.
Surface casing extends from the surface to the base of the lowermost USDW. For Class II wells in
some States, the depth of surface casing may be prescribed according to a different standard, for
example, to the base of 3,000 mg/1 TDS rather than 10,000 (e.g., Texas), or as 10 percent of the total
well depth (e.g., California and Arkansas). Surface casing represents the outermost string of pipe,
and its purposes are to protect USDWs from the effects of the drilling process, and to furnish a
redundant layer of protection for USDWs. Surface casing sizes range from 6Vi to 15 inches in
typical wells, or up to 60 inches in municipal wells. Surface casing is almost always fully cemented
into the borehole.
Intermediate or long-string casing extends from the surface to or through the injection zone.
Typically from 4!4 to 10 inches in diameter, long-string casing is the primary layer of protection for
the well. The casing is cemented into the borehole to prevent fluid movement outside the pipe along
casing. For Class II wells, the long-string may be only partially cemented, and cement typically
extends 100 feet above the confining zone.
Tubing carries the waste from the surface to the injection interval. Typically from 2/2 to 7 inches
diameter, it is hung from the wellhead and set on a packer. The wellhead and packer seal the
annulus and provide a method of pressure testing for leaks. In Class I wells, the annulus is
maintained at a constant pressure, for continuous monitoring of annulus integrity. Class INH wells
are allowed to request an exemption from using a packer. A prudent permit writer would have to
have a very persuasive reason to exempt the packer. The packer-wellhead annulus forms the first
line of defense in the UIC program, in that it allows the well to be self-monitoring. Packerless wells
generally do not provide the same level of protection.
The injectate enters the injection interval through a well screen and gravel pack or through a series
of perforations of the long-string casing.
This diagram features typical Class I construction. The differences between Class I and other
classes involves the extent of long-string cement (Class II), the amount or presence of surface casing
(Classes II and III), and the presence of tubing and/or packer (Class IM, IIH, and III).
11-4
-------
November 2001
s
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Almost all injection wells are drilled using rotary methods. Rotary drilling is boring a
hole by using a rotating bit to which downward force is applied. The bit is attached to
and rotated by a drill pipe, which extends from the drill face to the turntable on the rig
floor. Drilling fluid, usually mud, is circulated down the drill pipe, past the bit, and
upwards between the drill pipe and the hole. The drilling fluid carries the rock chips
and cuttings up the hole. The cuttings are separated from the mud for analysis of the
drilling progress, and the mud is re-conditioned and continually re-used.
The rig turntable turns the drill pipe via the Kelly bushing, a joint of square tubing that
fits in the square hole in the turntable. Mud is pumped down the tubing and back up
the hole. When 20 or 30 feet of hole is made, another joint of drill pipe is screwed on
and drilling continues. When casing is run, special tools are used to screw it together.
We'll cover cementing in another section.
When the hole has been drilled and the casing set and cemented, the well is
completed. Either bullets are fired through the casing (known as "perforating") or a
special tool is used to ream the injection zone wider than the bottom of the casing. A
slotted screen is installed and pea-gravel circulated around it. This method is called a
"gravel-pack" completion, and has much higher hydraulic efficiency.
Tubing is run in the hole, and the size has been chosen based on what size will fit and
provide the best trade-off between minimizing factional losses and reducing cost. A
packer is set to seal the tubing-casing annulus. Packers can be a simple, cast-iron
design costing $400, or a complex, 60-feet-long, multiple-element, PBR-type design
that uses exotic metals and costs $1.2 million.
11-5
-------
November 2001
Drilling Hazards
Environmental problems
associated with construction
-Deviation
-Lost circulation
-Junked hole or stuck pipe
There may be environmental hazards associated with the drilling process.
* Deviation occurs when the well tilts from the true vertical condition and
another hole is created. When the drillbit enters a hard zone from a soft zone,
the bit can "walk" and re-start the wellbore at an angle. Sometimes, the drill-
string will straighten itself, causing a "dogleg," or kink in the middle of the
well. This is bad for tool entry and maintenance, but the worst part is that you
are guaranteed a poor cement job as the casing will lie to one side of the hole
and/or restrict cement circulation. In a worst case scenario, the driller realizes
he is off-track, and will pull up and try to straighten the hole by up-and-down
motion of the drillstring. What usually happens is that the bit will head off in
another direction entirely, and there will be a "phantom" well bore that
parallels the first. That is also a sure way to get poor cementing and, in
extreme cases where it involves penetration of the confining zone, the
deviation can present an avenue for migration.
* Lost circulation is when a porous and permeable zone steals a large proportion
of the mud. The drill string usually sticks at that point, and the efforts to free it
will, at the least, create an oval hole, which can be bad for cementing. At
worst, the pipe remains stuck and the hole is worthless. If the hole is deep
enough, it could act as a conduit to shallower zones.
> Several other problems can ruin a hole or stick the drill pipe, such as junk in
the hole, sloughing or heaving formations, or differential-pressure sticking.
"Blowouts" could also be included in any list of drilling hazards, but drilling
injection wells does not involve the conditions in which blowouts occur: deep,
high-pressure zones; gas; and wildcat drilling.
11-6
-------
November 2001
Data Obtained During
Drilling and Completion
Numerous opportunities to obtain site-
specific data
Data used to predict performance
Test types
- Rock and fluid sampling
- Geophysical logging
- Pressure and transient testing
During drilling and completion, there are numerous opportunities to obtain
site-specific data concerning the geology, hydrology, and engineering
properties of the injection zone, confining and containment zones, and
USDWs. Many of these types of data are essential to predicting the
performance and acceptability of the injection operation over time, and
provide a sound foundation for permitting decisions.
The types of tests and sampling methods can be classified as rock and fluid
sampling, geophysical logging, and pressure transient testing. We will
discuss the logging phase of construction here, but we will discuss the
"Formation Testing " program separately after this section.
Remember that most UIC construction is not witnessed. The permit writer's
only connection to the construction process is the operator's submission of
the Completion Report. Make sure that you specify in advance the standards
and types of logs and samples that you require.
11-7
-------
November 2001
146.12 "Considered.."
Resistivity, SP, gamma, caliper logs
cement bond, temperature, or density
log
Fracture finder logs
Fluid pressure, temperature, fracture
pressure
Physical and chemical characteristics of
the injection matrix and formation fluids
The UIC regulations suggest the suite of logs and tests necessary to support a
permit application. The types of information shown here "shall be
considered" for open-hole, after the casing is cemented, and for testing the
injection and confining zones. Consider this the minimum of information.
In Class II and III applications, most of what you will see is data developed
when the field was first drilled. For Class I, although the regs allow "similar,
available" data in the application, you should insist on verification logs and
tests performed directly in the well in question.
11-8
-------
November 2001
Method
Property
Appl Icatlon
Spontaneous
Potential
-------
November 2001
Open-hole
Well Logs
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Method
Ganma Ray
Spectral
Gamma Ray
Gamma-Gairma
Neutron-Gamma
Neutron-Thermal
Neutron
Neutron-Epi ther-
mal Neutron
Pulsed Neutron
Capture
Spectral Neutron
Property
Gravity Meter
Ultra-Long Spaced
Electric Log
Nuclear Magnetism
Temperature Log
Natural radioactivity
Natural radioactivity
Bulk density
Hydrogen content
Hydrogen content
Hydrogen content
Decay rate of thermal
neutrons
Induced ganina ray
spectra
Application
Shales and nonshales; shali-
ness
Lithologic Identification
Porosity, Hthology
Porosity
Porosity; gas from liquid
Porosity; gas from liquid
Water and gas/o1l saturations
revaluation of old wells
Location of hydrocarbons;
lithology
Density
Resistivity
Amount of free hydro-
gen; relaxation rate
of hydrogen
Temperature
Formation density
Salt flank location
Effective porosity and
permeability of sands; poro-
sity for carbonates
Formation temperature
11-10
-------
November 2001
LOG
FUNCTION
1.
Cement bond
Determine extent and effectiveness of
casing cementing
2.
Gamma ray
Determine Hthology and presence of
radioactive tracers through casing
Cased
3.
Neutron
Determine Hthology and porosity through
casing
4.
Borehole televiewer
Provide an image of casing wall or well
bore
Hole
5.
Casing Inspection
Locate corrosion or other casing damage
Logs
6.
Flowmeter
Locate zones of fluid entry or discharge
and treasure contribution of each zone
to total injection or production
7.
High resolution
thermometer
Locate zones of fluid entry Including
zones behind casing
8.
Radioactive tracer
Determine travel paths of Injected fluids
including behind casing
9.
Fluid sampler
Recover a sample of well bore fluids
10.
Casing collar
Locate casing collars for accurate
reference
11.
Fluid pressure
Determine fluid pressure in borehole
at any depth
12.
Casing caliper
Locate casing damage
11-11
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November 2001
Cement
and
Cementing
After casing is installed in the well, cement is circulated to seal the casing
into the borehole. Cement is required on long string casing to prevent fluid
and waste movement out of the injection zone and to protect casing from
corrosion. Class I wells usually require complete cement to the surface,
whereas most Class II wells feature only partial cement, usually a hundred
feet above the top of the confining zone.
The tubing, casing, and packer can be directly tested for integrity by means of
an MI pressure test and, in Class I, continuous monitoring of the annulus
pressure. Cement, however, can not be directly tested, but its presence and
competence may be indirectly measured by means of wireline logs.
11-12
-------
November 2001
After casing is set in the well, a cement slurry is pumped downhole through the casing, and back
up the annular space between the pipe and formation. The technology supporting modern well
cementing is a complex science of cement properties and mechanical devices, used to achieve
good cement coverage downhole.
A schematic of a typical cementing job is shown here. As the casing is run in the hole, the string is
assembled to include a "guide shoe" at the bottom and a "float collar," which acts as a check valve
to prevent cement from flowing back into the casing after it has been pumped down.
"Centralizers" are run at intervals to ensure the casing is centered in the hole, so that the cement
slurry can flow evenly up the hole and provide uniform coverage. Cement is mixed at the surface
prior to being pumped downhole as a slurry.
The cementing operation begins when the "bottom plug" is released down the wellbore,
immediately followed by the cement slurry. When the hollow bottom plug lands or "bumps" into
the float collar during pumping, the increase in pressure causes a rubber membrane in the plug to
rupture. The cement then passes through the bottom plug and begins moving up the casing-
borehole annulus. When a sufficient volume of slurry has been pumped, an "Upper" or "Top"
plug is introduced to the wellbore. The top plug separates the cement slurry from the displacement
fluid that follows.
When the top plug lands on the bottom plug in the float collar, the slurry has been displaced from
the inside of the casing and a dramatic pressure increase is seen at the surface. This signals that
the cement job is complete. The cement then "cures" to its final hardness over a period of 8 to 30
hours, depending on slurry composition and downhole temperature.
In deeper wells, the length of casing to be cemented may present the risk that the weight of the
cement column might exceed fracture pressure. "Cement fracs" occur when fracture pressure is
exceeded and the cement level falls as slurry enters a hydraulic fracture until hydraulic equilibrium
is re-established. This is prevented by cementing the well in stages using the same methods.
In Class I wells, the volume of cement slurry is designed to allow circulation of slurry to the
surface before the top plug lands. In most Class II wells, however, the volume is designed to
extend only a few hundred feet above the injection zone, primarily for reasons of economy.
-------
November 2001
Cement Classes and
Additives
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Cements are manufactured according to standards developed by the American Petroleum Institute
(API). The API classifies cements based primarily on temperature rating, using a letter rating
from Class A to Class J. API class "G" cement is the most commonly used.
Cement cures through a process of crystal growth. Once the cement is in place around the
casing, it is important that the crystallization process proceed quickly so that water from
permeable formations does not dilute the slurry and prevent crystallization.
Cement is broadly classified as "neat" or "tailored." Neat "Portland" cements are finely ground
mixtures of calcium compounds, usually ground-up limestone. Iron and aluminum oxides are
added, and the material is subjected to intense heat in a rotary kiln. After heating, gypsum is
added to form the completed cement.
Tailored cements contain additives to modify the slurry properties for a particular downhole
condition. Additives may be used for a variety of reasons: to raise or lower slurry density, to
increase compressive strength, and to accelerate or retard the setting time. The most common
types of additives are:
^ Accelerators and retarders: to speed up or slow down the early stages of curing, depending
on downhole temperature. Calcium chloride is the most common accelerator, used at 2 to
4 percent by volume in shallower, low temperature wells. Lignosulfates are the most
common retarders.
* Extenders: to reduce slurry density to prevent cement fractures. Bentonite, sodium silicate,
and Pozzolans (from volcanic ash) are the most common extenders. High-strength foam
cements may also be used to cement long stages.
* Lost circulation agents: additives to prevent losses to vugular or weak zones, from corn
cobs and walnut shells to engineered gel agents.
* Fluid-loss agents: control water loss from the slurry into permeable formations. Bentonite,
polymers, and cellulose derivatives are most common.
~ Weighting agents: increase slurry density to prevent blowouts in high pressure zones. Lead
ores are most common.
~ High temperature additives: Portland cement becomes unstable above 750ฐ F. Geothermal
wells and some deep gas wells require the use of calcium aluminate or calcium silicate
cements.
11-14
-------
November 2001
Cement
Volume
Calculations
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-------
November 2001
Cement Calculations
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(D2.- d2) 0.0009714 = bbl/foot
The first-cut analysis involves simple geometry. What is the volume of the
hole, minus the volume of the casing that is in the hole? Most manuals
provide a table of values for different borehole/casing combinations. For
example, the Halliburton handbook specifies that the volume between 7-inch
casing and a borehole of 8.5 inches is 0.0226 barrels per linear foot of depth.
There is a formula available also: (D2 - d2) x .0009714 for barrels per foot
and .005454 for cubic feet per foot, where capital-D is the hole diameter and
little-d is the outside diameter of the casing.
If the attachment includes a design cement volume, you can perform a rough
comparison of cement volumes. Subtract the outside diameter of the casing
from the bit size, and multiply by the depth cemented and you have a rough
idea of the minimum cement volume necessary to provide the appropriate
cement coverage. Conversely, you could use the known cement volume and
divide by the "barrels per foot" value to get the maximum number of feet
cemented.
After the completion report has been submitted, use the caliper log is to
perform this calculation. Mark the intervals where the hole is in or out of
gauge. Most people disregard excursions of less than an inch, unless it occurs
over more than a hundred feet. For those excursions of the borehole diameter
that are over one inch and/or 100 feet, you can do the same calculation in a
micro scale. Use "hole diameter plus 1" for big D, and the gauge hole
diameter for little-d.
Most engineers use a safety factor when calculating cement volume. Most in
the oilfield use 15 percent excess, but many Class I programs use up to 40-
percent excess. Most Class I operators would rather pay for discarded
cement, than see a cement column come up short.
11-16
-------
November 2001
Principles of Cement Logs
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Hang a length of pipe from a string and hit it with a hammer. The pipe will
ring loudly, like a wind chime. Now, hold it in your hand and hit it; the
sound is only a thud. The basic principle of cement logging is that cement
muffles the sound of casing. Unsupported casing, if hit by a hammer or other
acoustic source, will ring loudly. The amount of sound produced is called the
"amplitude." Cement around the casing will drastically reduce, or attenuate,
the sound.
The amplitude produced by an acoustic signal in pipe is highest when
unsupported and lowest when a sheath of hard cement is bonded to the entire
casing periphery. Lab and field experiments have found that a linear
relationship exists between increasing amplitude and the portion of the casing
periphery that is not supported by cement.
Cement logging tools utilize an acoustic transmitter and one or more
receivers. The transmitter emits a timed, 20 kHz signal, which transmits
elastic compressional waves traveling vertically and horizontally in the
borehole fluid. Of primary interest is the wavefront moving horizontally,
directly toward the casing wall. As the wavefront impinges on the casing,
some energy is reflected, while the balance is transferred into the steel, the
cement sheath, and the formation. At each interface, some energy will be
reflected, and some will be transferred into the adjoining medium.
11-17
-------
November 2001
Amplitude:
How Loud?
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Poorly
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No Cement
Effectively
Cemented
When acoustic energy is transmitted into the borehole fluid, the nearest
reflective component is the well casing. The reflection of that energy from
the casing wall to the receiver is called the "first arrival." The amplitude of
that reflected signal is directly related to the thickness of the casing, and to
the presence and amount of cement that supports the casing.
A high amplitude indicates casing that is free to vibrate, and is poorly or
incompletely supported by cement.
A low amplitude indicates the casing is supported by cement, which causes
adsorption and transmission of the wave energy to the surrounding media.
Amplitude measurements between maximum and minimum values are a
function of the percentage of casing bond.
The primary component of a cement log is the amplitude measurement.
11-18
-------
November 2001
Energy Reflections:
When and How Much?
The first arrival is the reflection of energy from the casing wall. We can also
measure the reflection of energy from other components of the well system.
Compression waves from the transmitter pass through the borehole fluid, the
casing, the cement, and the formation, and return to the receiver. Passage
through these media alters the character of the compressional wave. Each
material exhibits its own characteristics that influence wave velocity,
amplitude and frequency.
The wave train above is a representation of the time of arrival and character
of the compressional wave reflected by each component of the well system.
The first arrival represents reflections from the casing, then the cement, then
the formation, and finally the mud wave traveling vertically down the
wellbore.
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11-19
-------
November 2001
Louder
Equals
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Film Strip
Representation of
Acoustic Wave on ^
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Variable Density Log
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Acoustic Wave Train
Signature
The frequency and amplitude of the wave components can be shown
graphically in what is known as a "variable density display."
* The spacing of the bars represents the frequency of the wave
components, and the shading of the bands represents the amplitude.
* The horizontal scale is time of arrival, in microseconds: casing first,
followed by cement, formation, and so on.
11-20
-------
November 2001
Variable Density Log
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The variable density display is labeled in microseconds. The display features
the equivalent of a wave graph for every foot of depth. The time of arrival of
casing reflections is constant, and is determined by the size and weight of
casing. If formation arrivals are shown, the presence of cement is inferred.
11-21
-------
November 2001
Typical
CBL
Cement
Log
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This is a typical CBL log. The combination of amplitude and wave analysis
provides a tool for interpreting the presence and condition of cement. Many
class II wells will utilize older, less-expensive technology such as this CBL.
These logs feature a lot of information at first glance. Remember that
amplitude, or loudness, is the primary measurement. It is located on the
center track, and may be called different things by different companies, but it
is always scaled in millivolts, or MV. There are usually two presentations: a
simple scale and an amplified scale for when the amplitude is really low due
to perfect cement. On the right is the variable density waveform display.
It's been said that interpreting a CBL is more art than science. I say that's it's
all science - the 'art' stuff is BS put out by consultants! I won't go into
details on how to interpret these logs, as that is the subject of another module.
What I want to point out, however, is that many, if not most, of these logs are
'faked' to some degree.
The primary method of accuracy and calibration of the tool is a single knob.
The logging engineer must set the equivalent of a "volume" control in the
logging truck (the amplitude gain and/or gate), and an improper setting of this
control can result in an over- or under-optimistic log presentation. For an
semi-accurate calibration, the logging engineer must find a zone of 'no
cement' in the well, and 'zero' the tool. If there is no zone which he knows is
-------
November 2001
Typical
3rd Generation
Cement
Log
360ฐ Channel
Peru Sand
30ฐ Channel
There are plenty of CBL-type logs still used for Class II wells, but this is an example
of the so-called "third generation" of logging tools used for most Class I wells. This
log was run in Jerry Thomhill's Ada cement-test well. These tools use several,
directional transmitter-receiver pairs in a single tool, and utilize computerized signal
discrimination and analysis for interpretation and presentation. Examples of these
logs include Dresser-Halliburton's SBT and Schlumberger's CET tools.
Computerization allows for a pretty easy interpretation: black is good (i.e.,
competent cement), white is bad (poor or no cement), and grey is something in
between.
However, these logs can be faked as in the case of the old CBL's. The key is to note
on the log header an input value called something like "input compressive strength"
or "screening value strength." This value is the equivalent of the old Gain knob on
CBLs, as it sets the maximum value the log will look for, as compressive strength (in
psi). Another way of saying this is that the input compressive strength value is how
strong the cement has to be to read as full-black on the log presentation. NEVER
accept a log that has an input value lower than 1000 psi compressive strength, but
1500 psi is much more realistic. By setting this value to 300 or so, mud will look
black on the log. Beware: many Class I wells were given permits based on black
logs. Know what the compressive strength input of the log is before you make any
determination!
11-23
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November 2001
Miscellaneous
Deviation checks
Driving, testing, and coring
program
Proposed annulus fluid
Attachment L also requires information concerning these aspects of
construction.
We discussed deviation under "drilling hazards." Deviation occurs when the
drillbit walks offline and the hole starts off at a diverging angle. When the
operator discovers his error and pulls up to straighten the hole, he can leave
another hole next to the wellbore. If this occurs near the confining zone, a
conduit can be inadvertently created. Deviation used to be more of a problem
in the past, but most modern rigs allow a continuous measure of angle. In
cases where continuous measurement is not feasible, operators stop the
drilling process periodically to run a wireline measurement in drill pipe.
Most rotary rigs use a casing hammer to drive conductor pipe a few feet when
beginning the well, but this has no environmental implications.
Formation testing will be discussed in the next section. Coring is a method of
retrieving 20-foot long, bit-diameter samples of formations. For Class I
hazardous wells, these are necessary for lab testing of waste reactions and
permeability, but coring is very expensive and rarely done for other wells.
If the well has an annulus, the operator will fill it with something. Air or
other gases are too compressible and do not provide accurate MITs, and do
not provide differential support for the tubing. Annulus fluids must be
corrosion-resistant, so most operators use brine with an additive. A few Class
II operators use diesel fuel, and in permafrost environments most operators
use glycol.
11-24
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November 2001
State Class II
Requirements
Some States allow
- Short or no surface casing
- No tubing or no packer
Minimum long-string cement
-100 feet?
- Both injection and production wells
Injection opposite uncemented zones
provides pathway
Presented on the following slides are a few scenarios to be on the lookout for
when you review a construction program. In many Regions, EPA may have
permitting responsibility for Class I wells, which can exist side by side with
Class II wells permitted by a State agency that uses different construction
standards. For example:
* Short or no surface casing: most Class II injection wells feature
surface casing that does not extend to the base of USDWs. Rather than
depth to the lowermost USDW, Arkansas, California and a few other
States require surface casing as a percentage of depth, usually 10
percent. In several other States that do use a water quality standard,
surface casing depth is set according to local practice, usually related to
"drinkable quality" or 3,000 mg/1 tds.
~ No tubing: In Texas, for example, any well of less than 1,000 feet is
not required to use tubing (or surface casing) (Rule 13). Similar
standards are used in Kansas, Indiana, and several other States.
Almost all production wells and the vast majority of Class II wells do not
feature complete cement of the long-string casing, but rather feature cement
that extends as little as 100 feet above the top of the injection interval. The
balance of the long-string/borehole annulus is filled with diluted drilling mud,
or whatever fluid was in the borehole at the time of cementing.
If this uncemented casing is opposite the proposed injection interval, upward
flow can occur along the outside of the uncemented long-string casing. If the
well in question ALSO features short surface casing, this situation provides a
pathway directly from the injection interval into USDWs.
11-25
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November 2001
Technical Pitfalls
Cement to surface: required, but rare?
Reports of long-string cement to surface
(but cement fell)
A study of cement issues in a large southwestern State found that almost all of the well
schematics and/or permit narratives indicated long string cement to surface. However,
almost 90 percent of wells with logs show top of cement (TOC) at least 400 feet lower,
and 30 percent have TOC below the surface casing shoe.
Of the wells where a cement log was available to allow the interpretation, only a handful
of wells were found that truly had cement to surface. Thirty-three of 37 had TOC at least
400 feet below surface, and for most it was more than 1,000 feet. Eleven wells (30
percent) were found to have TOC below the surface casing shoe, with 6 wells having
TOC several hundreds or thousands of feet below the shoe.
A few of these wells experienced mechanical failures during primary cementing.
However, the study found two mechanisms whereby an operator (or agency witness)
could report cement to surface, but actually have TOC far down the hole.
It found several instances in drilling logs where operators reported long string cement to
surface (sometimes witnessed by inspectors), but who found that the cement column then
fell, either immediately or up to two hours later.
> This condition is common in cases where operators attempt to cement long
intervals of casing, and the weight of the cement column causes the cement to
fracture the formation.
* The cement runs into the fracture until hydraulic equilibrium is re-established,
sometimes after hundreds or thousands of linear feet of cement have "gone south,"
as it is called in the oil field.
The study also found many instances in the file reviews where the installed cement
volume grossly exceeded the annular volume of the hole, but the TOC was still hundreds
of feet down the hole, and massive cement fracs were indicated.
11-26
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November 2001
Technical Pitfalls
Incomplete displacement of the mud
column (short-circuiting)
"Top job" - add cement to an
incomplete or falling cement column
Incomplete cement logs
A second mechanism would involve incomplete displacement of the mud column, or
"short-circuiting." In this case, cement could arrive at the surface having bypassed a
significant volume of the casing/hole annulus. In other cases, drillers may report returns
of what is actually gray water, rather than cement. Whatever the mechanism, the study
found that the vast majority of the active Class I HW wells with cement bond logs (CBLs)
do not have cement to the surface.
The study found several instances of operators attempting to "top" long string cement
jobs, sometimes after reporting returns to the surface. A "top job" is a procedure in which
an operator attempts to add cement to an incomplete or falling cement column by adding it
from the surface through 1 -inch tubing in the annulus or bullheading into the bradenhead.
Some operators will even specify this method as a contingency.
This procedure is rarely successful and, if the cement volume calculations were originally
correct, implies a cement fracture at the shoe. If you see this procedure in a construction
program, be sure to remind the operator that top jobs imply problems and require extra
diagnosis. If ever you see any mention in a Class I completion report about "topping out,"
suspect cement problems and immediately order the best cement log the operator can run.
Production well long-strings are cemented only to keep the water out, and to save money
most operators will log only the cement immediately above the production zone. Most
Class II wells feature only partial cement on the long string, and many operators will do
the same thing. Be sure to specify that all cement in the well be logged. If you are
specifying that the entire long string be cemented, make sure that you get 100 percent of
the well logged, top to bottom.
11-27
-------
November 2001
Technical Pitfalls
"Continuous" cement
For .Bond Inooi 0.8
\
\
V
/
5 5v> 6 T 6 9 9hl0
Casing Sue
The big Southwestern State study found that about half of the wells had major
cement problems over substantial intervals of the long string. Some of the
wells had sufficient bonding in the lowest interval above the injection interval
to rate a fair-to-good rating overall, but a few wells appear to have absent to
poor cement bond overall.
The question is now being discussed in UIC forums: How much of what
quality cement is good enough for Class I service? What is the performance
standard supporting UIC "hydraulic isolation" requirements? The basis for
an answer lies with standard oil industry practice. "Hydraulic isolation" is
defined by the oil and wireline logging industries as the number of feet of
continuous cement bond, of greater than 80 percent quality, that will
reasonably assure isolation of adjacent, normally pressured, permeable zones.
Eighty percent bond is the condition in which 80 percent of the circumference
of the casing is supported by cement. The number of feet of 80 percent bond
necessary to achieve hydraulic isolation is a function of casing size. For
example, the interval requirement ranges from 5 feet for 5- lA inch casing, to
15 feet for 9-5/8 in casing.
The question becomes: how many intervals of hydraulic isolation are
necessary in the well? At a minimum, each of three intervals would need at
least one zone of hydraulic isolation: near the base of surface casing (for both
surface and long string casing); within the confining zone; and between the
top of the confining zone and the base of USDWs.
11-28
-------
November 2001
Technical Pitfalls
Remedial "squeeze" cementing
- Often tried but not always successful due
to restrictions behind casing
- Applicable for uncemented casing
Remedial cementing is a common method of corrective action, especially for
Class II projects. Squeezing involves perforating the casing, setting bridge
plugs or packers above and below the perforations, and pumping cement into
the voids behind the casing.
In a poorly-cemented well, most squeeze jobs are not successful because
circulation behind the casing is very limited. In a zone that has not been
cemented or that is entirely devoid of cement, circulation can be established
and hydraulic isolation can usually be achieved.
Squeeze-cementing is not a cure-all for repairing a poorly cemented well, but
it is usually effective in preventing upward migration along uncemented
casing.
11-29
-------
November 2001
Technical Pitfalls
Packer set within 100 feet above
injection interval
T
Incomplete casing strings
Used equipment?
^Conductor
USDW
Liner hanger
A common pitfall in many permit applications is a well schematic that
provides for packer setting somewhere up the hole. This is convenient for
operators, since there is less annulus to monitor and a cost savings due to
fewer joints of tubing used in the well. The drawbacks for a permit writer are
that a greater amount of casing is exposed to the injection stream, and the
entire well is not subject to internal MIT. Always check, and insist that the
packer be set within 100 feet of the current injection interval.
Occasionally you will see a well design in which the operator will propose a
liner hanger and an incomplete casing string. This is used a lot for production
wells, and may show up as a Class II design. Technically, the surface casing
isn't there, or you could say the upper part of the long string serves double-
duty. In most areas, if this design featured complete cement it might be
acceptable. Most likely, however, the cement will cover the bottom hundred-
or-so feet of each casing string (and that's not enough).
As mentioned, there is usually a lot of used tubing and casing lying around
most big-company equipment yards. There is nothing specific in the
regulations about the use of used equipment, provided it can pass an MIT.
But, given a five-year MIT interval, at least disposal wells should feature new
tubular goods. If you think the use of new components is an issue, make it a
permit condition or at least mention it somewhere.
11-30
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November 2001
Permit Review
Design protects USDWs?
- Regulatory prioritization
- Full cement + tbg/pkr unless good reason
Surface casing versus USDW base
Cement coverage
Packer placement
Logs and sampling next section
Many reviewers get concerned with trivia like the grades of casing and the
cement additives. The operator probably knows what works in that field, and
what sizes, grades, and additives will give him mechanical integrity. Instead,
focus on these issues, the essential items to look for in reviewing the
construction attachments of a permit application.
* Does the design protect USDWs? For Class I or commercial Class II-D,
that usually means cement to the surface and tubing and packer. For
Class II, however, you may that find partial cement and a packer
exemption meet the regulatory standards. For Class II, consider the
proximity of USDWs and threat posed by the injectate. You should
specify cement to the surface casing shoe and tubing and packer for any
design or well class, unless there is a good reason to accept less.
Remember, cost can be a good reason.
^ Where is the base of the 10,000 tds USDW? You may not know,
because the State uses a different standard of 3,000 tds for production
wells. It doesn't make much sense to demand 2000 feet of surface
casing when every other well in the field has 1,200.
> Verify the cement coverage by asking for details rather than just
accepting the shading on a schematic drawing. Remember the between
standard if surface casing does not cover all the USDWs.
* Specify as a permit condition that the packer must be set within 100 feet
of the current injection interval, not just 100 feet above the injection
zone.
We will cover the logging and sampling program in a later section.
11-31
-------
November 2001
Exhibit 7-1 (rnlMd)
Propa Commrtan Minn
Northstar Well WD-1
KOF: 500* J
Hit ftnoti 40* I
OvpartanatSHL: Appro* 3700*
(180088)
Discussion
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11-32
-------
November 2001
ATTACHMENT "V (Continued)
Excess Cement Volume for Surface Casing
The 9 5/8" surface casing was cemented to surface with 350 sxs of
regular Class A cement. This volume is 40.5% in excess of the
required annular volume as shown below:
Vol. Req. = HP2 - PD* (L)
183.33
%
Where: Vol. Req. is the cement slurry volume required (ft1)
HD is the hole diameter (in)
PD is the pipe diameter (in)
L is the desired length of the cement column (ft)
HD =ฆ 12.250 in
PD = 9.675 in
L = 937 ft
Vol. Req. = 12.252 - 9.625* (937)
183.3
Vol. Rep. = 293.48 ft*
Vol. used = (sx)(yield)
Vol. used is
Sx is the number of sacks of cement used (sx)
Where: Vol. used is cement slurry volume used (ft3)
Yield is the slurry yield per sack of cement (ft1)
Sx = 350 Sx
Yield =1.18 ft/sx
Vol. used = f3501 fi.iai = 413 ft3
% Excess = Vol. used - Vol. reo. (100)
Vol. req.
Vol. used =413 ft'
Vol. req. = 294 ft
* Excess = 413 - 294 (100) * 40.5%
294
11-33
-------
November 2001
Lesson 12
Formation
Testing
Program
DRINKING
WATER
ACADEMY
Attachment I concerns the formation testing program. Testing of the
formation rocks and fluids takes place during completion activities, and may
involve sampling, pressure testing, and chemical and physical analysis, for
USDWs or for the injection and confining zones. The purposes of formation
testing can involve almost any aspect of the UIC program, such as:
Verifying the lowermost USDW;
Logging to determine permitted intervals;
Sampling, testing, and logging in support of model validation; or
Collecting in-situ samples to simulate down-hole chemical reactions and
products.
The instructions for Attachment I suggest the scope of testing necessary to
support different permit levels.
12-1
-------
November 2001
Formation Testing
Program
Requirements for new Class I wells in 40
CFR 146.12(e)
Determine or calculate:
- Fluid pressure
- Temperature
- Fracture pressure
- Other physical and chemical characteristics of the
injection matrix
- Physical and chemical characteristics of the
formation fluids
40 CFR 146.12(3) requires the permit applicant to determine or calculate:
^ Fluid pressure;
* Temperature;
* Fracture pressure;
* Other physical and chemical characteristics of the injection matrix; and
* Physical and chemical characteristics of the formation fluids.
Be sure that the applicant includes radiological characteristics in its analyses.
Note also that the formation testing requirements for Classes I, II, and III
apply only to new wells.
12-2
-------
November 2001
Formation Testing
Program
Requirements for new Class II wells or
projects in 40 CFR 146.22(g)
Determine or calculate
- Fluid pressure
- Estimated fracture pressure
- Physical and chemical characteristics of
the injection zone
For new Class II wells or projects, the permit applicant must determine or
calculate:
* Fluid pressure;
* Estimated fracture pressure; and
* Physical and chemical characteristics of the injection zone.
12-3
-------
November 2001
Formation Testing
Program
Requirements for new Class III wells at 40
CFR 146.32(c) apply to injection zones that
are naturally water-bearing
- Fluid pressure
- Fracture pressure
- Physical and chemical characteristics of the
formation fluids
If the formation is not water-bearing, 40 CFR
146.32(d) requires only fracture pressure
We discussed fluid pressure in a previous section. It's another way of saying
static bottom-hole pressure; that is, the weight of the fluid column as defined
by fluid density and column height.
We also covered fracture pressure in a previous section, which can be
measured in a step-test, estimated using State or service-company fracture
logs, or estimated using the method of Hubbert and Willis.
Determining the physical and chemical characteristics of the formation usually
involves mineralogical analysis and shale identification, porosity
measurement, and permeability tests. Some fracture-related properties such as
Young's Modulus of Elasticity can only be measured using specialized down-
hole samples.
Determining the physical and chemical characteristics of the fluids usually
involves physical and chemical analysis, but in Class I wells that feature
corrosive or reactive wastes, testing for down-hole compatibilities can involve
many other types of additional analyses.
12-4
-------
November 2001
Use of "Similar Data"
In determining tests and logs to be
conducted, may consider. .availability
of similar data in the area of the drilling
site..
-40 CFR 146.12(d)(2), Class I
-40 CFR 146.22(f)(2), Class II
-40 CFR 146.32(b), Class III
The regulations allow operators to submit non-original data to satisfy
formation testing requirements.
For Class I wells, however, you should require basic correlation logging,
porosity and mineralogy samples, and a cursory drill-stem test for the specific
well.
In Class II and III applications, however (unless the application is for a
municipal well), much of what you will see is data developed when the project
was first drilled. It is not usually necessary to require much beyond a
correlation log, but most operators would run those logs anyway, to assist
cementing design.
One issue that isn't discussed very much is that a permit writer can exempt
operators from extensive formation testing if there is no USDW within lA mile
of the wellbore.
12-5
-------
November 2001
Data Obtained During
Drilling and Completion
Several opportunities to obtain site-
specific data
Data used to predict performance
Test types
r- Rock and fluid sampling
- Geophysical logging
- Pressure and transient testing
During drilling and completion, there are several opportunities to obtain site-
specific data concerning the geology, hydrology, and engineering properties of
the injection zone, confining and containment zones, and USDWs. Many of
these types of data are essential to predicting the performance and
acceptability of the injection operation over time, and provide a sound
foundation for permitting decisions.
The types of tests and sampling methods can be classified as rock and fluid
sampling, geophysical logging, and pressure transient testing.
Most U1C construction is not witnessed. The permit writer's only connection
to the construction process is the operator's submission of the Completion
Report. Make sure that you specify in advance the standards and types of
sampling that you require.
12-6
-------
November 2001
Rock Sampling
Mud and cutting analysis u**
Sidewall cores
St
Full diameter cores
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Almost every Class I and II injection well utilizes rotary drilling methods. As the
bit advances by grinding the penetrated rock into small chips, the mud system
carries these chips to the surface. Shakers and other filtration equipment separate
the rock cuttings from the mud, prior to its recirculation into the hole.
Periodically, the collected chips are washed and examined under a microscope.
Careful analysis of the drill cuttings will yield an accurate depiction of the
stratigraphic column. Soft shales and unconsolidated sands will not yield useful
samples, however.
Sidewall cores can be taken by a wireline tool that carries hollow, cylindrical
bullets from 7/8 to 1 3A inches diameter. When the sidewall sampler is in position
opposite a formation of interest, a hollow bullet is fired into the borehole wall.
The bullet and sample are retrieved by means of a cable attached to the tool.
Sidewall cores are very useful for lithologic analysis and for basic measurements
of in-situ permeability and porosity.
Full diameter cores are taken in 20-foot sections using a hollow coring bit, either
drilled or pushed. In contrast to sidewall cores, full cores provide a continuous
sample of the borehole and provide better samples for testing. These samples
range from 1 to 5 inches in diameter and from 20 to 60 feet in length, depending
on the tool configuration. In addition to lithology and permeability information,
full diameter cores exhibit important geologic features such as fractures, bedding
planes, solution cavities, and other macro-scopic characteristics. More
importantly, full diameter cores can be used for "core-flood" studies, in which the
intended waste is injected through the core in a dynamic process that includes the
downhole aspects of temperature and pressure. The downside is that full diameter
coring is a very expensive process, and core recovery in poorly consolidated
formations can be problematic.
12-7
-------
November 2001
Fluid Sampling
Drill-stem testing
Nitrogen lift and swabbing
Downhole formation sampler
Samples of fluid from the injection zone or a USDW provide important information in the
permitting process. Samples of injection zone fluid allow testing for corrosion or injectate
reactions. Sampling USDWs in the borehole provides salinity data, and when USDWs prove to
be more saline than expected, might serve to support exemptions from other UIC drilling and
testing requirements.
Drill-stem testing is a technique in which a zone in an open borehole is isolated by a temporary
packer, and fluid from the zone is allowed to flow through a bottom-hole valve and into the drill
pipe. Fluid may flow to the surface, or be trapped within the drill pipe until it is pulled and the
contents of the pipe sampled. We will discuss pressure transient testing with a drill-stem test in a
subsequent slide.
Swabbing is a method of fluid recovery that uses a collapsible element within the drill pipe. The
element collapses on the down stroke through the drill pipe, but opens on the up stroke, rests
against the inner pipe wall, and pulls a volume of fluid to the surface. The advantage to
swabbing is that a large volume of fluid can be produced, until the flow stream is representative
of the true formation water chemistry. A similar method uses nitrogen injected down the drill
pipe to lift the fluids contained in the pipe. The lifting mechanism, however, can change the fluid
chemistry of samples by driving off volatiles, creating precipitates due to the lowered
temperature, and introducing water from other zones.
Downhole formation testers are somewhat similar to sidewall coring devices. A tool is run into
the well on wireline and positioned opposite a permeable formation. A suction-cup element is
forced against the borehole wall and the tool is opened, allowing formation fluid to be collected.
The tool can be configured with many small chambers for sampling several intervals, or as one
sample of about 7 gallons. The testing protocol allows detection of leakage to the borehole
environment and indicates contaminated samples. The primary drawback of this method is that
the sample may consist partly of mud filtrate that has invaded the formation during drilling.
When sampling is planned for some zones, the mud system is changed out for a polymer system
to allow representative sampling.
12-8
-------
November 2001
New MFT Tool
ParmnUltty
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Testing
FVT
Sampling
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Schlumbeger's new modular formation tester (MFT) tool takes over where the
old repeat formation tester left off. It can take multiple fluid samples, up to 15
gallons each, from multiple zones. Samples are suitable even for gas analysis,
in that a series of packers and sealing devices allow a probe to be inserted into
the borehole wall up to 20 inches deep in sandy formations. This allows virgin
water samples, free of contamination from completion fluids or mud filtrate;
preserves dissolved gases; and prevents precipitation of key solutes. What's
more exciting, the tool also can be configured to contain sensors and
instruments, so that the sample event can be interpreted in the logging truck as
a transient test and generate accurate measurements of in situ permeability.
For multiple zones in a single wireline trip!
The tool can be configured for many purposes, but for in-situ fluid sampling
from multiple zones it opens unique opportunities for the UIC permit process.
Imagine a valid water sample and in-situ permeability measurement for every
USDW in the surface casing section.
12-9
-------
November 2001
Method
Property
Application
Spontaneous
Potential (SP)
Electrochemical and
electroklnetlc
potentials
Formation water resistivity
(Rw)i shales and nonshales;
bed thickness; shallness
Open-hole
Well Logs
ELECTRICAL
Nonfocused
Electric Log
Focused
Conductivity
Log
Resistivity
Resistivity
a. Water and gas/oil satura-
tion
b. Porosity of water zones
c. R* in zones of known
poroslty
d. True resistivity of for-
mation (Rf)
e. Resistivity of Invaded
zone
a,b.c,d
Very good for estimating R.
In either freshwater or oil
base mud
Focused
Resistivity
Logs
Resistivity
a.b.c.d
Especially good for determin-
ing of thin beds
Depth of Invasion
Focused and
Nonfocused
M1crores1st1v1ty
Logs
Resistivity
Resistivity of the flushed
zone (Rxo) for calculating
pososity
Bed thickness
Ui
Transmission
Compresslonal and
shear wave
velocities
Porosity; lithology; elastic
properties, bulk and pore
compressibilities
II
as
Compresslonal and
wave attenuations
Location of fractures;
cement bond quality
-ICC
ua.
Reflection
Amplitude of
reflected waves
Location of vugs, fractures;
orientation of fractures and
bed boundaries; casing In-
soection
Most of you are familiar with these types of logs, but logging companies now
digitize the data and presentations, and can present amazing cross-plots and
solutions that used to take three hours each.
12-10
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November 2001
Open-hole
Well Logs
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a
s
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o
Method
Ganma Ray
Spectral
Ganma Ray
Gamma-Gamma
Neutron-Ganrea
Neutron-Thermal
Neutron
Neutron-Epi ther-
mal Neutron
Pulsed Neutron
Capture
Spectral Neutron
Gravity Meter
Ultra-Long Spaced
Electric Log
Nuclear Magnetism
Temperature Log
Property
Natural radioactivity
Natural radioactivity
Bulk density
Hydrogen content
Hydrogen content
Hydrogen content
Decay rate of thermal
neutrons
Induced ganma ray
spectra
Density
Resistivity
Amount of free hydro-
gen; relaxation rate
of hydrogen
Temperature
Application
Shales and nonshales; sha 11-
ness
Lithologic identification
Porosity, lithology
Porosity
Porosity; gas from liquid
Porosity; gas from liquid
Water and gas/oil saturations
revaluation of old wells
Location of hydrocarbons;
lithology
Formation density
Salt flank location
Effective porosity and
permeability of sands; poro-
sity for carbonates
Formation temperature
12-11
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November 2001
Pressure-T ransient
Testing
Provides averaged data for larger
portion of reservoir
- Build-up or draw-down
Types of tests
- Drill-stem test
- Injectivity
- Specialized (e.g., straddle-packer)
Well logs and all the other tests we have discussed provide data that is relevant only for the
near-borehole environment. Pressure transient testing allows information to be gathered
concerning the formation properties outside the wellbore, and provides averaged, effective
data for the entire reservoir, rather than from a small sample. These tests provide the
optimum basis for predicting the long-term behavior of the well, detecting changes in well
performance or reservoir conditions during operation, and analyzing the well effects during
post-closure.
Transient testing involves recording and interpreting changes in reservoir pressure induced
by pumping or injection. Typical tests record pressure build-up and falloff, or draw-down
and recovery. For interpretation, transient test analysis uses the known quantities in the
Matthews and Russell equation we discussed earlier to solve for formation variables such
as formation pressure, effective average permeability, skin, and many other injection
variables. Another objective would be to determine if significant fractures are present that
could provide non-radial injection.
The area of investigation of a single-well test is primarily a function of test duration.
During the drilling process, a drill-stem test may be performed to evaluate potential
injection or confining intervals. These tests are run for a few minutes, and provide average
effective permeability data for a radius of investigation of only a few feet away from the
borehole.
Injectivity testing is performed after the well is completed. Tests are run for a few hours
(or days, for large radii of investigation), and provide data concerning formation damage
and skin factor, permeability, storage, and compressibility, averaged over a radius of
investigation of hundreds of feet. Longer tests can evaluate the presence of flow
boundaries, changes in reservoir thickness or permeability, and other information, over a
radius of thousands of feet from the wellbore.
Specialized tests involving dual packers are used to evaluate the leakage potential of a
confining zone.
12-12
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November 2001
Objectives of
Formation Testing
Consider how much you need to know
before asking for expensive tests
Focus on real concerns
- USDW, confining zone, and AoR
- Cement
- Detailed mineralogy and water
chemistry
- Fracturing or step test
Every well is different, but every formation testing program shares a common set of
questions to answer. Obviously, for Class-1 Hazardous wells there is a high data
hurdle for the operator to leap. But aside from that, the most important question is:
how much do I need to know? Some permit writers will ask for the same extensive
tests and information for every well, just because it's allowed in the regs (to be
"considered," remember) or it's in the sample permit. But rig-time, sampling, and
analysis are very expensive, and you should focus an operator's time, money, and
attention into areas where you have real concerns. The price of coring will buy a lot
of extra cement or MITs!
In that sense, how much about the lithology do you really need to know? If logs from
the area indicate the presence of a substantial confining zone, the injectivity and
mineralogy of the injection zone are the operator's problem.
What will a 4-day pressure transient test tell you that you didn't already know at 4
hours?
Some permit writers like to see lots of fracturing tests. But before asking, consider,
for example, how an applicant can generate a significant frac with 85-horse pumps
and clear fluid.
Before requesting 150-species mass-spec analyses of the formation fluids, consider
that if the well plugs due to reaction products, it is entirely the permittee's problem,
and not related to the environment unless he willfully exceeds his maximum injection
pressure (but that's a different issue).
Focus on the things that concern you, and spare no expense there, but be more
judicious about requesting "technical window-dressing."
12-13
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November 2001
Permit Review
Essentials
USDW stratigraphy and chemistry
- Gamma, resistivity and SP logs
- Verify or sample lowermost USDW
Injection and confining zones
- Stratigraphy: add density/neutron?
- Basic mineralogy and properties: sidewall
cores with complete analysis
Keep in mind that the permit writer does not initiate the formation testing program - the
operator submits it with the permit application. However, if extensive testing is not
required for the particular site, you might consider trading off some of the tests that are
not required for better cement logs and more frequent MIT.
Consider these the minimums, but remember that for Class D and II you will probably
see data from other wells in the project. A prudent permit writer should want to know
the following from a formation testing program:
* Detailed stratigraphy of the USDW section. Gamma, resistivity and SP are
sufficient in most cases, unless limestone is present (in which case, you should add
a neutron log). Given the MFT tool and other new technologies, require proof of
the lowermost USDW and a sample from the uppermost non-USDW aquifer. (It is
usually not that expensive because the applicant must clean up the surface casing
hole prior to cementing.) The surface casing should be set at least 50 feet below
10,000 TDS (100 feet is used in most States for Class I wells).
~ Detailed stratigraphy of the confining and injection zones. You can use the same
logs as surface casing, but add a density/neutron combination to allow cross-plots.
The applicant should provide representative sidewall cores of both zones (NTE
40), with mineralogical analysis, porosity measurement, and permeability estimate
for water.
12-14
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November 2001
Permit Review
Essentials
Detailed driller's and activity logs
Short-term injection test
- Initial BHP and skin
- Analysis for Kh
Detailed driller's log and log of all rig activities, signed by the engineer
in charge and by the operator.
Short-term injection test (with bhp and skin) to confirm allowable
injection pressure.
If the operator submits (or you require) these basics, you can perform an
accurate review on any well except I-H. In the case of Class II or III,
you can use representative data from nearby wells, but for Class I or
Class II-D commercial use original data.
12-15
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November 2001
Lesson 13
Stimulation Program
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DRINKING
WATER
ACADEMY
Attachment J concerns the proposed well stimulation program. Stimulation of
a well involves improving injectivity by either chemical or physical means.
13-1
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November 2001
Chemical Stimulation
Salts
- Potassium chloride (KCI)
Acid
- Hydrochloric (HCI)
- Hydrofluoric (HF)
Organic solvents
- Methanol or detergents
One widespread method of stimulation utilizes potassium or ammonium
chloride (KCI) brines. KCI has been found to stabilize some types of clay
particles by saturating their ion exchange sites. Although this technique does
not immediately improve permeability, the stabilized clays will shed fewer
fine particles that tend to migrate and plug pore throats, which reduces
permeability.
Chemical stimulation usually involves the injection of chemicals that will
dissolve either formation minerals or waste reaction products in an effort to
improve permeability. The most common stimulation fluid is 15 percent
hydrochloric acid (HCI), which dissolves carbonate cements and precipitates.
Another common acid agent is hydrofluoric acid (HF), which dissolves most
types of clay particles. Sometimes these acids are used in combination. In
either case, the enhancement of permeability can approach 100 percent in a
virgin injection zone or over 500 percent in a zone that has been partially
plugged by precipitates.
A less-common stimulation chemical involves organic solvents such as
methanol. These chemicals are used mostly in Class II wells to flush away a
partial oil saturation in the pores, but are also used in Class I wells to dissolve
or mobilize organic polymers that form as reaction products with organic
wastes.
13-2
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November 2001
Design Criteria
Prevent corrosion
- Inhibitors reduce steel corrosion (but not
cement)
Reduce harmful side-effects
- Iron precipitates, clay disaggregation
Depth of beneficial effects
- Sizing and staging of treatment chemicals
- Respect maximum injection pressure
The primary design criterion of chemical stimulation is to dissolve the bad
things without dissolving the good things. For example, although HC1 will
readily dissolve carbonate cements and precipitates, it will also dissolve
tubing, packer, and most types of cement. To prevent corrosion of tubular
goods, acids used for downhole stimulation are almost always treated with
inhibitors. These chemicals inhibit (but do not eliminate) corrosion of the
steel components of the well. Inhibitors do not prevent corrosion of the
cement, however.
In addition to inhibitors, other components of the acid program might include
surfactants to mobilize oil, chelation agents to prevent iron precipitation, and
polymers to prevent clay disaggregation.
A small-volume treatment might only improve injectivity in the skin area of
the wellbore, which extends only a few inches into the injection zone. These
treatments typically utilize up to 50 barrels of acid to remove residual drilling
mud and improve skin efficiency. Conversely, many Class I wells utilize
complex, multi-stage acid treatment that are intended to penetrate hundreds of
feet into the injection zone. These treatments typically utilize up to 15,000
barrels of acid, and alternate injection with other acids and treatment
chemicals. For example, a recent large-scale acid treatment was designed to
utilize six alternating stages of 1500 barrels of HF acid, followed by 5,000
barrels of HC1 and 3,000 barrels of KC1.
Always make sure that the operator is aware that maximum injection pressure
limitations also apply to chemical stimulation programs.
13-3
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November 2001
Physical Stimulation
Swabbing
- Surging well using cups on tubing
Hydraulic fracturing
- Extreme pressure, specialized fluids, and
proppants
Shooting
Physical stimulation utilizes mechanical methods to improve injectivity. The
most common method is "swabbing," where injectivity is improved by moving
the fluid column up and down by means of a series of cups mounted on tubing.
This provides a surging action that dislodges fine particles and mud which can
plug pore throats at the injection face.
Another common method involves hydraulic fracturing, used primarily in
Class II wells. In a previous section, we discussed hydraulic fracture gradient
and the properties of fractures. Hydraulic fracturing for well stimulation
involves thousands of barrels (or hundreds of thousands barrels!) of
specialized fracturing fluids, injected at high rates and extreme pressure using
specialized treatment units, and creates fractures that may be hundreds of feet
both in length and/or height above the perforations. When the fracturing
pressure is released, the fracture will close. To provide a permeable pathway
within the fracture, proppants (glass or plastic beads) are emplaced in the
fracture to keep it open.
A less-common method of wellbore stimulation involves shooting the well
using explosives, or, most recently, surplus Russian and American solid-fuel
rocket motors. Explosives can cause catastrophic well failures and this
method is seldom used anymore, but was once popular before hydraulic
fracturing became more economical. The disarmament treaties of the last 15
years have made available thousands of solid-fuel rocket motors. This method
provides a slower, controlled, burn that can create horizontal fractures over
100 feet from the wellbore.
13-4
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November 2001
Fracturing Design Criteria
Require detailed fracture design
Ensure confining zone integrity
- Observe fracture limit for confining zone
Ensure USDW integrity
Swabbing is a routine drilling practice and not usually specified as a stimulation treatment in
Attachment J. Shooting can cause damage to the cement, and should not be allowed for an
injection well under any circumstances. The only mechanical stimulation method we are concerned
with is hydraulic fracturing. UIC regs usually prohibit fracturing the injection zone, so this
practice is usually limited to Class II wells.
The fracture treatment is designed by the service company that will perform the treatment. The
fracture program may have been designed using typical oil production criteria, rather than UIC
regulatory criteria and specific permit limitations. Be sure to look for a detailed fracture design in
the permit application. Always ask for a detailed job design, and caution the operator about the
prohibition against fracturing the confining zone (Class II).
The primary design objective of a fracture treatment is to ensure that the fracture will not break out
of the target zone by breaching the confining zone. Preventing break-out is achieved by having
knowledge of the fracture gradient of the confining zone rocks, and limiting the injection pressure
during fracturing to respect that gradient. This knowledge could be obtained by the service
company in other frac jobs, or testing or sampling performed in the subject well. Other than
pressure limitations, there are no other methods to prevent fracturing the confining zone or to
detect breaching after the fracture treatment.
However, you should recognize that under normal stimulation conditions, it is highly unlikely that
a properly designed fracture treatment would fully penetrate a clay confining zone of any thickness
over a few feet.
The highest hydraulic fracture ever created using non-slurry fluids reached only 600 feet above the
perforations. Unless your USDW is located within 600 vertical feet of the injection zone, there
should be no worry about direct or secondary effects. In shallow injection zones (or production
zones such as for coal-bed methane), you should be aware that fracturing fluids can contaminate
USDWs and that the connection between the injection zone and USDW can provide a direct
pathway for contamination.
The secondary design objective is to ensure that injectivity improvements actually support a
proposed maximum injection pressure limitation. Make sure that a short injectivity test is also
included to document the improved injection rate (or lower injection pressure for the old rate).
13-5
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November 2001
Too Much Stimulation?
Post-construction acid jobs improve
injectivity
- Dissolve precipitates and solids
Acid jobs can also:
- Dissolve cement in AoR
- Create channels along borehole
- Cause harmful reactions
- Dissolve confining zone
We can all use a little stimulation! But just like the human kind, too much
stimulation of an injection well can be a bad thing. Most wells are stimulated
during construction, but stimulation can also be performed to remedy
injectivity problems during operation. There are permit records for Class I
wells where the operator has stimulated his well twice a month for the life of
the well, due to the formation of precipitates. Acid jobs are no substitute for
proper preventive measures to assure compatibility between wastes and
formation fluids.
First, most acid programs will readily attack some types of cements, both in
the injection well and for offset wells in the AoR. Second, the repeated use of
acid can create solution channels in the interface between the cement sheath
and borehole, not all of which can be seen by a RAT. Third, unspent acid may
cause harmful reactions with formation rocks, such as when excess gas is
created (which can migrate to the wellbore when the well is shut in for
workovers) or when organic wastes in contact with acids form permanent
polymers in the pores. Most important, the formation of new, high-
permeability flow channels is not a homogeneous process, and channels can
grow vertically as well as horizontally. Acids can be delivered to and also
dissolve the materials of the confining zone.
In reviewing a permit application, make clear to an operator that post-
construction stimulation jobs must be approved in advance, and for Class I
wells be sure to ask for detailed program specifications.
13-6
-------
November 2001
Review Essentials
Need or reason for stimulation
Objectives and methods
Stimulation chemicals
Program to prevent
- Corrosion
- Cement dissolution
- Harmful effects to injection or confining
zone
Basically, the operator should present the reason for stimulation, the objectives
and methods he proposes, and the chemicals to be employed. The operator
will propose the program he thinks he needs, but you should require that he
justify the need for stimulation and that he define the steps he will take to
prevent well damage or harmful effects.
You may also want to add a permit condition that he notify you prior to
performing stimulation during operation.
13-7
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November 2001
Lesson 14
Proposed
Operating Data
Attachment H of the permit application provides information on the permit
applicant's proposed operating data.
14-1
-------
Section Outline
Regulatory requirements
Performance standard
Components of injection pressure
Exercise: calculate permit injection pressure
Shorthand method
Calculate permit injection rate and volume
Monitoring injected waste
-------
November 2001
Attachment H
Average and maximum daily rates and
volume of the fluids to be injected
Average and maximum injection
pressure
Nature of annulus fluid
The instructions for Attachment H require that supporting data for the
following values be included in the permit application:
~ Average and maximum daily rates and volume of the fluids to be
injected;
* Average and maximum injection pressure; and
> Nature of annulus fluid.
The key relationship to injection rate and volume is the radius of the Area of
Review (AoR). That is, for any given injection zone, higher rate (and
therefore, higher pressure and volume) will increase the radius of the AoR. As
we will see in a later section, the primary method of corrective action is a
restriction of injection rate and pressure, which can reduce the radius of the
AoR to accommodate a problem well, for example.
14-3
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November 2001
Attachment H
Class I wells
- Source of injection fluids
-Analysis of the chemical, physical,
radiological and biological characteristics,
including density and corrosiveness
Class II wells
- Source of the injection fluid
- Analysis of the physical and chemical
characteristics
Attachment H also should contain data concerning the nature and source of the
injectate. These requirements vary by well class.
For Class I wells, the permit application should identify the source of injection
fluids and provide the results of an analysis of the chemical, physical,
radiological and biological characteristics, including density and
corrosiveness.
For Class II wells, the applicant should identify the source of injection fluids
and provide the results of an analysis of the physical and chemical
characteristics of the injection fluid.
14-4
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November 2001
Attachment H
Class III wells
- Qualitative analysis and ranges in
concentrations of all constituents
- If the information is proprietary, maximum
concentrations only may be submitted, but
all records must be retained
For Class III wells, the owner/operator should provide a qualitative analysis
and ranges in concentrations of all constituents of injected fluids. If the
information is proprietary, maximum concentrations only may be submitted,
but all records must be retained.
14-5
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November 2001
Performance Standard
Classes I and III
Pressure in the injection zone does not
- Initiate new fractures or propagate existing
fractures in the injection zone or confining
zone
- Cause movement of injection or formation
fluids into USDW
The overriding performance standards for injection pressure are contained in
40 CFR 146.13 (for Class I) and 146.33 (for Class III).
For Classes I and III, the standard requires that except during stimulation,
pressure in the injection zone does not initiate new fractures or propagate
existing fractures in the injection zone or confining zones or cause movement
of injection or formation fluids into USDW. As we discussed in the AoR
section, the pathways for communication with USDWs are natural faults and
fractures, induced hydraulic fractures, and incomplete or faulty construction,
cementing, or plugging of offset wells.
Note carefully that the regulations include the harmful effects to USDWs not
only of wastes, but also the native formation fluids (which are usually high-
TDS brines).
14-6
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November 2001
Performance Standard
Class II
Injection pressure at the wellhead shall
not exceed a maximum which shall be
calculated so as to assure that the
pressure during injection does not
initiate new fractures or propagate
existing fractures in the confining zone
adjacent to the USDWs.
The standard for Class II wells is not nearly as clear. The regulation at 146.23
reads: "Injection pressure at the wellhead shall not exceed a maximum which shall
be calculated so as to assure that the pressure during injection does not initiate new
fractures or propagate existing fractures in the confining zone adjacent to the
USDWs."
First, 40 CFR 146.23 specifies "injection pressure at the wellhead," rather than the
"pressure in the injection zone" used for Class I. This usually limits measurements
to less meaningful wellhead gauge pressure rather than bottom-hole pressure or
injectivity tests. Gauge pressure neglects the considerable effects of fluid density
and skin.
Second, "calculations" are specified. Pressure calculations without the benefit of
injectivity-derived transmissivity are almost meaningless.
Third, and most important, the Class II standard locates the no-fracture prohibition
at the last confining zone before the USDW, rather than the zone immediately
above the injection zone. In a typical Class II well of over 2,500 feet depth (and
assuming 500 feet to the base of the USDW), it would be a scientific impossibility
to vertically fracture that much intervening rock using even conventional fracture-
job technology, let alone injection pressure.
Class II pressure or volume limitations generally do not need to be specified in the
permit, unless there are serious AoR issues like faulty plugging or cementing.
However, in the case of AoR issues, the regulations also add the standard fluid-
movement prohibition: "In no case shall injection pressure cause the movement of
injection or formation fluids into an underground source of drinking water."
14-7
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November 2001
Fluid Injection
Fluid is injected into saturated pores
- Native water is displaced (open system)
or
- Native water is compressed and system
expands (closed system)
Injection reservoirs should be closed
systems
The resistance to displacement is, in a Newtonian sense, the reservoir pushing
back. We mentioned that subsurface injection takes place into a "full"
reservoir, that is, the pores are already saturated with native saline water.
During injection, space is created for the injection fluid by two possible
mechanisms:
* The receiving formation is part of an open system, and native water is
displaced elsewhere; or
* The reservoir is a closed system, and space is created by compressing the
native water and aquifer skeleton, as well as expanding the system
(similar to blowing air into a balloon).
All injection reservoirs are (or should be) closed systems. Although water is
generally considered a non-compressible fluid, some slight compression does
occur (3.1 x 10"6 lb/in2 at subsurface temperature). Similarly, the "elasticity"
of the rocks allows very slight compression of the reservoir rock skeleton
and/or expansion of the system, on the order of 3.2 x 10"6 lb/in2 for typical
sand injection reservoirs featuring 30 percent porosity. In simple terms, every
psi of injection pressure (in excess of existing formation pressure) creates
0.0000065 square inch of space for injectate. This may be a very small
amount, but when applied to the immense volume and area of a reservoir
system, large volumes of fluid storage may be created by injection pressure.
Oilfield applications refer to this phenomenon as the "compressibility factor,"
whereas in ground water usage it is called the "storage coefficient."
14-8
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November 2001
Components of
Injection Pressure
Existing lithostatic and hydrostatic
pressure
Darcy friction losses
Displacement resistance
In order to understand the principles and practices involved in permitting and
area of review analysis, we must first examine the mechanics of subsurface
injection. Injection implies the introduction of fluids into the porous network
of a rock or sediment layer. Fluid injected into a subsurface reservoir does not
flow into empty voids; the injection process must displace the fluids that are
already there, usually saline water. The pressure necessary to effect this
displacement consists of three components: the existing formation pressure;
the Darcian head loss that must be overcome when pushing fluid into a porous,
granular medium; and the resistance to displacement.
Existing formation pressure can be caused by a combination of rock
overburden, the weight of the saturated fluid-column (hydrostatic pressure),
the temperature at depth, the presence of gas, and chemical reactions within
the system. While the existing subsurface pressure varies considerably among
geologic environments, almost all injection reservoirs approach nominal
lithostatic conditions, that is, containing less than 1 psi per foot of depth.
The friction losses that must be overcome are a function of permeability, and
are described by Darcy's Law. In its simplest form, Darcy's Law shows that
injection pressure is a function of injection rate and formation transmissivity
(i.e., thickness times permeability). For a given injection rate, a highly
transmissive formation will present lower friction losses than will a less-
transmissive formation. That is, the lower the transmissivity the higher the
injection pressure required for emplacement at a given rate. The effective
porosity of the rock affects the amount of fluid that can be emplaced, whereas
the effective permeability of the rock affects the rate at which fluids may be
emplaced.
14-9
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November 2001
Delta p (A p)
Matthews and Russell (1967) show that
pressure increase is greatest at the well, but
decreases dramatically (log) with distance
Ap= 162.6 Qu flog kt -3.23]
k b nCr2
The injection of fluid into a subsurface reservoir is accomplished by increasing pressure within the system.
The pressure increase is greatest at the wellbore and decreases away from the wellbore (i.e., into the
injection formation). The effect is the mathematical opposite of the cone of depression in a pumping well.
The cone of impression created by an injection well reflects highest pressure at the well, decreasing
logarithmically with distance from the well. The amount of injection pressure required for emplacement
and the distance to which it extends into the formation depends on the properties of the injection fluid and
the formation, the rate of fluid injection, and the length of time the injection has been going on.
The most common mathematical expression for a single well injecting to an infinite, homogenous and
isotropic, non-leaking aquifer was developed by Matthews and Russell (1967).
delta p (the increase in pressure) = 162.6 Q(n)/k b * [ (log k t /
-------
November 2001
Bottom Hole Pressure
Bottom-hole pressure during injection
(BHPI) consists of
- A p (injection pressure at some Q) plus
- Weight of the fluid column
Height of fluid x density, e.g.,
4000 ft @ .4416 psi/ft = 1766 psi
BHPI also expressed as gradient (psi/ft)
E.g., 1940 psi 4000 ft. = 0.485 psi/ft
We have previously considered the minimum pressure necessary for
emplacement of fluids into the reservoir. It is also important to consider this
pressure as the bottom hole pressure, or BHP, which also includes the weight
of the fluid column. The components of BHPI include delta-p (the injection
pressure), the weight of the fluid column in the tubing, and certain friction
losses at the injection face that we call "skin" losses. Unless you have a
documented test of skin losses, it's best to ignore them for most BHPI
calculations.
The weight of the fluid column equals the height of the fluid column times the
density gradient of the fluid. Charts and conversion tables allow you to
convert units to density gradient as psi per foot using traditional measurements
such as grams per cc, pounds per gallon, specific gravity, or even TDS
concentration.
Most analysts also express BHPI as a BHPI gradient, which is BHPI divided
by the depth of the injection zone. The BHPI gradient for this example would
be 1940 psi divided by 4000 feet, or 0.485 psi per foot.
BHP can be estimated as we have done, or directly measured in the field using
a pressure sensor. You could also work at this backwards in the field if you
needed to, by observing the operating well-head pressure. The problem with
this method is that WHIP (well-head injection pressure, also called SIP for
surface injection pressure) also includes friction losses in the tubing and skin
losses downhole. In some Class I wells, these losses can total hundreds of psi,
because of pore-plugging by chemical waste reactions.
14-11
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November 2001
Example: Allowable
Injection Pressure
Well depth: 4000 feet
Thickness of interval (b): 50 feet
Porosity (O): 30 percent
Permeability (k): 400 md
Injection rate (Q) = 1700 bbl/day
Viscosity (|j) = 0.90 centipoise
Duration of injection (t) = 87,600 hours
Effective well radius (r) = .292 ft
Reservoir storage (C) = 6.5 x 10*6 psr1
Well tubing = 2.375"
Injectate specific gravity = 1.02
We're going to consider two methods of calculating allowable injection pressure. The
first method considers eveiy possible variable so that you can see how it all fits together,
and so you can use all or parts of it in the future. For now, however, we will just skim
over it and concentrate here on a shorthand version.
Allowable injection pressure for a well is considered at the surface. An analysis of
wellhead injection pressure (WHIP) must consider not only the injection pressure at the
formation face (Matthews and Russell), but also friction loss in the tubulars of the well
and the weight of the fluid column in the tubing.
Consider this problem: determine the allowable injection pressure for the following well.
Dep
h to injection interval: -4000 feet
Thickness of interval (b): 50 feet (measured or estimated from logs)
Porosity (O): 30 percent (measured or estimated from logs)
Permeability (k): 400 md (measured or estimated from logs)
Injection rate (Q) = 1700 bbl/day
Viscosity (n) = 0.90 centipoise @ 100ฐ (measured or estimated from chart)
Duration of injection (t) = 10 years = 87,600 hours (life of permit)
Effective well radius (r) = .292 ft (casing diameter is 7 inches)
Reservoir compressibility or "storage" (C) = 6.5 x 10^ psr1 (estimated from chart)
Well tubing = 2.375" steel
Injectate specific gravity = 1.02 (.44 psi/ft, from conversion chart)
Existing formation pressure: 1795 psig @ 4000 feet (measured)
14-12
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November 2001
Step 1: Injection
Pressure
A p = (162.6) (1700) (.90) x
(400) (50)
[ log (400) (87600) 3.23]
(.30) (.90) (.0000065) (.292)2
A p = 138.6 psi at the injection face
At the injection face (r = casing radius) and considering the lifetime of the
well (10 years), we can calculate the necessary injection pressure:
A p (psi) = (162.6') (1700) (.90) x \ log (400) (87600) - 3.23 1
(400) (50) (.30) (.90) (.0000065) (.292)2
A p = 138.6 psi at the face of the injection interval
This is the injection pressure required after 10 years' service that is necessary
to emplace 1700 bbl per day (about 50 gpm) into the example formation.
14-13
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November 2001
Step 2:
Friction Loss
Additional pumping
pressure is needed to
overcome frictional
losses in the tubing
(34 psi)
FLOW RATE BPM
(O 10 100
To the injection pressure we must add friction losses that are encountered in
the well tubulars and at the entry to the injection formation.
Friction losses are a function of tubing size and length, flow rate, injectate
viscosity, and the smoothness of the interior of the tubing. Friction losses are
usually provided by the manufacturer of the tubulars, or can be calculated or
estimated from a standard chart. The friction losses of the specified 2-3/8 inch
tubing are 0.00839 psi/ft, at 50 gpm, as estimated from this standard chart.
The additional WHIP that accounts for friction in tubing is about 34 psi.
Now, that's not very much pressure, and may not even seem worth the effort.
However, there is lots of used 2-3/8 inch tubing lying around most oil leases,
and a lot of operators will use it by default. In other words, a higher-rated
pump head is a lot cheaper than a new 3-1/2 inch tubing string, and the friction
losses in many Class II wells can be 150 psig or more.
14-14
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November 2001
Friction Loss at
Formation Face
Friction losses also at the formation
face ("skin") (35psi)
Ap + friction + skin = 207.6 psig @
wellhead (+ formation pressure)
Friction losses at the formation face are due to perforation restrictions and
permeability reductions from plugging from drilling mud, chemical precipitates, or
unfiltered solids in the waste stream. This phenomenon is known as skin, skin
damage, or skin effect in the oil industry and as well losses in the water well industry.
Whatever you call it, it covers a wide range of processes that can reduce effective
permeability near the wellbore. In extreme cases, the formation permeability can be
severely reduced, sometimes permanently, by plugging from precipitates or solids.
Skin effect is tested and measured by a variety of methods that involve an injection
test and some form of A p analysis.
The net effect of skin is to reduce well efficiency and increase pumping pressure. We
can express skin as a percentage increase in A p. Completions using perforations
commonly exhibit skin on the order of 15 to 35 percent, whereas gravel pack
completions are more efficient and feature skin as low as 2 percent. The perforated
completion in the example features 25 percent skin effect, so an additional 35 psig is
required for emplacement (138.6 x .25).
In the subject well, a total of 207.6 psig WHIP is necessary to emplace 50 gpm of
injectate into the subject formation (A p + friction). Note that this value is in addition
to the existing formation pressure in the injection interval (specified as 1795 psig).
For the example well, 2003 psig will be necessary to emplace the design injection rate
of 50 gpm; that is, the combination of A p (138.6) and friction losses (34 + 35 psig)
added to the existing formation pressure of 1795 psig.
Not all of the 2003 psig necessary for injection must come from surface pumps; the
weight of the fluid column in tubing supplies kinetic energy at the formation face. By
calculating this kinetic energy, we can determine the actual operating pressure at the
wellhead (WHIP).
14-15
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November 2001
Bottom Hole Pressure
Static bottom-hole pressure (BHP)
- Weight of the fluid column
Height of fluid x density, e.g.,
4000 ft @ .4416 psi/ft = 1766 psi
BHP also expressed as gradient (psi/ft)
E.g., 1766 psi - 4000 ft. = .4416 psi/ft
The weight of the fluid column in tubing is a function of injectate density,
usually expressed as grams per cc. Injectate density is either directly
measured in the field or laboratory, or estimated using total dissolved solids
(TDS) data. Density is usually reported as "specific gravity" (SG), a
comparison to the density of distilled water at room temperature. The specific
gravity of the example injectate was measured as 1.02, which corresponds to a
weight of 0.4416 psi per foot (multiply 1.02 x .433, the weight gradient of
distilled water). The weight of the fluid column in the example well would be
1766 psi (4000 ft @ .4416 psi/ft).
Most analysts also express BHPI as a BHPI gradient, which is BHP divided by
the depth of the injection zone. The BHP gradient for this example would be
1766 psi divided by 4000 feet, or 0.4416 psi per foot.
BHP can be estimated as we have done, or directly measured in the field using
a pressure sensor. You could also work at this 'backwards' in the field if you
needed to, by observing the operating well-head pressure. The problem with
this method is that WHIP (well-head injection pressure, also called SIP for
surface injection pressure) also includes friction losses in the tubing and skin
losses downhole. Remember that in some Class I and II wells, these losses can
total hundreds of psi.
14-16
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November 2001
Step 3: Operating
WHIP
Emplacement = A p + friction/skin (69
psig) + existing pressure (1795 psig) =
2003 psig
Fluid weight using specific gravity
-1.02 S.G. = .4416 psi/ft = 1766 psig
WHIP = emplacement pressure - fluid
weight = 237 psig
The actual operating wellhead injection pressure would be the emplacement
pressure (2003 psig) minus the kinetic energy of the fluid column (1766 psig),
or 237 psig WHIP. This isn't the maximum allowable WHIP, but rather the
gauge pressure the operator will experience at his requested injection rate.
Note that if the skin damage increases, for a given injection rate the WHIP will
increase. If the specific gravity of the waste stream increases (more saline
wastes, for example), the WHIP will decrease.
14-17
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November 2001
Step 4a: Bottom Hole
Pressure (Injection)
Bottom-hole pressure during injection
(BHPI) consists of
-A p (138.6 psig)
- Skin effect (35 psig) plus
-Weight of the fluid column (1766 psi)
(4000 ft @ .4416 psi/ft = 1766 psi)
BHPI = 1940 psig, or .485 psi/ft
-1940 psi - 4000 ft = 0.485 psi/ft
Here in another way of looking at BHP. This step involves analysis of the
operating bottom-hole pressure (BHPI). The components of BHPI include Ap,
skin losses, and the weight of the fluid column in the tubing. Note that friction
losses in the tubing are expended in travel downhole, and should not be
included in BHPI calculations. During operation, the BHPI of the example
well would be 1940 psig (including fluid column weight, A p, and skin).
Another way to express BHPI is as a BHPI gradient, which is BHPI divided by
the depth of the injection zone. The BHPI gradient for the well would be 1940
psi divided by 4000 feet, or 0.485 psi per foot.
14-18
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November 2001
Fracture Gradient
Injection pressure can not exceed the
fracture pressure
- Injection zone (Class I)
- Upper confining zone (Class II)
Fracture pressure is unique for every
formation and time
- .65 to >1 psi/ft
The ultimate limit for allowable injection pressure in Class I and III wells is
the fracturing pressure. UIC regulations prohibit Class I wells from exceeding
the fracture pressure of the rocks of the injection zone, whereas Class II wells
must not exceed the fracture pressure of the uppermost confining zone.
Hydro-fracture pressure is unique for every formation, and is related to the
formation's depth, elastic modulus, overburden and fluid pressure, geologic
age, and the sand/shale ratio. The fracture pressure can change with
increasing (or decreasing) formation pressure, due to injection or production.
In other words, a fracture pressure measured early in the life of a well may not
be valid after continuous injection for a number of years. Hydro-fracture
pressure information for a given area can be found in the literature, measured
directly by a drill-stem or step test, or estimated using several possible
methods.
Fracture pressure is usually expressed as the fracture gradient, in psi per foot,
by dividing the fracture pressure by the well depth. This allows test results or
regulatory standards to be applied to different wells. Fracture gradients can
vary from 0.65 psi per foot for poorly-consolidated sand zones, to over 1 psi
per foot in the hard rocks of the midcontinent and Appalachian regions.
14-19
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November 2001
Fracture Pressure
Finding fracture pressure
- Published data (oil and gas industry)
- Measured downhole using injection test
- Estimated
* Fracture pressure information can be found in oil and gas industry publications
or the scientific literature. When considering published data, it is important to
remember that injection wells usually operate in an environment markedly
different from the oil wells that are the usual subjects of published research.
Injection well use is typically at shallower depth (less than 7000 feet), in
normally pressured, water-saturated formations of high permeability and
porosity, in areas free of active faulting and tectonic activity. Published values
for oilfield fracture gradients are usually derived from deep production zones
and overstate the true fracture gradient in shallower formations.
Fracture gradients can also be measured, using either a specific test in the
subject well, or using industry or published data derived from fracturing
procedures.
14-20
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November 2001
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In a step test, injection pressure is increased until the formation breaks down. These tests are usually
required for a Class I Hazardous permit application, especially in Region 5. For other wells, the most
common information available is from a nearby hydraulic fracturing procedure. Data from these
procedures is usually available from service companies who perform the procedures (such as
Halliburton) or from State agencies (given to operators to allow planning for blowouts). In either
case, a step test and fracture log provide the same information, and the terms and solutions are the
same. This example is a log of a fracture procedure. Ignore the dotted line, but concentrate your
attention on the down-hole pressure.
P-zero is the initial hydrostatic pressure in the formation plus the weight of the fluid column (BHP).
Injection pressure is increased until "breakover" is observed, labeled "Pc" on most logs. Once the
fracture pressure has been exceeded and a flowpath is created, continued injection into the fracture is
easier as the fracture is being extended. This phenomenon is labeled "Pp" and is known as flowing
pressure. Pf is especially significant, in that once injection pressure has exceeded a threshold fracture-
pressure value, subsequent injection into the fracture requires significantly lower pressure. Depending
on the elastic properties of the formation, the initial fractures may never heal, and the effective
fracture gradient is now lowered. In semi-consolidated formations, however, fractures can heal, and
the original breakdown pressure must again be exceeded for subsequent fractures.
When pumping is stopped, the well stabilizes at a value known as the "instantaneous shut-in
pressure," or ISIP, labeled Ps on this slide. This pressure is considered by most researchers to be
equal to the least principal earth stress in the vicinity of the well.
Many fracture logs are recorded as surface pressure (always check the log header or P-zero first).
For surface-recorded logs, we would need to add the weight of the injection fluid column to ISIP to
get the true fracture pressure for the new injection well. This log is recorded as down-hole pressure,
but many fracture jobs use light fluids (such as methanol) or the fluid level is not to surface when P-
zero is measured. So for bottom-hole fracture logs, subtract P-zero from log-ISIP for a true ISIP
pressure, and then add the weight of the proposed injection fluid column.
Because of the Pf phenomenon and the fact that some fractures never heal completely, many
regulators avoid fracture testing every well, and for setting permit limitations rely instead on tests of
similar wells or on estimates of the fracture gradient.
14-21
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November 2001
Estimating Fracture
Gradient
Three principal stresses
- Overburden
-Tensile
- Compressive
Hydro-fracture pressure for a given formation can be measured directly by a
fracture log or step test, or can be estimated using several methods. Most
estimation methods require specialized tests of rock properties (such as
Young's Modulus), or may be valid only for certain depths or geologic
provinces. It is possible, however, to develop a simple estimation logic using
published data and the method of Hubbert and Willis.
There are three principal stresses acting at any point in the earth's crust:
vertical overburden stress, and horizontal tensile and compressive stresses.
The tensile and compressive stresses are, as opposites, oriented perpendicular
to each other. A practical way to express that relationship is to measure their
effects at any point in the subsurface: we can define vertical stress as the rock
overburden pushing down, and describe the relationship of tensile and
compressive forces as the two, perpendicular directions of least and most
horizontal stress.
14-22
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November 2001
Hubbert and Willis (1972)
Fracture orientation perpendicular to
least principal stress
Fracture gradient is usually from 0.64 to
0.73 psi/ft in typical oil sands
More for shale-rich, hard rock, or thrust
areas (up to 1.0 psi/ft)
Hubbert and Willis (1972) are most famous for proving that fracture
orientation is perpendicular to least principal stress. (Remember that hydraulic
fractures are planar and are oriented in a particular direction.) When the least
principal stress is vertical, that is, the overburden is small, then fracture
orientation will be horizontal. That is the usual case for shallow wells, usually
less than 1,000 feet in depth. When the least principal stress is horizontal,
fracture orientation will be vertical. That is the case for deeper wells.
The method of Hubbert and Willis also postulates that the fracture pressure
gradient is dependent on the overburden, the pore-pressure gradient, and the
rock frame stress. In typical oil-exploration basins that feature normal
faulting, they found that the least stress is probably horizontal and from 1/2 to
2/3 the effective pressure of the overburden. Using these assumptions and
data for overburden in many regions, Hubbert and Willis found that the
fracture pressure gradient probably ranges from 0.64 to 0.73 psi per foot.
Published data from other literature sources generally agree with the postulate
of Hubbert and Willis (if we consider the geologic conditions typical of
injection wells). Test data in the field, however, has shown fracture gradients
approaching 0.85 psi/ft for shale-rich sections, and in hard-rock environments
that feature thrust faulting, gradients can approach 1.0.
14-23
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November 2001
Step 4b: Calculate
Permit WHIP
Operating WHIP = 237 psi
Allowable WHIP (for 1.02 S.G.)= 654
psig
- Fracture pressure (2560 psi using .64 psi/ft
gradient @ 4,000 feet)
-Minus BHPI (1940 psi)
- Plus tubing friction (34 psi)
The WHIP the operator will experience at his requested injection rate is 237
psig. Most Regions and States calculate the maximum allowable WHIP using
the fracture gradient as an upper limit.
Now that we have researched, measured, or estimated the fracture gradient, we
can calculate the allowable injection pressure as a permit limitation.
Calculating the allowable injection pressure for the example well involves
considering the range between the operating WHIP (237 psig, the minimum
WHIP necessary for injection) and a WHIP related to the estimated fracture
gradient. Using the Hubbert and Willis method, the BHP fracture pressure
may be estimated as from 2560 psi (.64) to 2920 psi (.73), or more in some
areas. If specific test data are not available, using the 0.64 psi/ft gradient
provides a margin of safety when considering allowable pressure. Some States
and Regions may use a different standard.
Regardless of whether the fracture gradient is measured or estimated, EPA
permits injection pressure limitations as surface injection pressure (WHIP).
To calculate maximum allowable WHIP, multiply the fracture gradient by
depth (fracture pressure), subtract operating BHP, and add tubing friction loss.
For the example well: .64 psi/ft x 4000 ft = 2560 psi, minus 1940 psi (BHP),
plus 34 psi (friction in tubing) = 654 psi maximum WHIP.
Remember that this WHIP calculation is only valid for the specified 1.02
specific gravity. Most permit limitations also specify an allowable range for
the gravity of the injectate.
14-24
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November 2001
Shorthand Version
Maximum WHIP = fracture pressure -
BHP
- Injection rate not considered
For example:
- .64 x 4000 = 2560 fracture pressure
-.4416x4000 = 1766 BHP
- 2560 - 1766 = 794 psig maximum WHIP
Now that you understand how it all fits together, here is a shorthand method of
determining allowable WHIP.
First, measure, estimate, or find an applicable fracture gradient from State or
industry data, and multiply by the well depth. Many DI and State programs
(especially Class II)use a sep rate test of the injection zone to establish the
maximum injection pressure. In this case, we estimated the fracture gradient
in this sandy zone as .64 psi per foot. Multiplied by depth we get .64 times
4000 or 2560 psi fracture initiation pressure.
Second, estimate his static BHP by multiplying depth by fluid gradient.
Remember, you can use specific gravity of the injectate times .433. In this
case the SG was 1.02, or .4416 psi/ft, times 4000 equals 1766 psi BHP. If you
subtract the two, you have a rough idea of allowable injection pressure. In this
case, 2560 - 1766 equals 794 psi WHIP. In essence, we are using the friction
losses in the tubing and at the injection face as our safety factor.
Recall that using the long method calculates a maximum WHIP as 654 psi.
The primary difference is that in the long method, we are specifying the
maximum WHIP in relation to the permit applicant's requested maximum
injection rate. In the short version, the injection rate is not considered.
14-25
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November 2001
Maximum Allowable
Infection Rate
Maximum rate usually specified by
applicant
- Long WHIP method already solved using
rate
Injection test at maximum WHIP
Back-calculate using results of
shorthand WHIP and Craft and Hawkins
The maximum allowable injection rate is a function of the maximum
allowable injection pressure. If you figured maximum WHIP using the
applicant's proposed maximum rate and the long method using Matthews and
Russell, you are already done.
You could also require that the applicant perform an injection test, and observe
the maximum injection rate achieved at the maximum WHIP you already
calculated using either the long or short methods.
But if you used the shorthand method based on fracture gradient and the
operator can't perform an injection test (typical for a Class II application), you
must back-calculate the maximum rate that corresponds to the shorthand
maximum pressure.
Many permit writers conclude that the maximum rate is far less important than
maximum WHIP, and do not specify a maximum rate at all, providing that the
maximum WHIP limitation is observed. It is probably advisable to give
operators some sort of maximum rate limitation, just to give them another
point of reference.
14-26
-------
November 2001
Matthews and Russell
Q = Ap kb 1
162.6[J [log kt -3.23]
OfiCr2
1
Q = (794M400V50) [ log (400) (87600) - 3.23 ]
(162.6)(0.9) (.30) (.90) (.0000065) (.292f
Q = 9740 BPD @ 794 psi maximum WHIP
If you want to calculate the maximum injection rate that corresponds to the
shorthand injection pressure, you have to plug everything back into Matthews
and Russell.
This is Matthews and Russell transposed to solve for "Q". Just remember that
A p here is the maximum WHIP you calculated using the shortcut method, and
"r" is the effective well radius.
14-27
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November 2001
Maximum Injection
Volume
Specified by applicant?
Estimated from maximum rate
- Use 24- or 10-hour days, 5 or 7-day weeks
The last permit limitation you must specify is maximum allowable injected
volume.
Almost all applicants will specify the maximum volume they expect to inject
over the life of the well. If not, you can estimate it using the maximum rate
we calculated earlier. Simply multiply maximum rate times the days and
years the well is expected to operate.
Some permit writers use a 24-hour day and a 7-day week, whereas others use a
10-hour day or 5-day week as a safety factor. If you are using the long method
of the previous slide, substitute a 10-hour day or 7-day week when calculating
the "t = hours" component of Matthews and Russell.
Actually, except for unusual Class I-H situations, maximum volume is much
less important than setting valid limitations for maximum pressure and rate.
14-28
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November 2001
Conservative Values
and Safety Factors
Is a safety factor necessary to protect
USDWs?
- 75 percent of fracture gradient
- Minimum rather than average values
-10-hour days
Some permit writers believe that a safety factor is necessary in all of the
previous calculations in order to protect USDWs from excessive injection
pressure, rate, and volume. These safety factors may be applied at various
points in the calculation exercises, such as using only 75 percent of ISIP or
estimated fracture gradient, 10-hour days, least values for porosity rather than
averages, et cetera. Different Regions and permit writers maintain different
standards and methods for safety factors.
Safety factors aren't recommended except in cases of corrective action, for
two reasons:
* You may have to justify them to the applicant, and there is usually no
technical explanation for them; and
~ The ultimate safety factor is that the operator couldn't fracture the
confining zone, let alone all the way to a USDW, using any but the most
extreme technologies of commercial fracture treatment.
14-29
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November 2001
Monitoring Injected
Waste
14-30
-------
November 2001
Injectate Characteristics
Permit writers review injectate
characteristics for monitoring
requirements and compatibility
Permit application includes injectate
information
- Injectate rate, volume and pressure
- Analysis of characteristics: physical,
chemical, biological and/or radiological,
depending on class of well
A second aspect of operating data is a review of the injectate characteristics. The purpose of
this review is two-fold: To determine appropriate monitoring requirements; and to determine
whether there are any compatibility issues with respect to the injection zone.
The permit application must contain information on the injectate. The requirements vary
depending on the class of well.
~ Class INH (40 CFR 146.14(a)(7) and (8))
- Average and maximum rate, volume and injection pressure
- Source and an analysis of the chemical, physical, radiological and biological
characteristics
- Proposed program to analyze the chemical, physical and radiological
characteristics of the injection formation and the confining zone
~ Class n (40 CFR 146.24(a)(4))
- Average and maximum rate, volume and injection pressure
- Source and an analysis of the physical and chemical characteristics
~ Class ID (40 CFR 146.34(a)(7) and (8))
- Average and maximum rate, volume and injection pressure
- Quantitative analysis and ranges in concentrations of all constituents of injected
fluids or maximum concentrations not to be exceeded
- Proposed formation testing program to obtain fluid and fracture pressures and
physical and chemical characteristics of the formation fluids
~ Class IH (40 CFR 146.70 (a)(8) and (9))
- Average and maximum rate, volume and injection pressure
- Proposed program to analyze the chemical, physical and radiological
characteristics of the injection formation and the confining zone
14-31
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November 2001
Monitoring Injectate and
Injection Parameters
All injected fluids must be monitored
Monitoring requirements vary by well type
Monitoring parameters
- Injection rate
- Injection pressure
- Monthly and cumulative injected volume
- Annulus pressure and volume
- Waste characteristics such as density, pH, and
other parameters
In addition to mechanical integrity, measuring and reporting these characteristics are
the fundamental factors in permit compliance. For every type of injection well, State
and Federal UIC regulations specify the type of tests necessary, the frequency of
testing, and the method of recording the results for each parameter, depending on the
toxicity of the injectate and the perceived threat to USDWs.
For Class INH, II and III injection wells, the fluids injected into a permitted well are
required to be monitored to provide "representative data of their characteristics."
This minimum requirement is located in the following rules for the different well
classes:
~ Class I wells: 40 CFR 146.13(b)(1);
~ Class II wells: 40 CFR 146.23(b)(1); and
~ Class III wells: 40 CFR 146.33(b)(1).
Class V wells are subject to different standards, since many are not subject to
permitting. Under 40 CFR 144.88 (64 FR 68545, December 7,1999), however,
permitted Class V motor vehicle waste disposal wells are required to demonstrate
that injected fluids meet MCLs and other health based standards at the point of
injection. Additional details on this topic (including the Federal Register notice and
several new guidance documents) can be found on the Web at
www.epa.gov/safewater/uic/c5imp.html.
Class I hazardous injection wells have more stringent requirements for monitoring,
found at 40 CFR 146.68(a). A written waste analysis plan must be developed and
followed for these wells.
14-32
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November 2001
Injectate Monitoring
Measurement
pH
Monitoring Methods
Grab sample
Comments
Measure in the field;
influences corrosivity
and well construction
materials
TDS
Chemical content
Temperature
Compatibility and
reactivity
Grab sample
Generator
knowledge; field
sampling
Grab sample
Grab or composite,
depending on waste
stream
Compatibility with
injection zone
Representativeness;
potential to be
hazardous waste
Field measurement;
formation and well
construction issues
Formation and
construction
component influences
Monitoring requirements for injected wastes are defined in the permit itself.
The permit writer needs to evaluate what will be injected and how the fluid
may affect the well construction components as well as the receiving
formations.
Many injected fluids are required to be evaluated for pH, total dissolved solids
(TDS), and temperature. Chemical content must be evaluated based on site-
specific information. The range of constituents evaluated should be based on
the known composition of the waste stream as well as variability in the waste
stream. For instance, the waste generated from production of natural gas is
well defined and should be consistent. However, for a commercial hazardous
waste disposal facility, the wastes received vary from hour to hour and day to
day. Also, the potential risk to USDWs from hazardous waste injection is
greater, given the characteristics of the various contaminants in the waste.
The permit writer also must consider potential compatibility and reactivity
issues regarding the injected waste. Injectate may react with the injection zone
formation or formation fluids. The wastes may be incompatible with the well
construction materials as well, causing degradation of the injection tubing,
packer or other materials.
14-33
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November 2001
Monitoring Waste
Parameters
Many Class I wells operate under permit limitations for waste density, waste
pH and temperature, or specific chemical parameters. Before the digital age,
these parameters involved a chemist analyzing periodic samples of the waste.
Now, however, the use of digital probes and transmitters makes this type of
permit limitation more practical.
Density and pH transmitters are now available for less than $300, and their
interface with PC-based recording systems makes collecting and reporting
these permit data incrementally very inexpensive. Due to the lower cost and
ease of data collection, constant density monitoring should be considered as a
part of any permit that poses a risk of hydraulic fracturing, as well as pH
monitoring for any site that handles acid or caustic wastes.
14-34
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November 2001
Subsurface Waste
Interactions
Permeability reduction
Precipitates or polymers
- Clay swelling
Permeability increase: Dissolution of matrix
minerals
Gas generation
Reduce permeability
- Blowouts
Adsorption or desorption: Immobilize,
exchange, retard solutes
Potential reactions may occur between injected waste and the rocks and fluids of the
injection zone. The primary types of reactions are:
> Permeability reduction: chemical precipitates form and block the pore throats;
sensitive clay minerals may swell or disaggregate; or complex organic polymers may
form. Some precipitate damage is reversible, but many types cause permanent
formation damage and loss of injectivity;
^ Permeability increase: low pH wastes can dissolve matrix minerals of the injection
and confining zones;
> Gas generation: dissolution of matrix minerals and some waste-fluid reactions can
generate gaseous reaction products. In small quantities, effective permeability may
be reduced. In large quantities, explosive blowouts have occurred during workovers;
and
* Adsorption and desorption: most of the minerals in a sand reservoir are capable of a
wide range of selective adsorption and desorption reactions. Many of these reactions
are non-reversible, and hold the potential for immobilizing enormous quantities of
hazardous substances in typical injection zones, at volumes up to 60 percent by
weight. This complex system of reactions, cross-reactions, and inter-reactions is
impossible to predict or quantify at the surface, but undoubtedly occurs in all types
of well and waste scenarios.
Some of these subsurface reactions may sound beneficial, such as adsorption removing
large volumes of hazardous constituents. Almost all of the reactions are unpredictable,
however, concerning rate and duration and reaction products, because of variations or
uncertainties regarding flow dynamics and chemical stochiometry.
All of these reactions are taking place, to some degree, in every Class I injection well.
14-35
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November 2001
Changes in Fluid
(Class III)
Attachment N provides expected
changes in fluid
- Pressure
- Native fluid displacement
- Direction of movement of injection fluid
Another aspect of injection fluid is presented in Attachment N. This attachment is oriented
primarily to Class HI, but be aware of other fluid change issues for other well classes.
Class I wells, especially commercial wells, may apply for a permit for a wide range of
injectates to facilitate blending or changes in treatment processes.
In Class II, it is common practice that EOR wells change fluids during the course of the
project, as different polymers are used to effect changes in injection or sweep profile. Class II-
H wells in salt domes routinely alternate between brine injection for production and product
injection for emplacement.
For Class III wells, changes in injected fluid are commonplace during mining, and Attachment
N is where the applicant will spell out the details of his proposed process.
* Class HI mining projects commonly change injection fluids and orates, depending on the
process involved. In many Class III methods, the injection well periodically reverts to a
production well, in order to recover the injected mining fluid and the dissolved or
mobilized minerals.
* In these types of projects, it is very tough (if not impossible) to specify an accurate
permit limitation for volume and to predict the pressure effects on the injection zone. In
most cases, the applicant will spell out the details of his process in Attachment N,
especially the fluids he proposes to use. This data may also include detailed modeling
for ground water effects, and some processes will specify a remediation plan to recover
mining fluids and restore the injection zone to its pre-mining condition.
* One option you may decide to use is to require that the operator notify you in writing
whenever the process changes or fluids are changed over.
Whatever class of wells you are dealing with, make sure that the applicant clearly specifies the
details of his injection program if changes in fluid are indicated. You may also decide to
require written or verbal notification when the fluid program changes over. Also remember
that if an operator decides to change to a fluid that he is not permitted for, a permit amendment
is required.
14-36
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November 2001
Class V Well Operating
Data Evaluation
Large-capacity cesspools are not allowed to
be in operation in Dl States after April 2005; all
new wells prohibited as of April 2000
New motor vehicle waste disposal wells
prohibited after April 2000
Existing motor vehicle waste disposal wells in
critical ground water areas subject to closure
or permitting
A few types of Class V wells have specific limitations on operations that need to be
mentioned. First, all large capacity cesspools (capable of serving 20 or more persons per day)
were banned as of April 2000 in DI States. For primacy States, the ban date will be based on
the date on which their updated State regulations became effective. You will need to review
primacy State regulations on a State-by-State basis to determine the date.
All existing large-capacity cesspools are to be closed, under an EPA reviewed closure plan,
by April 2005.
No new motor vehicle waste disposal wells were authorized to be constructed or operated
after April 2000 in DI States. Again, the effective date of this prohibition will vary in
primacy states, depending on the date of their rule update adoption.
Existing motor vehicle waste disposal wells in critical ground water areas are banned as well.
However, the owner/operator may request a waiver from the ban and apply for a permit to
operate. The permit to operate must include some specific operating limitations.
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November 2001
Motor Vehicle Waste
Disposal Well Limitations
If allowed to continue to operate in critical
ground water area, must be permitted
Operations limited:
- Meet MCLs and other health based standards at
point of injection
- Monitor injectate and sludge
- Implement best management practices (BMPs)
The motor vehicle waste disposal wells that are subject to the ban and waiver or permit option are those
located in a critical ground water area. There are two possible types of areas in which these Class V
wells may be located. They may be in a delineated source water protection area or in an "other
sensitive ground water area" as defined by the Region or State. Additional information regarding other
sensitive ground water areas is available in the Class V Rule, signed December 7,1999, and in
guidance developed by Headquarters. You can access this information on the Web at:
* www.epa.gov/safewater/uic/c5imp.html
If the motor vehicle waste disposal well owner/operator desires to continue to operate his well in a
critical ground water area, he may apply for the waiver from the ban and submit a permit application.
A permit issued for these wells or any other Class V well must include the minimum permitting
requirements applicable to Class V wells (or "all wells") in 40 CFR 144.31 and 144.51. The permit
conditions of 40 CFR 144.52 must be considered and applied as EPA deems appropriate. In addition,
permit applications for all motor vehicle waste disposal wells must describe and the permit must list:
> A requirement that MCLs and other health based standards will be met at the point of injection.
The application should discuss how the applicant proposes to meet this requirement on an on-
going basis;
~ A requirement to monitor the quality of the injectate and sludge. Again, the application should
describe how this will be accomplished and the permit must specify the conditions (we will
discuss this more when we discuss injectate monitoring); and
* A requirement that best management practices (BMPs) be implemented at the facility to protect
the well from releases at the facility.
Other Class V wells may be required to be permitted, based on where and what is injected. There is no
simple way to state what operating conditions should be imposed on any Class V well, given the large
universe. However, at a minimum, you should consider the limitations placed on motor vehicle waste
disposal wells as a relevant standard, then determine what different conditions may be appropriate
given site-specific data.
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November 2001
Section 15
Proposed Injection
Procedures
DRINKING
WATER
ACADEMY
15-1
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November 2001
Injection Procedures
Describe the proposed injection
procedures, including pump, surge tank,
etc.
Include operating procedures and
contingency plans
In the permit instructions, injection procedures are specified as hardware, to
include "pump, surge tank, etc." An effective permit application, however,
should also include a complete overview of operating methods and procedures,
and plans to address surface-related emergencies.
The class of the well and nature of the injectate should guide the level of detail
necessary. For example, a Class II application might include a process
diagram and three paragraphs for operational methods, whereas a Class I
application might run for several pages.
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November 2001
Importance of
Procedures
Equipment used must be dependable
and durable
Automatic shut-down and emergency
response are critical for protection of
environment
* The equipment chosen for use in emergencies must be dependable and
durable. While one can more easily inspect and replace surface equipment
compared to downhole devices, alarm systems and other emergency response
equipment are critical for protection of the environment.
A properly functioning automatic alarm and shut-down system is a critical part
of the multi-barrier protection system in place for UIC wells. Until you can
investigate the reason for a well's pressure anomaly, you cannot be certain
what has happened. Rapid response of the well system is necessary to shut off .
the flow of waste to best protect the USDWs at the site.
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November 2001
Contingency Plans:
Iniectate Concerns
Source and type of injectate
Method of delivery (truck, pipeline)
Off-load equipment and procedures
Waste screening
Manifests
In addition to a site schematic diagram, you may decide to require specific
information concerning several areas of concern that are common to all
injection well operations. The discussion of surface equipment and procedures
might entail different degrees of detail, but all applications should include
contingency plans that address these common areas and issues.
Incoming injectate issues include:
^ Source and type of injectate, to include special handling characteristics
such as corrosive, explosive, etc.;
~ Methods of delivery to the site, such as by barge, truck, or pipeline
(whether on- or off-lease);
* Off-loading equipment and procedures;
> Waste screening, which might range from a simple pH check for Class II
waste to elaborate laboratory testing for Class I waste; and
* Manifests, which may be required for Class I wastes or for Class II
commercial salt water wells.
15-4
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November 2001
Contingency Plans:
Processing and Pre-Treatment
Oil-water separation
Filtration
Storage
Treatment equipment and methods
- RCRA ง3004(m) treatment
- Reagent storage
- Sludge handling and disposal
- Air emissions
Processing and treatment processes may include:
* Oil-water separation;
^ Filtration, whether simple settling or pressure filtration;
* Long or short-term storage; and
* Treatment equipment and methods. Treatment procedures may range
from the simple addition of a biocide or oxygen scavenger to
sophisticated chemical reactions such as pH adjustment or toxic
neutralization. Since the advent of the Class I-Industrial (that is, non-
hazardous) well category, many industrial operators pre-treat their waste
under RCRA ง3004 (m) (land disposal restrictions) to remove hazardous
constituents or characteristics in order to avoid regulation as I-H. The
applicant should explain the process and how he will guarantee the
effectiveness of the process and procedures on a day-to-day basis.
Of course, any pre-treatment process opens the door to many other related
issues, such as reagent storage, handling and disposal of sludges or other
reaction products, and a wide range of other air or water issues.
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November 2001
Contingency Plans:
Injection and Shut-in
Pump specifications
Back-flow prevention
Rate and pressure limitation
Shut-in methods
Injection and shut-in equipment and procedures should be covered in some
degree of detail, no matter what class of well is involved. A discussion of
injection equipment should include not only pump specifications and back-
flow prevention, but also the specific equipment and procedures that will be
used to limit injection pressure, rate, and volume as prescribed in the permit.
Inspectors have encountered several sites whose method of limiting injection
pressure was a red Magic Marker line on the wellhead pressure gauge.
Especially for Class I wells, demand to know about specific procedures and
equipment!
Shut-in of a well is an important step. As you know, abrupt shut-in during
operation causes pressure spikes that can damage downhole components,
similar to water hammer in your home. In many Class I wells, shut-in can also
involve switching to injection of a clean stream in order to protect tubulars
from corrosion or to provide a buffer between incompatible waste streams.
Written procedures for routine shut-in should have already been developed for
operator training, and also should be submitted as part of any Class I permit
application.
15-6
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November 2001
Contingency Plans:
Emergency Procedures
Spill prevention and containment
Loss of mechanical integrity
Exceed maximum rate or pressure
Auto alarm and/or shutdown
Emergency contacts
Emergency procedures should be written (and practiced!) in any class of
facility.
* Spill Prevention, Control, and Countermeasures (SPCC) plans should be
prepared for every facility that features tanks, and may be submitted as
part of the UIC permit application. Reviewing SPCC plans is a complex
subject; permit writers should forward the plans to the appropriate expert
reviewer for separate comments, especially for Class I permits.
* In addition, require written procedures that prescribe actions to be taken
when a permit limitation is exceeded or MI is lost, for any class of well.
If the well also features continuous annulus monitoring (Class I-
Industrial), require automatic alarms under any and all circumstances.
An automatic shutdown system can be complex and expensive, but if
you think that the circumstances justify the expense, do not hesitate to
require one.
Emergency contact numbers are an important part of a contingency plan.
Every application and permit should prominently feature the telephone
numbers that the operator would use to notify site and corporate management
in the case of a well failure or other emergency, and which a UIC official can
use to contact the site directly.
15-7
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November 2001
Automatic Shut-Down
Typically monitor rate, pressure, or Ml
- Requires continuous monitoring, usually of
electronic devices
Limitations
- Complex shutdowns
- Expensive
As we have discussed, typical permit limits for an injection well usually involve restrictions
to injection pressure, rate, and volume, as well as maintenance of MI. An injection well
operating outside specified permit limits is a matter of grave concern. In order to prevent
these violations, automatic shut-down systems can be used. Automatic shutdowns can be
harmful to a well, however, and a prudent permit writer should consider both the benefits and
the limitations of these systems.
First, automatic systems are applicable only to wells that feature continuous monitoring of the
permit parameter.
Except for simple mechanical pressure-actuated switches and valves (flow regulation
applicable only to centrifugal pumps with a bypass system), most automatic systems require
monitoring of electronic devices. Most Class II and III wells feature only periodic
monitoring of analog devices, so do not qualify for most automatic systems.
Automatic shut-down of a well entails a lot more than closing a valve. First, the valve
actuation rate must be carefully controlled, and is a function of injection rate and pressure.
Second, most 440-and higher voltage pumps must be shut down using several steps, rather
than all at once. For fuel-powered pumps (gasoline, natural gas), shutdown is even more
complex in that the fuel pressure and flow must also be bled down or diverted. Third,
shutdown at the wellhead must also entail closing valves at tanks and lines, and recirculating
line contents back to the tanks. Fourth, most Class I shutdown procedures involve switching
to a brine stream so that waste is not left in tubing or surface piping.
Automatic shut-down systems are expensive, and may cost from $75,000 to almost $1
million for a system on a slurry injector on the North Slope. There is also a significant
expense related to maintenance of these systems, because an unintentional automatic shut-
down disrupts surface processes, and may in fact cause a coincident shutdown of an entire
chemical plant.
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November 2001
Automatic Shut-down
Here is an example of part of a simple, mechanically actuated, automatic shut-
down system. A drop in annulus pressure triggers a valve actuator. Abrupt
shut-down of most injection wells would cause downhole damage to tubulars
or might allow sand to surge into the wellbore of perforated completions.
Therefore, most automatic shutdown systems switch to a noncorrosive
injection stream and reduce the pump rate until the tubing has been displaced,
in order to protect the tubulars from corrosion due to waste standing in the
wellbore. Waste standing in tubing would also provide a hazard to a workover
crew in the event of well repair.
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November 2001
Automatic Shut-Down
Benefits
- Limits versus trust
- Limits versus effects of violation
- Corrective action involved
Auto alarm appropriate for every well
The primary potential benefit of an automatic shut-down is that permit
limitations will be observed. You must also consider, however, that an
operator who would consciously operate outside permit limits or ignore an
alarm would also be capable of disabling the automatic shut-down system, as
well. An automatic system is no substitute for trust.
If rate or pressure has been limited for corrective action, there may be
situations where a system more compelling than an alarm is necessary.
Loss of internal MI in the tubing or packer is a more serious reason for
automatic shut-down, but unless the waste is very corrosive (or otherwise
harmful to the casing), it may still not be necessary. Indeed, if the MI loss
were in the casing, the only thing exiting the annulus is annular fluid, not
waste.
Permit writers would be wise to require in every case an automatic alarm
appropriate to the monitoring system, but save the automatic shut-downs for
extreme circumstances.
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November 2001
Emergency Shut-Down
Notification of excursion or Ml loss
Specific response procedures
Response time
Procedures to secure waste
Subject to inspection and rehearsal
It may not be appropriate to require an automatic shut-down system for every
well, but you should certainly know the details of the operator's procedure for
emergency shut-down.
* How does the operator propose that the site respond to excursions from
any permit limitation, or to a loss of MI?
> How will he find out that the parameter has been exceeded or MI lost?
* How will he shut down the surface and downhole operations, or regulate
the rate or pressure?
* How long will the process take?
* How will he secure the waste in piping and tanks in the event of a
downhole or pump failure, or for a spill?
Make sure that the procedures are in writing and are specific. Verify the
procedures during inspections and require rehearsals, at least when the well is
shut in for MIT.
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November 2001
Documentation
Accurate diagrams of system
Complete description of alarm system;
know "internal" from "permit" alarms
Response procedures and proper
notification when shut-down occurs
Schedule for testing system and
calibration of components as
appropriate
The permit itself, as well as the administrative record, should document a variety of
issues that arise out of this section. First, an accurate diagram of the well system
should be included in the permit or referenced clearly and retained in the application.
This diagram is especially important if an auto-alarm and shut-down system is
required. The diagram should be referenced or included so inspectors can
appropriately inspect the well system during site visits.
Any required alarm system should be clearly presented in the permit. You should be
able to recognize and understand the difference between alarms that may be in place at
a facility for internal reasons (for parameters not regulated in the permit; early warning
alarms for pressures, etc.) compared to those that are in place explicitly to meet permit
requirements. The facility need not report every alarm that sounds - only those that
are in place to address a specific permit requirement.
Be sure to evaluate the proposed response procedures when an emergency occurs.
Any loss of MI should be reported to the regulatory agency, and the permit should
require this reporting within a specific time frame. 40 CFR 144.5 l(k)(6) specifies
conditions that are required to be reported within 24 hours. The 24 hour reporting
requirement has generally been interpreted to included losses and apparent losses of
MI. Within five days, a written report must be submitted; this requirement must be in
the permit as well. Guidance 21 for the UIC Program provides some interpretation of
what is required in the verbal vs. written report.
The auto warning and shut-down system, if required, should be tested to demonstrate
its effectiveness, and EPA should have the right to witness testing. You should ensure
this is in the permit as well. Some system components may require periodic
calibration; if appropriate, require the calibration through the permit.
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November 2001
Lesson 16
Plans for Well
Failures
DRINKING
WATER
ACADEMY
We ended the previous section (Injection Procedures) with a discussion of the
operator's responses to process-related emergencies: exceeding permit
limitations such as injection rate, pressure, or volume; or receiving indications
from the monitoring system that mechanical integrity has been lost.
In this section, we will present a detailed analysis of downhole problems and
failures, as well as the methods the operator will use to test for, respond to,
and, hopefully, prevent well failures.
16-1
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November 2001
Attachment O Instructions
Contingency plans (proposed plans, if
any, for Class II) to prevent migration of
fluids into any USDW
- Shut ins
- Well failures
Provides assurance of existing and
future well integrity
In the last section, we covered how contingency plans spell out what to do in
the event of a well failure related to injection procedures.
Attachment O is really misnamed; the primary emphasis of this attachment is
the operator's plan to prevent well failures, which should include plans for
testing and monitoring the downhole integrity of the injection well.
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November 2001
Mechanical Integrity
40 CFR 146.8(a):
"No significant leak in casing, tubing, or
packer
and
No significant fluid movement into
USDW through vertical channels
adjacent to injection well bore"
An operator is required to maintain the mechanical integrity of his well at all
times. First, we need to define mechanical integrity as used in the UIC
program.
Mechanical integrity (MI) of a well is defined in 40 CFR 146.8(a). The
regulation states:
"An injection well has mechanical integrity if:
> There is no significant leak in the casing, tubing or packer; and
* There is no significant fluid movement into an underground source of
drinking water through vertical channels adjacent to the injection well
bore."
These two provisions are typically called "Part 1" or "internal" and "Part 2" or
"external" MI.
16-3
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November 2001
What is Required?
All wells are required to demonstrate
external and internal Ml on a regular
basis
Frequency and acceptable tests vary
among well classifications
The regulations for Class I, II and III injection wells have specific schedules
for demonstrating mechanical integrity.
^ Class I nonhazardous wells: Part 1 and 2 MI at least once every five
years (40 CFR 146.13(b)(3));
* Class I hazardous wells: Part 1 annually, Part 2 every five years (40 CFR
146.68(d);
* Class D: Part 1 and 2 MI at least once every five years (40 CFR
146.23(b)(3)); and
* Class EI: Part 1 and 2 MI at least once every five years for salt solution
mining (40 CFR 146.33(b)(3)).
Class V wells typically do not have MI requirements, unless they are unusually
deep or sophisticated.
You may also consider more or less frequent MIT when writing permit
conditions, depending on circumstances. Many wells with poor mechanical
histories are subjected to more frequent MIT, as are wells in sensitive
locations, such as low fracture gradient or deep USDWs. Less frequent MIT
may be allowed for wells that inject hazardous and non-hazardous waste on a
long-term periodic basis; such as injecting hazardous waste at plant
changeover for two months every five years and non-hazardous waste the rest
of the time. However, unless unusual circumstances like this exist, the permit
writer must require at least the minimum frequency of testing listed in the
regulations.
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November 2001
Types of Well Failures:
Tubing and Packer
Most common (80 percent)
Easily detected by annulus monitoring
or APT
Contains leaked injectate
Located and fixed by pulling tubing and
packer
In the previous section, "Injection Procedures," we discussed the types of
things that can go wrong with the surface processes of injection. This section
will discuss the types of things that can go wrong with the subsurface aspects
of injection. We will deal primarily with things related to the mechanical
aspects of the well. You will recall that we covered external subsurface
problems in our section dealing with corrective action.
Four nationwide studies of MI failures showed that tubing leaks were the most
common form of MI loss, by a four-to-one margin over packer and casing
leaks, combined. Packer leaks are the second-most common, and will be
tough to discern from a tubing leak in an annulus pressure test (APT).
Continuous annulus monitoring or a traditional annulus pressure test will
detect these leaks 100 percent of the time. The only way to find the leak is to
perform pressure tests on segments of the tubing using a bridge plug, or to pull
the tubing and test at the surface. Because you have to pull the tubing to fix it,
most use the latter method.
Most regulators regard tubing and packer failures as less threatening than other
failures, because as long as the well is shut down, there is nowhere for the
leaked injectate to go but downward to the injection zone (or it is contained in
the annulus). Oilfield operators will even argue that tubing is an expendable
maintenance item, and many Class II wells are constructed with used tubing.
Unless the waste is highly corrosive, or other components are also leaking, this
type of leak can be considered contained.
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November 2001
Types of Well Failures:
Casing Failures
12 to 20 percent of Ml failures
APT detects, but can not tell from tubing
and packer leaks
Located with bridge plug
Repaired by liner, squeeze, or
recompletion and sidetrack
Uncontained leak (threat to USDW?)
The second major category of MI failures are casing failures. About 12 to 20
percent of MI failures involve casing, with frequency depending on well class
(Class lis have more because they are not usually fully cemented). A
traditional APT or annulus monitoring will find a casing leak, but can not
discern the difference between tubing and packer leaks and casing leaks.
About 30 percent of the time, however, a distinct pressure differential between
annulus and tubing can indicate the difference.
The only way to find the actual location of a casing leak is to perform segment
tests using a bridge plug. Casing can be repaired by running a liner (another
string of casing set or cemented inside the first), squeeze-cementing, or
plugging back and recompleting in a higher zone. A few Class I wells may
sidetrack (i.e., directionally drill a new lower wellbore) if a higher zone is not
available.
Casing leaks may present a severe threat to USDWs, depending on the vertical
location of the leak, that is, ranging from within the permitted injection zone to
opposite a USDW.
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November 2001
Types of Well Failures:
Cement Failure
Migration captured
- Indirect connection to USDW through conduit in
capture zone?
Direct connection to USDW through
uncemented or poorly cemented casing
Detect with RAT or other external MIT (Class I)
- Prevented with cement logs or records during
permitting
Repaired by squeeze or recompletion
The scariest kind of MI failure involves failure of the cement seal. An external MI failure can
allow waste to migrate out of the injection zone. If the waste escapes the confining zone (a bad
thing), it will probably be captured in the first permeable zone above the confining zone (a good
thing). That could present an indirect threat to USDWs, however, if that zone has a conduit to a
USDW, such as a poorly constructed or abandoned well, as we discussed in the corrective
action section.
If, however, the well features a segment of uncemented casing above the confining zone (typical
of Class II) or the overall cement job is poor to begin with, there is a distinct possibility that the
injection zone could communicate directly with the USDW. Experience and studies show that:
* The most difficult thing to do in constructing a well is to get a good cement job;
* Cement failures in wells with good cement seals are rare to non-existent; and
* Lots and lots of injection wells have substandard cement jobs, including Class I-H.
Unfortunately, the only way to detect a cement failure is with a radioactive tracer test (RAT) or
other approved test. These tests are run every five years on most Class I wells, and but are not
run at all on Class II wells. Therefore, the primary way to prevent cement failures is to give
permits only to wells with decent cement jobs. As we discussed, that would involve cement
logging for Class I wells, and careful scrutiny of cement records for Class II and III wells.
Cement failures are repaired by squeeze-cementing or, more commonly, by abandoning the
zone and recompleting by plugback or sidetrack. There are three ways you can deal with a
migration incident caused by cement failure, that does not involve a USDW:
* Attempt to recover or remediate (very infrequent);
* Take no action (usually used when zone is saline); or
* In Texas, repermit the injection zone to include the migration.
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November 2001
Ml - Part 1 (Internal)
Testing Method
What Is Evaluated?
Comments
1 Annulus
pressure test
Ada
Water-ln-annulus
Casing, tubing
and packer leaks
ฆ Small leaks may not be
readily detected?
Casingless Class II In
Regions 2 & 3
Ohio Class II
The UIC regulations denote a few acceptable MITs, but the program also has the authority to evaluate and
approve additional, or alternative, tests for both internal and external MI. Although this list may not be
complete, because there are a few tests approved in some Regions for unconventional well types, these are
the basic MITs you will see in the majority of cases.
An annulus pressure test (APT) is a test in which the annular space between the injection tubing and well
casing is pressurized. The pressure is monitored for a preestablished time period (based on the regulatory
agency's requirements). If the pressure changes more than a certain percentage of the starting pressure
(often three percent), the test is determined to have failed and the agency may require a retest or further
investigation of the well prior to allowing injection to resume. Some States require that test pressure equal
injection pressure; others specify one test standard, such as 1500 psi for 30 minutes, plus or minus 10
percent; while others require that the test pressure exceed routine injection pressures.
Other approved internal MITs are the Ada and water-in-annulus tests. These tests also evaluate the
pressure characteristics of tubulars, but use a dynamic fluid level as the pressure source.
The permit should specify that internal tests are performed at the casing head, not at a remote fitting. The
annulus should be full of liquid (not compressed air or nitrogen), and that liquid used for the test. Also,
for traditional APTs, most inspectors know to check for the volume of "returns," the flow-back from the
pressure test. If you put a thousand psi on a 5,000 foot annulus, fluid compression may total five gallons.
When you release the pressure on a liquid-full annulus, the casing head will "return" the five gallons it
took to attain 1,000 psi. If it doesn't, the packer is not set accurately.
Recording methods should also be specified in the permit. Digital recording devices are available for rent
in almost all areas, and the output from a certified device is almost 100 percent valid. At the least, the
permit writer may accept a circular chart recorder, but should require the circular charts from two
simultaneous recording devices, both signed by the operator.
For Ada-type tests in other well classes, it may be prudent to require that any time the tubing is pulled, a
packer-type test be performed on the well.
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November 2001
Ml - Part 2 (External)
Indirect Evaluation
What is Evaluated?
Comments
Cement evaluation
tools and cement
bond logs
Overall Cement
Integrity
Must evaluate over
time
Cement records
Only allowed for
Class II and III
Replaces Part 2 MIT
demonstration
requirement
External MITs look for flow channels behind casing.
Cement evaluation tools and cement bond logs evaluate the integrity of the cement
behind the casing. They look for annuli between the casing and the cement, or the
formation wall and the cement. Just as with the casing inspection tools, it is
important not to assume a cement area that is thin or a possible annulus is a huge
issue and has been formed by injectate leakage. The problem may have been there
from the initial emplacement of the cement and may not pose a risk to the well's
integrity.
Cement records may be used only for Class II and III wells, replacing the Part 2
MIT requirement. For Class II wells, the cementing records must demonstrate the
presence of adequate cement to prevent behind-pipe migration. For Class III wells,
the records can only be used when the nature of the casing precludes using Part 2
MI tools downhole.
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November 2001
Ml - Part 2 (External)
Testing Method
Radioactive
tracer test
What Is Evaluated?
Internal leaks,
behind pipe flow
Comments
1 Very useful tool
Temperature
Behind pipe flow
' Temperature contrast
between Injected test
fluid and formation fluid
required for conclusive
results
A radioactive tracer test (RAT) is a logging technique in which a radioactive tracer
is ejected from portals in a tool. The movement of the tracer is observed to ensure
that the tracer material does not exit the tubing prior to the packer, does not move
back up behind the packer into the annular space, and does not move upward in
fractures behind the well casing ("behind-pipe flow"). The pumping rate of the fluid
and methods used by the logger can affect the results observed, and close
examination of the results compared to historical results and the permitted injection
interval are critical.
The RAT is the most commonly used (by far), but the regulations also allow for
these alternatives. Remember that the RAT can only detect injection-related flow at
the bottom of casing.
Temperature logs can be conducted two ways. One method involves injecting fluid
at a different temperature from the downhole temperature, with observation over
time to evaluate whether the fluid has moved behind the pipe and is changing the
temperature of the formation (cooling or heating it). The second method involves
static logging over time to observe the way the formations downhole cool (or heat)
when the well is shut in. If a particular zone does not cool or heat according to what
is expected, the anomaly may be caused by upward migration of fluid behind the
casing through microannuli or formation fractures. It is not advisable to accept a
noise or temperature log as the sole method of proving MIT. These tests require a
larger amount of flow than a RAT test or oxygen activation, and, in many cases, the
interpretation is somewhat subjective.
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November 2001
Ml - Part 2 (External)
Testing Method What is Evaluated?
Noise
Behind pipe flow
Comments
Very limited due to
small zone heard by
tool
Oxygen activation Behind pipe flow
Calibration crucial
Noise logs essentially involve placing a microphone downhole to listen.
Upward flow of fluids behind the pipe will be heard. This log is not as widely
used as the temperature and oxygen activation logs. Noise logs are 1950s
technology, and are useful only in gas environments or for larger flow. These
days, noise logs are not used at all in industry except in offshore gas wells.
Oxygen activation (OA) logs use excitement of oxygen atoms to monitor flow
behind the casing, and is the only tool capable of directly monitoring flow
above the bottom of the casing (noise and temperature logs use indirect
indicators of flow). It used to be more expensive than other Mi-related logs,
but has become much cheaper with increased usage by the oil industry.
Oxygen activation logs got a bad reputation when they came out, because the
Class I Hazardous industry lobbied aggressively against them when EPA was
considering a requirement for them. A major oil company and the American
Petroleum Institute also lobbied against them, so that EPA would not think
about extending the requirement to Class II.
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November 2001
Know What You Are
Seeing!
MITs are crucial to ensuring on-going well
component safety but they only see within
inches of the wellbore
MITs do not replace siting criteria
Failure can occur beyond the wellbore
environment that can contaminate USDWs
MITs are one part of an injection well's
multiple barrier set to protect USDWs
It is crucial that the permit writer and other UIC staff understand exactly what
the tools "see" in the well, and what the various tests are able to tell you.
MITs provide valuable information about the wells. Most tools used for MITs
only reveal what is happening within inches (a few feet at best) outside the
well casing. A RAT can only provide information about injection-related flow
at the casing shoe.
Thus, a permit writer needs to understand that the siting criteria for a well, and
associated verification of the local and regional geologic settings, are still very
important even when all MITs are passed with flying colors.
MITs can indicate that a well has a problem before there is an actual failure of
MI. Obviously, the goal is to prevent significant flow from the well and
injection interval that will put USDWs at risk. So even if an annulus pressure
test (APT) indicates a fairly small leak, don't wait until it's really big, call it
"significant" and then require repairs!
MITs are one part of a multiple-barrier system designed to protect USDWs
from contamination.
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November 2001
Annulus
Monitoring
Class I is unique in that continuous annulus monitoring is required for all non-
municipal wells (40 CFR 146.13(b)(2)). Continuous annulus monitoring usually
provides instant warning of mechanical integrity failures that involve the tubing,
casing, or packer.
Most States require that annulus pressure be maintained at a level greater than tubing
pressure. This provides improved identification of minor tubing leaks that occur
during operation, and ensures that leakage will involve annulus fluid leaking into
tubing, rather than waste leaking into the casing annulus.
Some operators monitor a closed, pressured annulus, but operating temperature and
expansion effects can cause significant pressure fluctuations in the annulus. Most
operators utilize an expansion tank as part of the annulus monitoring system, and also
monitor changes in fluid level in the expansion tank. This is an extreme example of
annulus expansion-tank monitoring; this is the Class I well at the Badami site on the
North Slope. The waste-to-annulus fluid temperature differential can be 180 degrees
F in winter and fluid volume can change 20 percent. Most wells use an expansion
tank on the order of 5 to 20 gallons.
Most Class I wells are required to use alarm systems to alert operators that a
monitoring parameter has been violated. Alarms are required not only within
operating spaces, but in central offices or control rooms.
Almost all Class I monitoring and recording devices are digital, and use a PC to
collect and simultaneously analyze the monitoring data. By assigning pre-set
operating ranges for all parameters, operators can use a PC to trigger alarms or
automatic shut-down systems. Make sure that the operator demonstrates his system
during inspections.
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November 2001
MIT Guidance
Many procedural differences among
States and Regions, well classes
Annulus pressure test
-Test pressure, duration, and variance
Radioactive tracer test
- Moving versus stationary, stations, flow
States and Regions have unique specifications and procedures for MITs. In
addition, most specify different procedures for different well classes.
For APTs, the areas of difference usually involve test pressure, duration, and
allowed variance. For RATs, the differences usually involve moving versus
stationary tests, the number and location of stations, and flow conditions.
Many Regions use a variation on the excellent RAT procedural guidance
developed by Region 5.
Most permit writers include the type and interval of MITs in permits. Include
a reference to and attach the applicable guidance or procedures. Also include
a requirement for timely notification, such as seven days rather than the 48
hours most permits specify, to allow you to witness a test now and then.
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November 2001
Section 17
Monitoring
Program
An essential part of the permitting strategy for Class I wells involves careful
consideration of applicable and appropriate methods of monitoring and
establishing mechanical integrity. Monitoring should include periodic or
continuous measurement and recording of operational parameters and waste
characteristics, using tests and test frequencies sufficient to establish that the
well is operating in compliance with permit conditions.
MIT should include internal pressure testing, radioactive tracer testing or
fluid-flow logging, and casing inspections on a sufficient basis to establish the
long-term acceptability of the well.
This section will discuss not only the methods of monitoring and recording,
but also the guidelines by which permit writers may decide the appropriate
level of requirements for a particular well.
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November 2001
Monitoring Program
Maps of wells
Monitoring devices
Sampling frequency
Parameters measured
Manifold monitoring, if applicable
The instructions for the permit application read as follows:
Discuss the planned monitoring program. This should be thorough, including
maps showing the number and location of monitoring wells as appropriate and
discussion of monitoring devices, sampling frequency, and parameters
measured. If a manifold monitoring program is utilized, pursuant to
ง 146.23(b)(5), describe the program and compare it to individual well
monitoring.
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November 2001
Monitoring Requirements:
Class I (40 CFR 146.13)
Analyze injectate (at unspecified
frequency) for representative data
Use continuous recording devices
-WHIP, rate, volume, annulus
Conduct MITs every 5 years
Put monitoring wells in USDWs
Report quarterly
40 CFR 146.13 (b) states that monitoring requirements for Class 1 wells must,
at a minimum, include:
* The analysis of the injected fluids with sufficient frequency to yield
representative data of their characteristics;
^ Installation and use of continuous recording devices to monitor injection
pressure, flow rate and volume, and the pressure on the annulus between
the tubing and the long string of casing;
> A demonstration of mechanical integrity pursuant to ง146.8 at least once
every five years during the life of the well; and
> The type, number and location of wells within the area of review to be
used to monitor any migration of fluids into and pressure in the
underground sources of drinking water, the parameters to be measured
and the frequency of monitoring.
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November 2001
Monitoring Requirements:
Class II (40 CFR 146.23)
Monitor nature of injectate (at unspecified
frequency) for representative data
Observe WHIP, rate, volume
- Monthly for ll-R
- Weekly for ll-D
- Daily for ll-H and cyclic steam
Conduct MIT (APT) every 5 years
May use manifold monitoring for ll-R and ll-H
Report annually
40 CFR 146.23(b) states that monitoring requirements for Class II wells must, at a
minimum, include:
~ Monitoring of the nature of injected fluids at time intervals sufficiently
frequent to yield data representative of their characteristics;
* Observation of injection pressure, flow rate, and cumulative volume at least
with the following frequencies:
- Weekly for produced fluid disposal operations;
- Monthly for enhanced recovery operations;
- Daily during the injection of liquid hydrocarbons and injection for
withdrawal of stored hydrocarbons during the injection phase of cyclic
steam operations.
~ Recording one observation of injection pressure, flow rate and cumulative
volume at reasonable intervals no greater than 30 days;
* A demonstration of mechanical integrity pursuant to ง146.8 at least once every
five years during the life of the injection well; and
~ Maintenance of the results of all monitoring until the next permit review (see
40 CFR 144.52(a)(5)).
Hydrocarbon storage and enhanced recovery may be monitored on a field or project
basis rather than on an individual well basis by manifold monitoring. Manifold
monitoring may be used in cases of facilities consisting of more than one injection
well, operating with a common manifold. Separate monitoring systems for each well
are not required provided the owner/operator demonstrates that manifold monitoring
is comparable to individual well monitoring.
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November 2001
Manifold Monitoring
Wells usually connected by common
piping network; monitor at central
location rather than well-by-well
Injection characteristics at the well are
different (usually less pressure) from
those at the manifold
Operator must demonstrate
comparability
In Classes II and III, the regulations provide for manifold monitoring. This
concept reduces the monitoring burden on operators by allowing them the
option of monitoring rate, pressure, and volume in a common manifold or
piping network, rather than at each individual wellhead.
In enhanced recovery and hydrocarbon storage projects (Class II), and in
almost all Class III projects, it would be prohibitively expensive and
impractical for the operator to install a dedicated pump for every well.
Instead, the operator installs a bank of pumps at a central location and runs a
piping network to each wellhead. The regulations allow him to monitor the
entire project from a central location, i.e., the manifold, rather than installing
measuring devices and driving around to every well in the pattern.
There are two things to remember:
* The calculations in the last section for allowable rate and pressure can
not be used when an operator uses manifold monitoring. Every well in
the pattern is injecting at a different pressure and rate (sometimes very
different), depending on the distance and gradient of the piping to each
well. If you specify the maximums as measured in the manifold, it is
unlikely that any well would have more rate or pressure at the wellhead.
~ Second, the regulations provide that the operator must demonstrate that
manifold-monitoring is "comparable to individual well monitoring."
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November 2001
Monitoring Requirements:
Class HI (40 CFR 146.33)
Monitor nature of injectate (at unspecified
frequency) for representative data
Monitor WHIP and rate or volume every 2
weeks OR meter and daily record injection
and production volumes
MIT every 5 years for salt solution mining only
Fluid level and water quality every 2 weeks
- Quarterly for collapse in USDW (146.32.g)
May use manifold monitoring
Report quarterly
40 CFR 146.33(b) states that monitoring requirements for Class III wells must, at a
minimum, specify:
* Monitoring of the nature of injected fluids with sufficient frequency to yield
representative data on its characteristics. Whenever the injection fluid is modified to
the extent that the analysis required by ง 146.34(a)(7)(iii) is incorrect or incomplete, a
new analysis as required by ง146.34(a)(7)(iii) shall be provided to the Director;
* Monitoring of injection pressure and either flow rate or volume semimonthly, or
metering and daily recording of injected and produced fluid volumes as appropriate;
* Demonstration of mechanical integrity pursuant to ง146.08 at least once every five
years during the life of the well for salt solution mining;
> Monitoring of the fluid level in the injection zone semimonthly, where appropriate
and monitoring of the parameters chosen to measure water quality in the monitoring
wells required by ง 146.32(e), semimonthly;
* Quarterly monitoring of wells required by ง 146.32(g); and
* All Class HI wells may be monitored on a field or project basis rather than an
individual well basis by manifold monitoring. Manifold monitoring may be used in
cases of facilities consisting of more than one injection well, operating with a
common manifold. Separate monitoring systems for each well are not required
provided the owner/operator demonstrates that manifold monitoring is comparable to
individual well monitoring.
There is also a requirement (ง146.32(e)) for Class III solution mining projects to monitor
the injection zone (unless >10,000 TDS), the first permeable zone above or beneath the
mining zone, and within the USDW at the periphery of the project.
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November 2001
Digital Monitoring
In Class I, operators of non-municipal wells are required to constantly measure
and record the injection parameters (40 CFR 146.13(b)). Most Class I
measuring devices are digital, although a few operations continue to use
circular charts and/or pump-stroke totalizers. Most Class I systems also use
digital recording equipment. These systems easily manage alarms and
automatic shutdowns.
In Class II and III, however, pressure monitoring usually consists of an
operator checking a gauge on the pump manifold at the end of every day or
shift. Monitoring for volume probably consists of checking a rack of pump
stroke totalizers and marking a clipboard list.
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November 2001
Reporting Methods
and Media
Reporting for Class I wells is performed on a quarterly basis (40 CFR
146.13(c) and 146.69). Although a few operators still use paper circular
charts, the preferred format for monitoring data is on PC "Zip" discs or CD-
recordable media. For Class II and III, expect to get daily or monthly
summary information for the project or field.
Monitoring reports should not be strictly a "data dump," but should provide a
few basic analyses in addition to the raw data.
> The permit should specify that all types of data be graphed, both for the
current reporting period and to date
^ In addition, the report should identify, for each parameter, the maximum,
minimum, and average values for the quarter and explain any deviations
from permit limitations; and
* The report should also discuss any maintenance activities, MITs, or other
significant events that took place during the reporting period.
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November 2001
Annulus
Monitoring
As we discussed earlier, Class I is unique in that continuous annulus monitoring is
required for all non-municipal wells (40 CFR 146.13(b)(2)). Continuous annulus
monitoring usually provides instant warning of mechanical integrity failures that
involve the tubing, casing, or packer.
Most States require that annulus pressure be maintained at a level greater than tubing
pressure. This provides improved identification of minor tubing leaks that occur
during operation, and ensures that leakage will involve annulus fluid leaking into
tubing, rather than waste leaking into the casing annulus.
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November 2001
Corrosion Monitoring
The corrosion rate of tubing and packers may be monitored by means of
corrosion coupons inserted in the waste stream. Corrosion coupons are
specimens of the same material as the well components. The samples are
periodically removed from the flow line, and carefully cleaned and weighed.
The weight is compared to previous values, and divided by the surface area
and time of exposure, which, for metals, provides a corrosion rate in terms of
mils per year.
Most corrosion samples are metal, but it is also possible to estimate the
corrosion potential for cement samples and fiberglass. Most corrosion samples
are located at the surface, so it is important to remember that downhole
temperatures will accelerate corrosion. Many corrosion sample holders are
heated to approximate subsurface conditions.
Another method of corrosion monitoring uses wireline enhanced caliper or
imaging logs to inspect casing. These logs are required by some states on a 5-
year interval, and involve pulling the tubing from the well. Most casing
inspection logs are helpful, but seldom provide definitive data before the well
starts leaking.
This photo is of casing from a prominent Class I-H well, a week after it
"passed" an MIT. That's a two-finger-sized hole in the foreground, and a fist-
sized hole in the upper background.
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November 2001
Monitoring Wells
Monitor injection zone
- Pressure, waste front, waste
decomposition
Monitor above confining zone
- Waste migration
Monitor USDWs
- Presence of waste
Class III monitoring necessary
Some States and Regions routinely require some sort of monitoring well,
whereas in others the practice is entirely unknown.
There are three types of monitoring wells:
* Wells in the injection zone, used to monitor pressure and the position and
chemistry of the waste;
* Wells in the first permeable zone above the confining zone, used to act
as sentry for waste migration; and
* Wells in the lowermost or other USDWs, used as confirmation that waste
is not present.
Class III solution mining wells are fairly shallow and inexpensive, and because
most mining takes place within or near USDWs, monitoring is a necessity in
most cases. The following discussion is limited to deep wells.
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November 2001
Monitoring Wells:
Problems and Limitations
Expensive (approach cost of injector)
Small capture radius unless continuous
pumping (water disposal)
Path for migration
There are some pretty significant problems and limitations connected with the
use of monitoring wells.
First, they are expensive, and costs for the two deep methods range from about
60 to 80 percent of the cost of the injection well itself. This could range from
$150,000 to $1 million for a Class I or II well.
Second, the capture radius of wells outside the injection zone is pretty small,
unless the well is continuously pumped. A typical sampling event, even one
with a lot of pumping, will give you an effective sampling radius of a few feet,
especially in typically thick aquifers. Because the potential problem area
around an injection well is defined by the area of review, you would need
literally hundreds of monitoring wells to sample that area. Continuous
pumping sounds feasible, but if that well is monitoring a saline aquifer above
the confining zone (or even a 10,000 TDS USDW), water-disposal costs can
be very substantial, unless there is Class II reinjection activity nearby or the
operator has excess capacity in the Class I well (both very unlikely).
In the case of deeper methods, a monitoring well can create its own migration
pathway. In a 1999 study of Class I MI failures, Florida reported that 4 of 16
Class I waste migration incidents were caused by the monitoring well the
State had required for each project (and they were looking into others). These
were both internal and external MI failures of the monitoring wells. To
safeguard this eventuality, require the operator to run internal and external
MITs, which also means bigger casing and tubing and packer. This may result
in a price similar to the cost of the injection well, and still have no guarantee
that the well won't allow flow above the casing shoe.
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November 2001
Is There a Real Need
for a Monitoring Well?
Injection zone
- Pressure, waste
Deep USDW/saline zone
- Capture radius, conduit
USDW
-Too late
A monitoring well in the injection zone can monitor injection pressure, but so
can the injection well itself. If you are looking for presence of the waste front,
once it arrives at the well, there is no further use for the well (but it still can act
as a migration pathway).
Monitoring waste decomposition is probably not necessary from an
operational standpoint, except for a Class IH well with a no-migration petition
(although with a 10,000-year timeframe only the foolhardy would drill a
monitoring well). The effectiveness of the confining zone is your primary line
of defense.
A well monitoring the deepest USDW or a zone above the confining zone
sounds more effective, but you still have that tiny capture radius in relation to
the size of the AoR. More importantly, any migration that would make it all
the way to a USDW is not due to wholesale upward migration, but to the
presence of a conduit like an abandoned well. It's highly unlikely that the
monitoring well would detect the real mechanisms that threaten USDWs.
A well monitoring a USDW has the same small capture radius, and if you did
find evidence of waste migration, given transit times in ground water, the
damage is already done.
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November 2001
Uses of Monitoring Wells
RCRA monitoring in upper USDW
Corrective action
Known migration
- Use other drilling on site for monitoring
Florida
- Poor confinement versus need for injection
Concessions?
If the operator also has a RCRA permit for his surface facility, that program will
usually require him to install monitoring wells in the uppermost USDW. You can
specify in the permit that those sampling results be shared with you.
The primary use of monitoring wells involves corrective action. It can often be
necessary to monitor pressure in the injection zone, and there are at least two
facilities that monitor pressure in the injection zone using existing wells in the AoR.
In a few cases, wells monitor waste migration that was found in an unpermitted
saline zone above the confining zone. In the two cases mentioned above, the
migration was discovered during the drilling of another well on the site. There is
also a lesson here: if another well is drilling on a site, ask (or require) the operator
to sample a few key zones above the confining zone. Sampling can be done as a
drill-stem test or by monitoring the mud returns for indicator chemicals in the
waste.
In Florida, the poor confinement offered by fractured dolomites is offset by the
perceived need for injection as a disposal method for municipal wastes. In many
projects, deep and shallow monitoring wells are required by the State UIC agency.
As we discussed earlier, many of the monitoring wells have themselves been
responsible for contamination of USDWs.
The words "deep monitoring well" will strike terror into most operators, due to the
cost involved and the potential for ambiguous (read expensive) results. Most
operators would do more frequent MITs or allow other concessions in order to
avoid having to install a monitoring well.
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November 2001
Review Essentials
Monitoring and reporting versus regs
- Specific to well class
Details of annulus system
Reporting format (specify!)
Special conditions
- pH, corrosion, density
- More MITs!
Review of this attachment is pretty straightforward - the regulations are very
specific as to the parameters to be monitored, how often sampled, and when
reported. You should compare the proposed program to the regulations as
presented earlier in this section.
You also want to know all the details of the annulus monitoring system, if
appropriate. Avoid systems that do not allow for overflow or surge tanks and
volume monitoring. Also avoid any methods that utilize air or other gases,
both in the annulus or for testing.
Specify the reporting format as we discussed, for Class I wells that are (or
should be!) more sophisticated.
If you have concerns, specify additional permit conditions for extra parameters
to be monitored or for additional frequency. For example, you might require
some form of pH and simple corrosion monitoring for any low or high-pH
waste. If the maximum allowable injection pressure is an issue, require
continuous waste density monitoring. With the low cost of the new generation
of digital monitoring, you are not out of line in asking for things unheard-of in
the past.
Also seriously consider additional MITs for any Class I-NH industrial well. It
may not be reasonable to use the same 5-year interval for MITs as used for
Class n. An annual internal MIT is always advisable. If you have concerns
about the waste or cement, add a condition for an annual or 2-year RAT.
There aren't many things we can control in UIC once the well is drilled. The
MIT is our first line of defense.
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November 2001
Injectate Monitoring:
Exercise
Class l-H commercial disposal well
High waste acid content
Injection into dolomite cemented
sandstone, through fiberglass injection
tubing with standard steel casing
What would you require the operator to
evaluate regarding injectate content?
How often?
Consider the following scenario and decide what kind of waste monitoring
you think would need to be conducted, and how often, to ensure the waste
(injectate) characteristics and potential impacts are adequately defined.
Think back to everything we've discussed about deltap, geology,
hydrogeology, siting, construction and other elements of the permitting
process. Explain the rationale behind each of the parameters you define for
monitoring.
SCENARIO: A facility operator has one Class I hazardous waste injection
well as part of the facility. The facility receives waste fluids from off-site
generators, including a large quantity of waste acids. The injection interval
consists of a dolomite-cemented sandstone. The injection tubing is fiberglass,
and the well casing is standard steel casing. Averaged over the last five years,
the well is operated approximately 250 days per year, with a flow rate of up to
100 GPM.
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November 2001
Lesson 18
Plugging and
Abandonment Plan
All UIC wells are required to be properly plugged prior to being abandoned.
Abandoned wells can become conduits to USDWs, allowing injected fluids or
native brines to migrate vertically into them. Uncemented annular space and
open casing can both provide these vertical conduits.
In this section, we will discuss the requirements of the plugging and
abandonment (P&A) plan that must be submitted for Class I, II and III wells
as part of the permit application. We also will discuss requirements for Class
V wells, and ideas of what to require for P&A in the permit.
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November 2001
P&A: OPERATOR'S
Burden, not EPA's
P&A is 100 percent the operator's
responsibility
Careful review and maintenance of plan
to be implemented is critical to ensure
EPA doesn't get stuck with the tab
Temporary cessation of injection may
not require P&A
While it may seem strange to think about how one should plug and abandon a
well before it even is drilled, the review and approval of this plan, and
ensuring money is in place to implement it, is critical. Historically, many
operators have walked away from "temporarily abandoned" wells and left the
state or Region with inadequate funds to properly plug the wells. The
Agency's already stretched budget then must cover costs that truly are an
operator burden.
Be certain that the permit very clearly specifies the responsibility to properly
close the well, regardless of well class. While a Class I vs. Class V closure
plan may be very different, the regulatory agency should not bear the cost of
closing even a shallow Class V well.
Temporary or intermittent cessation of injection is not "abandonment" for
purposes of deciding when plugging and abandonment is required. However,
if well operations cease for two years, the owner or operator is required to
plug the well in accordance with the approved plan. This two-year time
frame is in effect unless the owner/operator notified EPA and describes
actions or procedures that are satisfactory to the Agency, demonstrating that
the well will not endanger USDWs during this temporary abandonment
period (40 CFR 144.52(a)(6)). This requirement regarding the two-year
cessation of operations, with the option to continue to leave the well
temporarily inactive with Agency approval, should be included in the terms
of the permit.
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November 2001
Requirement for P&A
Plugging must occur in a way that will
not allow movement of fluids into or
between USDWs
Must use cement
- Class III wells may use other plugging
materials with EPA approval
Temporary cessation of injection may
not require P&A
As with all UIC activities, plugging and abandonment must be conducted in a
manner that is protective of USDWs. 40 CFR 146.10 requires that Class I, II
and III UIC wells be plugged with cement "in a manner which will not allow
the movement of fluids either into or between underground sources of
drinking water."
EPA may allow plugging material other than cement if the owner/operator
demonstrates to EPA's satisfaction that the proposed materials will prevent
movement of fluids into or between USDWs.
The reader should refer to the section on cementing in this training course to
gain insight into appropriate types of cement, methods of cementing and
other technical information regarding cement.
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November 2001
Plugging Methods
Cement plugs emplaced in the well
by:
- Balance method
- Dump bailer method
- Two-plug method
- Alternative approved method
Specific means of plugging the well are listed in 40 CFR 146.10:
* Balance method;
* Dump bailer method;
> Two-plug method; or
* Alternative approved method that will reliably provide a comparable level of
protection to USDWs.
Briefly, we will define what these methods are. Additional resources, such as Region
5's Guidance #4 on Plugging and Abandoning Injection Wells, may be reviewed for
more detailed information on this and other plugging and abandonment topics.
Balance method: This technique involves setting a viscous mud pill or mechanical
plug at a required (predetermined) depth. The necessary quantity of cement is
pumped down the drill pipe or tubing and displaced until the level of cement is the
same both inside and outside the pipe. The pipe or tubing is then pulled slowly from
the cement slurry, leaving the plug in place. Cement volume and heights of fluid
need to be determined beforehand to ensure an adequate and successful plug is set.
Dump bailer method: A cement basket, bridge plug or gravel pack-is placed below
the desired plugging location. A dump bailer containing a measured amount of
cement is lowered on a wire line, then dumped and raised to place a cement plug on
top of the plug or basket.
Two-plug method-. This method, used in open holes, uses a plug catcher into which
two separate plugs are injected. The bottom cementing plug is set first. As cement
continues to flow out of the string at the plugging depth, the annulus is filled. The
top plug is introduced into the cementing string. When it is caught by the plug
catcher, a sharp rise in cement pressure occurs at the surface, illustrating that the plug
catcher has been closed off.
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November 2001
Other Conditions
Well must be in static equilibrium
Class I, II and III permit must include
P&A conditions, with a plan submitted
by applicant. May include in Class V
permit
Plan must be submitted to EPA 30 days
prior to closure for large capacity
cesspool and motor vehicle waste
disposal Class V wells
The well to be plugged is required to be in a state of static equilibrium, with the mud
weight equalized top to bottom. This can be accomplished by circulating the mud in the
well prior to placing the plug(s). This requirement also is part of the P&A requirements
of 40 CFR 146.10.
40 CFR 144.51 (o) requires that Class I, II or III permits include conditions that meet the
plugging and abandonment requirements of 40 CFR 146.10. Class V well permits may
also include these requirements if EPA decides that it is appropriate. A plan must be
submitted for all large capacity cesspools and motor vehicle waste disposal wells being
closed, at least 30 days prior to scheduled closure. This gives EPA an opportunity to
review it and determine if the steps planned for closure of the Class V well are
considered adequate, given the hydrogeology of the site, wastes disposed and other
information. Keep in mind that techniques used for a deeper Class I, II or III well may
not be necessary to impose on an operator of a Class V well. Very simple cementing
may be allowed, but other issues, such as related piping being cleaned and removed,
may need to be addressed.
A plan is required to be submitted by the well owner/operator, addressing the
requirements of procedures for plugging the well. EPA reviews the plugging and
abandonment plan for adequacy.
State regulatory agencies in Direct Implementation states may have well plugging
requirements that are more stringent than EPA's UIC requirements. It is important that
the EPA's DI Program personnel coordinate with state personnel to ensure the plan
complies with all applicable regulations.
18-5
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November 2001
Plan Content
Provide details of proposed plugging
method
Demonstrate movement of fluids into or
between USDWs will not occur after
plugging
For Class V wells, sampling and
analysis may be necessary prior to
closure
The P&A plan must discuss the methods that will be used in the plugging and abandonment
procedures to protect USDWs. It must demonstrate that the proposed procedures will prevent
any migration into USDWs. In addition to discussing the specific method of plugging that will
be used, other information that should be discussed includes:
* Prior notification to EPA of intent to plug the well;
~ Pulling free casing, as applicable;
* Proposed depths of plugs (or discussion of cementing to surface as applicable);
* Proposed cement type and quantity;
~ Testing or logging that may need to be conducted prior to plugging (such as part II MIT
testing);
~ Surface restoration; and
* Reporting of P&A activities to EPA.
The prior notification and subsequent report are required by 40 CFR 144.51, and need to be
addressed in the plan. Often, EPA will want to have a technical person present to witness the
plugging activities.
At least 30 days prior notice must be provided to EPA for closure of Class V large capacity
cesspools and motor vehicle waste disposal wells.
Free (uncemented) casing usually will need to be cut and pulled from cased wells. Otherwise,
the annular space between the wellbore face and the casing will provide a potential migration
conduit to USDWs. In deciding what portions of free casing should be pulled, the protection of
USDWs needs to be the focal point. Consultation with other UIC personnel experienced in
dealing with this issue will be highly beneficial to the reviewer of the plan if this issue arises.
If the submitted plan meets the requirements of 146.10, it is incorporated into the permit. If not,
the permit writer should require the applicant to revise the plan, prescribe conditions meeting
the requirements, or deny the permit.
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November 2001
Costs of Plugging and
Abandonment
Permit application required to include
documentation of owner/operator's
financial ability to properly plug and
abandon the well.
Additional discussion of requirements
for financial demonstration provided in
Section 19.0 of this course.
The P&A plan ties directly into the section we discussed previously regarding financial
responsibility (Section 19.0). 40 CFR 144.52(a)(7) requires that the permittee
demonstrate and maintain financial responsibility and resources to close, plug and
abandon the UIC well until the well has been plugged and abandoned in a way
prescribed in the approved P&A plan and an abandonment report (required by
144.51(p)) has been submitted.
It is important that the P&A plan provide adequate information on volume of cement,
equipment, testing, and other equipment and materials proposed for closure of the well.
The permit reviewer can then acquire information on current market costs of these
materials and equipment, as well as labor, to determine if the cost estimate used for
financial responsibility documentation is adequate and realistic.
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November 2001
Additional Class IH
Requirements
Class IH wells have additional
requirements for well closure
40 CFR 146.71 lists the requirements
for closure
Post-closure plan also required for
Class IH wells as part of the permit
application (see 40 CFR 146.72)
Class I hazardous waste disposal wells are subject to slightly different requirements.
The basic concepts regarding the P&A plan are included in 40 CFR 146.71, which spells
out the requirements for a closure plan for these wells. In addition, a few other
requirements are included in this rule. If you are working on a Class IH permit, you
should review these requirements instead o/the P&A requirements of 40 CFR 146.10.
Also, Class IH wells are required to have post-closure plans submitted with the permit
application. The post-closure care plan deals with pressure changes in the injection
zone, waste front position at closure, status of any required corrective action, financial
assurance issues, as well as recordkeeping and notification to appropriate authorities and
deed notations to record information on the hazardous waste managed and injected at the
site.
The post-closure care plan is separate from the closure plan. 40 CFR 146.72 should be
closely reviewed when evaluating the adequacy of these plans.
18-8
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November 2001
Get It into the
Administrative Record
Documentation of verification of cement
quantity
Comments and responses
Updated plans submitted during
permitting process
It is a good idea to document in the administrative record that you verified the
calculations for adequate cement quantity, as well as any other calculations and
verifications conducted.
Along with all other plans that are part of the application, if you comment on them and a
new plan is submitted as a replacement, make sure you update the application and the
record demonstrates when the new version was submitted.
18-9
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November 2001
Lesson 19
UIC Financial
Responsibility
Owning and operating a UIC well is a costly venture that requires financial
stability from the beginning of the permitting process through closure of the
well and post-closure care, if applicable. An owner/operator must demonstrate
that funds will be available to properly close the facility and provide post-
closure care.
In order to demonstrate that he has the financial resources to operate a UIC
well, the owner/operator must use one or more of the financial assurance
mechanisms designed by EPA or the primacy State.
The topic of financial assurance documentation can become quite tedious, and
all aspects of each instrument will not be covered in this training course.
However, additional supporting information is available in the regulations,
EPA guidance and other materials available for reference.
In this section of the training we will discuss:
~ Why financial assurance is required;
~ What financial responsibility requirements apply to the different UIC well
classes;
* The different mechanisms that may be acceptable; and
~ The UIC permit writer's responsibilities for reviewing the mechanism and
instrument submitted by the owner or operator.
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November 2001
UIC Financial
Responsibility
Required for all permitted Class 1,11 and
III UIC wells (ง144.52(a)(7)); optional for
Class V wells, at Agency discretion
Most stringent requirements for Class I
hazardous waste disposal wells
Variety of different mechanisms
Separate and distinct from closure
authority (ง144.52(a)(9))
Financial assurance for UIC wells is required only for permitted wells in order to cover the costs
of closing, plugging and abandoning a well. No documentation regarding the owner's or
operator's ability to cover these costs is required for wells authorized by rule. This should not,
however, be confused with the regulatory agency's ability to require closure of any rule-
authorized well. At the expense of the owner or operator, the regulatory agency has the
authority to require closure of any well if it determines that the well poses an endangerment to
USDWs (see 40 CFR 144.12).
Financial assurance is a demonstration on the part of the owner or operator of a well that when
closure is necessary, funds will be available to permanently close the well in a way that is
protective of USDWs. Closure of the well may be necessary due to closure of a facility,
implementation of other disposal means, the well's useful life being reached, or problems with
the well.
* For deeper wells and for wells that have been used for disposal of hazardous waste, the
cost of closure is relatively high due to the volume of cement and the equipment necessary
to implement closure, as well as testing that may be required just before closure.
~ Closure requirements vary by well type, and closure requirements in the regulations
directly affect the cost. For example, shallow Class V wells may be able to be closed quite
simply, by backfilling from the surface with cement. Deeper, more "high-tech" Class V
wells may need more complicated closure and thus should be required to demonstrate
financial responsibility. Also, even shallow wells that inject wastes that, if system failure
occurred may cause significant contamination, should be required to implement these
requirements.
Post-closure requirements, including financial assurance, apply to all Class I hazardous waste
disposal wells, and may be applied to other wells if deemed necessary to protect USDWs.
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November 2001
Financial Responsibility
Regulatory Requirements
40 CFR 144.52(a)(7)
Basic requirement for
all Class I, II, III UIC
40 CFR 144.60-.70
wells
(Subpart F)
Specific requirements
for Class I hazardous
40 CFR Part 146
waste UIC wells
Reference to ง144.52
Financial responsibility
for post-closure for
Class I H
40 CFR 144.52(a)(7) provides the basic requirement regarding financial
responsibility:
"The permittee, including the transferor of a permit, is required to demonstrate and
maintain financial responsibility and resources to close, plug, and abandon the
underground injection operation in a manner prescribed by the Director [i.e., EPA
Regional Administrator or primacy agency Director],. .The permittee shall show
evidence of such financial responsibility to the Director by the submission of a
surety bond, or other adequate assurance, such as a financial statement or other
materials acceptable to the Director."
40 CFR Part 144, Subpart F (งง144.60-.70), establishes very specific financial
responsibility requirements that apply to Class I hazardous waste injection wells.
. 40 CFR Part 146, Subparts B, C and D, each has a requirement included in
"Information to be considered by the Director" regarding financial assurance. These
regulations state that prior to issuance of a permit to operate, construct or convert a
well to a Class I, II or III injection well, the Director must review and consider a
certificate that the applicant has assured (through a performance bond or other
appropriate means) the resources necessary to close, plug and abandon the well.
40 CFR Part 146, Subpart G, imposes requirements for post-closure financial
responsibility for Class I hazardous waste injection wells. Note that the financial
responsibility requirements for these wells are consistent with the financial
responsibility requirements under the Resource Conservation and Recovery Act
(RCRA) for hazardous waste disposal facilities.
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November 2001
Financial Responsibility
Requirements
Class II oil- and gas-related injection wells
-Acceptable options for Class II wells
- Specific information on each acceptable type
- Available on-line at:
http://www.epa.gov/r5water/uic/r5_02.htm
Specific information about financial assurance mechanisms that are acceptable for
Class II wells is provided in EPA's guidance entitled Federal Financial Responsibility
Demonstrations for Owners and Operators of Class II Oil- and Gas-Related Injection
Wells, dated May 1990 (Publication EPA 570/9-90-003).
This guidance is also available on Region 5's Web site at:
http://www.epa.gov/r5water/uic/ffrdooc2.htm
Financial instruments (surety bonds, letters of credit, and trust funds) and financial
statements are discussed as options for fulfilling the requirement for demonstration of
financial assurance for these well types.
Full coverage or blanket coverage may be options for Class II well operators as well.
Full coverage is an option in which the chosen instrument guarantees that enough
money will be available to close, plug and abandon each injection well owned or
operated. The amount of the instrument meets or exceeds the total cost per well.
For blanket coverage, the amount of the instrument is sufficient to plug an
appropriate number and acceptable proportion of the total number of injection wells
owned or operated in a project or by a company. The decision to allow blanket
coverage is at EPA's discretion, and the owner/operator needs to meet certain criteria
outlined in the guidance to qualify for this type of mechanism.
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November 2001
40 CFR Part 146 Class I H
UIC Requirements
Demonstrate resources for
closure and post-closure care
Assure financial responsibility
for closure
Assure financial responsibility
for post-closure care
Comply with specific post-
closure financial
requirements
40 CFR 146.70(a)(17) requires that the well owner or operator demonstrate to the Director, as
part of a permit application, that resources needed for closure, plugging and abandonment,
and post-closure care are available. The rule cross-references Part 144, Subpart F.
Closure requirements for Class I hazardous waste injection wells are provided at ง146.71.
The closure plan for Class I hazardous wells is required by this section of the regulations.
The plan must include financial assurance, and the estimated cost of well closure.
Post-closure care is required for Class I hazardous wells also, as established by ง146.72.
This section requires that a post-closure care plan be submitted by the well owner/operator.
Assurance of financial responsibility and a cost estimate for post-closure care are required to
be included in the post-closure plan. 40 CFR 146.73 requires that post-closure care financial
responsibility demonstrations meet all the standards established for closure in 40 CFR Part
144, Subpart F. Based on this, all the standards for closure financial responsibility also apply
to post-closure financial responsibility.
Though financial assurance is specifically required independent of the closure and post-
closure regulations (ง146.71 and ง146.72), it is tied closely to the closure and post-closure
plans. Cost estimates are part of the plans, and the mechanisms established to fulfill the
regulatory requirements for financial responsibility must cover all the costs provided in these
cost estimates. Further, the closure and post-closure plans, as well as financial responsibility
demonstrations, must be "acceptable" to the Director, and thus are subject to review and
approval by regulators.
The requirements to provide for closure and post-closure care survives the term of the permit
or cessation of injection and are enforceable regardless of whether the requirements are
conditions of permits (40 CFR 146.71(a) and 146.73).
ง146.70(a)(17)
ง146.71 (a)(3) '
ง146.72(a)(3) *
ง146.73
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November 2001
Permit Writer's
Responsibilities
Determine that the amount of assurance is
adequate
Determine that the type of mechanism is
appropriate
Determine that the wording of the instrument
complies with the regulations
Determine that all parts of the instrument are
in place
Decide if a permitted Class V well needs to
have financial assurance in place
Permit writers may be tempted to downplay this element of the permitting
process to some degree, as most permit writers are scientists and engineers, not
accountants. It may seem relatively unimportant, especially if the well
owner/operator is a large corporation that would appear to have plenty of
money to close a well. However, it is important that attention be paid to the
mechanism to ensure that when the time comes to close a well, the regulatory
agency is not stuck paying for it!
Permit writers have a responsibility to review four aspects of an applicant's
financial assurance submission:
* The amount of assurance;
* The type of mechanism used;
* The specific wording of the instrument;
* The completeness of the mechanism, especially when the selected
mechanism requires that a standby trust accompany it.
For Class V well permits, it is likely that if a permit is necessary, some type of
closure and financial assurance requirements may be appropriate to protect the
agency. The permit writer should consider the well depth and construction,
type of fluids injected, and other site-specific factors to make this evaluation.
Though permit writers may be somewhat intimidated initially by reviewing
these documents, staff in other programs (such as RCRA) with experience in
reviewing such documents may be able to provide some assistance.
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November 2001
Closure Plans and Cost
Estimates
Financial responsibility amounts are
directly related to cost estimates in the
closure and post-closure care plans
A variety of factors influence costs
- Inflation
- Well design changes (drilling out to
increase depth)
- Equipment costs
- Site-specific well issues
The basis for the financial assurance is the cost estimate, which is, in turn, based on the closure
(and post-closure) plan.
A number of factors can influence the validity of the cost estimate for closure and post-closure,
and thus the amount of the financial assurance mechanism. Inflation is one such factor. 40 CFR
144.62(b) requires that these cost estimates be adjusted every year, on a very specific schedule.
Due to well performance, well design changes may be made over time that will influence the cost
of closure. For instance, a well may be drilled out to increase the injection interval thickness,
deepening the well. If the change is significant enough, it will increase the cost of well closure.
The cost of materials and equipment needed for closure may vary over time. The cement, frac
tanks, rigs and other equipment, as well as personnel required to oversee the closure activities,
may change from the time a cost estimate is prepared. Though these costs generally will not
change very much from one year to the next, they may change significantly over the life of the
well.
Site specific circumstances influence the costs of closure and post-closure more than anything
else! The well depth, internal diameter, number of UIC monitoring wells on-site, pressure in the
well, and many other factors will determine how simple or complicated the closure and post-
closure will be, and will determine the cost of performing the required activities.
Since well permits are issued for anywhere from a few years to the life of the well (for some
Class II wells), costs of closure may change over time, based on the cost of materials, labor,
equipment, and other factors.
As cost estimates for closure and post-closure are updated, the financial assurance mechanism
needs to be reviewed to see if the amount of the mechanism is adequate to cover the total costs
anticipated.
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November 2001
Reviewing the Cost
Estimate
Review the cost estimate to determine
whether the amount of the financial
assurance is adequate
Ensure that all activities in the plan are
covered in the cost estimate
Ensure that costs are reasonable and
valid
The permit writer must review the cost estimate in conjunction with the
closure (and post-closure care) plan to ensure that all activities in the plan are
covered by the cost estimate.
It is also important to review the cost estimates to see if they are reasonable. If
two Class I nonhazardous well owners or operators for similar wells both
submit estimates at the same time, and closure costs are estimated by one at
$15,000 and by the other at $5,000, the regulator must determine whether
these estimates are "reasonable." He or she may need to request a breakout of
costs, showing estimated labor, equipment, materials, etc., to determine if the
costs make sense.
Some operators may overestimate the cost so they do not have to keep
updating the estimate every time it rises. Similarly, the financial assurance
instruments submitted are often developed for costs that exceed the truly
anticipated closure and post-closure costs, to avoid reissuance of the
instrument over time. Each reissuance may cost the owner or operator
additional money, so an inflated cost estimate may be used to provide a long
life to the instrument chosen.
Conversely, there may also be incentives to underestimate the costs in order to
reduce the owner/operator's financial requirements while the facility is
operating.
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November 2001
What Mechanisms Are
Allowed for Hazardous
Waste Wells?
Trust fund
Surety bond with standby trust
Letter of credit with standby trust
Insurance
Corporate guarantee
Financial test
There is no guessing about what is acceptable to satisfy financial assurance
requirements for Class I hazardous waste disposal wells! The regulations are
extremely specific regarding the wording, timing, and means to implement the
various mechanisms listed in Subpart F of 40 CFR Part 144.
Significant details regarding language, methods for cancellation, schedules of
submission, and additional information specific to each mechanism are
included in the regulations. It is important that you reference the regulations
and review these details when you review an instrument submitted by an
owner/operator.
Remember that Subpart F requirements apply to financial assurance for both
closure and post-closure care for Class I hazardous waste disposal wells.
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November 2001
What Mechanisms Are
Allowed for Class II
Injection Wells?
Surety bond with standby trust
Financial guarantee bond
Performance bond
Letter of credit with standby trust
Irrevocable trust
Financial statement
Each instrument that is acceptable for Class II wells is discussed in the EPA
publication Federal Financial Responsibility Demonstrations for Owners and
Operators of Class II Oil- and Gas-Related Injection Wells.
The mechanisms that may be acceptable for Class II wells are:
* Surety bond with standby trust fund;
* Financial guarantee bond with standby trust fund;
* Letter of credit with standby trust;
* Irrevocable trust fund; and
* Financial statement (financial test).
It is important to realize that the use of a bond or letter of credit always
requires a standby trust fund to be in place.
It is important for a Class IIUIC well owner/operator to know whether full or
blanket coverage can be used for his or her wells. EPA must be consulted to
determine this, since allowing blanket coverage is discretionary. Use of the
Federal guidance document will assist both permit writers and
owners/operators to decide what options exist for the wells in question, based
on the pointers laid out in the guidance document.
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November 2001
What Mechanisms Are
Allowed for Other Injection
Wells?
Surety bond
Other adequate assurance
- Financial statement
- Other materials
As touched on previously, the minimum financial assurance requirements of
the Federal regulations for UIC wells other than Class IH and Class II do not
specify a list of instruments that would be "acceptable to the Director."
A surety bond or a financial statement are the only two items specifically
listed. Thus, for other permitted injection wells, the Director has a great deal
of latitude regarding what is permissible. As noted before, however, most
permit writers are not experts in this area, and thus may not be comfortable
deciding what is "acceptable."
Since the regulations for Class I hazardous waste injection wells and guidance
for Class II wells are very specific regarding what is deemed acceptable, they
can be used as models for other well types if the permit writer so chooses. The
language may need to be modified somewhat, for instance to eliminate
references to hazardous waste as stated in the Class IH regulations. Otherwise,
the basic elements are established and available for use.
This does not prevent the use of other means of establishing financial
assurance, however, if the owner or operator is able to satisfy the regulatory
agency that its submission guarantees that money will be available to cover
closure costs on closing the well.
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November 2001
Which One to Use?
The owner/operator chooses which
mechanism to use
The selected mechanism may be changed at
any time with EPA's approval
An established instrument is not terminated
by the Director until a new instrument is in
place and approved
The owner or operator of the well will submit the financial assurance
instrument as part of a permit application. The instrument is reviewed and
determined to be adequate or inadequate by the regulatory agency. If it is
found to be inadequate in language, the Agency will issue comments to
indicate this. However, in some instances the owner or operator may not be
able to meet the criteria required by rule for certain mechanisms. In this case,
the choice of that mechanism is eliminated and the regulatory agency will
have to tell the owner or operator that the chosen mechanism cannot be used.
The owner or operator may chose a different mechanism at any time with the
Director's permission, based on the company's business structure, costs of the
mechanism, or other factors that may not be revealed to the reviewer. As long
as the standards of the rule are met, any of the mechanisms listed may be used.
The existing instrument is not terminated, however, until a new instrument that
has been deemed acceptable by the regulatory agency is in place. The means
of terminating an existing instrument and circumstances under which the
termination is allowed are listed at the end of the discussion of each
mechanism in ง144.63.
If EPA has reason to believe that the instrument in place is no longer adequate
to cover the cost of closing, plugging and abandoning the well, 40 CFR
144.28( c)(3) provides the authority for the Agency to require a revised
demonstration be submitted.
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November 2001
Reviewing the Mechanism
Does the company meet the
requirements for the type of mechanism
selected?
Is the stand-by trust established where
required?
Has the mechanism been set up
properly?
The permit writer needs to review the mechanism to ensure that it is
appropriate for the company and that it has been set up correctly.
For example, a company must meet certain financial requirements in order to
use the financial test or to provide a corporate guarantee. Certain mechanisms
require the owner/operator to establish a stand-by trust fund.
Permit writers should consult guidance, more experienced permit writers
(including those in other programs), or Regional Counsel to help with the
complicated technical or legal aspects of reviewing the financial mechanisms.
The guidance documents listed below may be helpful in reviewing these
documents.
* Federal Financial Responsibility Demonstrations for Owners and
Operators of Class II Oil- and Gas-Related Injection Wells, May 1990.
* Guidance for Financial Responsibility in Federally-Administered UIC
Class II Programs, March 29,1989.
* Guidance for Financial Assurance for Federally-Administered UIC
Programs, May 29,1985.
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November 2001
Wording of Instruments
40 CFR 144.70 provides the EXACT
wording for Class I H instruments
Applies to instruments for closure and
post-closure care
Wording, including punctuation, must be
in compliance
Wording may be used as a guide for
instruments for other well classes
We have mentioned before, but need to stress again, that the wording of the
instruments is critical. Because these are detailed, legally binding documents,
the exact wording of the regulatory language in 40 CFR 144.70 must be used.
This is true for both closure and post-closure financial assurance instruments.
40 CFR 146.73 requires that post-closure care financial assurance meet the
specifications for the mechanisms and instruments in 40 CFR Part 144,
Subpart F. The wording merely needs to be revised to cover post-closure care
as well as closure.
A word-for-word comparison should be made for each instrument against the
wording in the regulations.
To ensure that nonhazardous waste wells have acceptable financial assurance,
you may want to use the language of these instruments as a basis for the
financial assurance for nonhazardous waste UIC well owners or operators.
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November 2001
Release from Financial
Assurance
Completion of closure (or post-closure)
according to the approved plan must be
certified by an independent professional
engineer prior to the release
The obligation to maintain financial
assurance survives the permit
termination and cessation of injection
Based on 40 CFR 144.63(i), a well owner/operator may only be released from
the requirement to maintain financial assurance by the Director. An official
notification must be sent releasing the owner/operator from the requirement,
once the Director is satisfied that the closure and post-closure plan have been
complied with fully. The completion of required closure and post-closure
activities must be certified by an independent professional engineer.
The Federal guidance on Class II financial assurance states that financial
assurance mechanisms may only be canceled with the written consent of the
EPA Regional Administrator or the UIC Program Director.
Neither the completion of closure, the cessation of injection into a well, nor
the termination of a permit release the owner or operator of a hazardous waste
disposal well from maintaining financial assurance. Only the regulatory
agency may release the owner/operator from the requirement to fulfill this
regulatory obligation.
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November 2001
Administrative Record
Final approved financial assurance
mechanism
Documentation illustrating how review
determined submission meets
requirements
The final approved financial assurance mechanism should be documented in
the administrative record of the permitting action. The original document may
need to be stored elsewhere, based on Regional policy, but a copy may be
inserted in its place.
Evidence of the Agency's review and determination that the mechanism is
adequate should also be placed in the record.
You may want to avoid specifically listing the approved mechanism in the
permit itself. If the operator changes mechanisms during the term of the
permit, you may need to conduct a permit modification. Leaving the specific
mechanism out of the permit keeps you from creating that additional work for
yourself and the applicant. The permit definitely should, however, indicate the
requirement to maintain an approved mechanism for closure of the well.
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November 2001
Lesson 20
Public Participation
in the Permitting
Process
DRINKING
WATER
ACADEMY
40 CFR 144.1(f)(3) requires that UIC permits be issued following the
procedures in 40 CFR Part 124, which provides the procedural rules for
EPA's UIC, RCRA, NPDES and other permitting programs.
It is important to follow the public participation procedures carefully. EPA's
policy is to inform the public and maintain open communication channels on
issues of concern. Also, if these procedures are not followed, they may
become an issue in a contested permit. States follow an issuance process very
similar to the Federal process described here.
Many Regions have guidance or other helpful documents that walk you step-
by-step through the public participation process for permit issuance or
reissuance. You should refer to these documents as you develop a permit or
permit renewal. It hurts the Agency's credibility and wastes resources if a
permit has to go through the public participation process more than once
because proper procedures were not followed.
Always feel free to have an experienced permit writer double-check your
steps as you prepare all the documentation and work through the steps
described here. The public desires and has a right to timely, accurate
information about UIC facilities. An experienced permit writer can help
make sure that little steps that mean a great deal to the public are not
overlooked.
Please note that the process for issuing an emergency permit is different from
that described in this section. If you must issue an emergency permit, you
should work closely with other experienced UIC staff, and refer to 40 CFR
144.34 for rule requirements.
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November 2001
Public Participation in
UIC Permitting (40 CFR Part 124)
Applicant
submits
application;
Agency
starts admin,
record
Issue
notice of
intent to
deny
Mall
schedule
to
applicant
Review
application,
draft permit
Prepare
statement
of basis,
public
notice
Review
comments,
prepare
responses,
develop
final permit
Issue final
permit
decision
and
response
to
comments
Complete
adminis.
record
Permit
effective
In 30 days
unless
appealed
and
stayed
Only minor modifications of permits, as defined in 40 CFR 144.41 are
exempt from the public participation requirements of 40 CFR Part 124.
Please keep in mind that the "public" in the regulations includes not only
people in the community around the UIC facility, but any other interested
party and the permit applicant as well. Anyone and everyone is able to have a
say in the permitting decision. However, the ultimate decision must be based
on the regulations applicable to the particular UIC well, not on well-
intentioned public sentiment or corporate interests that are not based on
protection of USDWs and public health.
The first step in the permit application review is ensuring that the application
is complete. This means it includes all the elements required (the basic
application plus all attachments) completed. "Complete" is defined in 40
CFR 144.31(d). If the application is incomplete, the reviewer develops and
sends a Notice of Deficiency (NOD) and the applicant must respond.
Generally, there is a difference between a complete application versus one
that is completely adequate technically. All the parts may be there, but
additional detail may be required even once the application is "complete".
The reviewer needs to make sure that the applicant did not make a claim of
confidentiality for all or part of the application. If this claim is made, it must
be done according to the requirements of 40 CFR 144.5, and EPA cannot
release the confidential information to the public.
Let's assume that no part of the application is claimed as confidential and that
the application submitted is "complete" as defined in the rules. We will now
walk through the steps that must be completed to act on the application by
issuing a permit. 20-2
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November 2001
Administrative Record
The record for the decision made on a UIC
permit application must be kept and made
available to the public
Includes all documents associated with
decision making process
- Draft permit
- Statement of basis
NODs
Comment letters
and responses
Other
correspondence
Applicant
submits
application;
Agency
starts admin,
record
Mail
schedule
to
applicant
The administrative record is started on receipt of the applicant's permit
application. The administrative record is an extremely important document.
If the permit is contested, the agency is allowed only to use documentation in
the administrative record to justify its permit decisions. The permit writer
needs to carefully document the entire permitting process to ensure that the
record is thorough and complete.
The administrative record for a draft permit includes documents listed in 40
CFR 124.9, including the permit application and any supporting data the
applicant submitted, the draft permit, the statement of basis or fact sheet, and
any other documents that are cited in the statement of basis or fact sheet or
used in support of permit development (such as maps or geologic articles).
The administrative record is required to be maintained by the regulatory
agency. It must be made available for public comment when the draft permit
is issued (ง 124.6(e)) and for public review when the final permit decision is
made (ง124.(8)).
After receipt of an application from a major new UIC well, the "Director"
must mail the applicant a project decision schedule that includes target dates
for major permit milestones (ง 124.3(g)). ("Director" means the State UIC
program director for a UIC primacy State or the EPA Regional Administrator
for a Direct Implementation State.)
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November 2001
To help inform the public of the UIC activities at a facility, a fact sheet is prepared
by the regulatory agency and distributed to the public. 40 CFR 124.8 requires that
a fact sheet be developed by the regulatory agency for every draft permit for a
major facility, and for every draft permit which the Director finds is the subject of
widespread public interest, or which raises major issues. What do "widespread"
and "major" mean? Work closely with your supervisor to help you determine
what sites and issues merit use of these terms.
The fact sheets are required to contain certain information listed in 40 CFR 124.8,
such as a description of the facility, type and quantity of fluids to be injected, a
summary of the basis for the permit conditions included in the draft, procedures
that will be used to make a final decision, and information on the public comment
period and hearing.
A statement of basis must be prepared for every draft permit for which a fact sheet
is not prepared. The statement of basis contains a brief description of the facility,
the permit conditions and how they were derived (ง124.7).
Some Regions may use the statement of basis in place of a fact sheet. The title is
not what matters nearly as much as the content of the document, which is intended
to educate the public about the injection facility.
The fact sheet or statement of basis is mailed to the applicant and, on request, to
any other person. It may also be distributed at a public information meeting or may
receive a wider distribution through the mailing list that is maintained by the
regulatory agency. The primary goal is to reach as many people as possible
through this and all other notices sent to the public.
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November 2001
^ Issue draft permit or
notice of intent to deny
Draft Permit Issuance
Draft permits must be announced
through a public notice
Opportunity for a public hearing must be
provided
A final permit decision must be
accompanied by a response to any
comments submitted on the draft permit
Since the application has been deemed complete, the agency prepares a draft
permit or a notice of intent to deny the permit. For procedural purposes, a
notice of intent to deny is considered a form of draft permit and the same
administrative requirements apply. We will assume that a draft permit is
being issued.
The draft permit includes permit conditions applicable to all permits (40 CFR
144.51 and .52); compliance schedules, as necessary (ง144.53);
recordkeeping, reporting and monitoring requirements (ง144.54); and other
requirements and limitations as established in 40 CFR Parts 144 and 146.
Additional details about draft permits are provided in 40 CFR 124.6.
Most Regions have boilerplate permits for each well class that you can use as
a starting point in developing the draft permit. Language is modified to be
site-specific, and any special conditions that are necessary based on site
conditions and the need for protection of USDWs are inserted as well.
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November 2001
Public Notice
Public notice prepared and published.
Must allow at least 30 days for public
comment once draft decision has been
made on the permit application
Describes draft action, where draft can
be reviewed, invites comment
The notice may include details of a
public hearing, if one has been
scheduled
Decisions to deny a permit, issue a draft permit, grant an appeal, and schedule
a public hearing are required to be published in a public notice. 40 CFR
124.10 lists the requirements for public notice and a public comment period.
For our draft permit example, a public notice is issued, usually through the
Branch Chief. This announcement provides the public an opportunity to be
aware of the action, review the draft permit and supporting documents, and
provide comments on the draft.
* Any interested individual may submit written comments on the draft
permit. These comments may support the permit action as prepared, or
may object to various conditions or language in the draft permit.
^ The Director responds to any comments prior to issuing a final permit
action.
The public notice is actually prepared as part of the Statement of Basis in
some cases. It must allow at least 30 days for public comment on the action
described. Also, public notice of a public hearing is required to be given at
least 30 days before the hearing. Public notice of the draft permit and of a
public hearing may be combined in one notice. If a hearing is scheduled later
due to public interest, another 30 day prior notice must be issued.
Mailing the notice to persons on a mailing list, the permit applicant, various
agencies, and local governing bodies, as well as publication in a newspaper,
are methods used to circulate the public notice.
Given the timing of the public notice requirements and preparation of the
various documents for public review, good planning and careful timing are
required to ensure that the rule requirements are met.
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November 2001
Public Hearing ^
Hold
public
hearing
-
Opportunity to provide written or verbal
testimony on the draft action
May be scheduled in advance or
requested during the public comment
period
The Director must hold a hearing if
there is "a significant degree of public
interest" in the draft permit
We have mentioned a public hearing several times. The hearing provides an
opportunity for interested persons to submit comments for the administrative
record either verbally or in writing. Written comments may be submitted by
mail using the procedures noted in the public notice of the draft permit action.
However, an individual or group of individuals may wish to speak to EPA
representatives about the action and request a public hearing.
The Director is required to hold a hearing if "a significant degree of public
interest" is generated regarding the draft permit. This may be just one
individual requesting the meeting, or a larger number of requests may be
required at the Director's discretion - the decision to hold or not hold the
hearing is up to the Region, but must be defensible given the procedural
regulations. EPA wants to seek out and be sensitive to public concerns. Each
Region has its own method of addressing the term "significant," so work
closely with your supervisor to determine whether a hearing is needed. The
Director may also schedule a hearing without a request from the public if he
or she believes the hearing will clarify the permit action.
You should note that EPA does not respond to questions or comments during
a public hearing. It is a formal session with designated roles for individuals
to preside over it. A transcript is made of all comments.
* EPA responds to questions and comments from interested parties at a
public information meeting (information session).
~ Records from a public hearing are maintained for the permit
administrative record. No such records are included for a public
information session.
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November 2001
Response to Comments
The comment period may be extended or
reopened
The agency responds to all public comments
received during the public comment period
when it issues a final permit decision
The response to comments is part of the
administrative record and must be made
available to the public
The applicant and all other individuals who believe any permit condition is
inappropriate are obligated to raise issues and submit arguments in support of
their position during the public comment period (see 40 CFR 124.13).
Depending on what issues arise, it may be necessary to extend the comment
period beyond 30 days, or reopen the public comment period. Specific
procedures for reopening the public comment period are provided in 40 CFR
124.10.
After all comments have been received and evaluated, the Agency makes a
final permit decision. At the time that the final decision is issued, a response
to comments must be prepared and distributed according to the procedures
listed in 40 CFR 124.17.
All changes made from the draft permit compared to the final permit must be
explained in the response to comments. Also, a brief description of
significant comments received during the public comment period and a
response to those comments must be included. The response to comments is
part of the administrative record for the final permit and must be made
available to the public. Often, the Agency sends the response to comments by
mail to the list of attendees of the public hearing and other commentors.
The administrative record for the final permit (ง 124.18) must include the
draft permit, all comments received during the public comment period, the
tape or transcript of any hearing held, any written material submitted at a
hearing, the response to comments, any other documents that support the
permit (such as correspondence or data submittals), and the final permit.
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November 2001
Permit Appeals
The public may appeal the final
within 30 days
Appeals may be filed by the permit
applicant or any interested person - as
long as they commented during the
public comment period or participated in
the public hearing
Permit effective
in 30 days
unless
appealed
and stayed
action
Briefly, to review, the public is notified of a draft action, can comment during
the published public comment period, can testify at a public hearing, and can
review all the materials in the administrative record of the permit. There is
still one more way the public can participate and affect the action, even after
a final action has been issued ~ by appealing the decision.
The final permit decision is effective 30 days after issuance unless a later date
is specified or review is requested (an appeal) under ง124.19. The permit
may also be immediately effective if no commenters requested changes from
the draft permit. Any appeal must be made within 30 days of the notice of the
Director's final action issuing the permit (or denial).
If a request for review is granted, the effect of the contested conditions is
"stayed" - that is, put on hold - pending final agency action. If the permit is
for a new facility, it cannot commence operation pending final agency action.
Only the contested conditions of the permit are stayed; all others must be
complied with on the effective date of the permit.
We often think of the permittee as being the one who would appeal a permit
decision, filing a complaint that certain conditions are unreasonable or
beyond the agency's bounds of authority. But anyone who participated in the
public hearing or commented during the public comment period can appeal a
permit. They are limited, however, to appealing the issues they raised in their
comments. For instance, a person who commented only on the operating
pressure of the well cannot then appeal the waste stream constituents allowed
by the permit. Also, any changes that were made from the draft to the final
permit can be appealed by anyone.
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November 2001
Unpleasant Surprises
Other issues that can arise
- Highly political sites
- New information at the last minute
- Public claiming lack of information
Anticipating issues and planning well
can alleviate many of the problems and
headaches!
There are many headaches and problems that can arise from the time a draft
permit is issued until it is final and the appeals deadline is passed. It is not
uncommon for EPA to be in a position where it cannot satisfy both the
regulated entity and the interested public at large. Some UIC permits, like
any other Agency action, become embroiled in political arguments or other
scenarios that can difficult to manage.
This is why it is so important to anticipate the issues that are likely to arise
and plan for them. For an existing site, have there been recent or historical
controversial issues that keep coming up? Be ready for them by preparing a
scientifically and regulatorily sound response, even if the issue is not really
about the UIC well permit. Check and double check that you have covered
all the bases required in preparing the statement of basis or fact sheet,
properly public noticing the action, and mailing the notice to all the interested
parties on the mailing list. Verify that the newspaper did in fact publish the
public notice - sometimes they do not, or it is published late. If your schedule
is tight, this can disrupt the process by causing you to have to change the date
of the public hearing and end of the public comment period.
There are many other details about how the newspaper ad is placed, who
maintains a mailing list, how you should format the statement of basis and
public notice, and so forth. Be certain to coordinate with your supervisor and
experienced permit writers and you can follow the right procedures. This
helps maintain your own and your Branch's credibility!
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November 2001
Lesson 21
Summary and
Conclusions
We have covered a tremendous amount of material in this course. We have
a few more points, then we will review some applications and permits and
discuss further the ways you can implement what we have covered.
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November 2001
Additional Conditions
Additional conditions may be
established on a case-by-case basis
-To prevent migration of fluids into USDWs
-To assure compliance with all applicable
requirements of SDWA and the UIC
regulations
In addition to all the things that have been covered in the last 21 sections of
this course, there is one final permitting point we need to cover. It is a bit
of a "catch-all" - the Director has the authority to impose additional
conditions through a permit on a case-by-case basis.
The authority for these additional conditions is found in 40 CFR
144.52(a)(9).
Conditions may be added "as necessary to prevent the migration of fluids"
into USDWs, and to "provide for and assure compliance with all applicable
requirements of the SDWA and [40 CFR] parts 144,145,146 and 124."
The rule also defines what an "applicable requirement" is, for both EPA DI
programs and primacy State programs.
This authority provides the permit writer with one final opportunity to insert
permit conditions as necessary where all the other conditions may not be
specific or stringent enough. For instance, if ground water monitoring is
determined to be essential at a site to ensure USDWs are protected, it can be
required under this authority.
It is important to exercise this option with care, however, as requirements
not specifically spelled out in the regulations are often appealed by the
permittee. As with any other permitting decision, make sure you have a
strong technical justification for any conditions developed under this
authority.
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November 2001
Hearing versus Doing
Course content is focused on the key
elements of permitting
Site-specific conditions may introduce
additional issues not addressed in detail
in this course
The content of this course was based on the key elements that are required
to be addressed in a permit application for a Class I, II or III well. Many of
the topics are also applicable to Class V wells that are required to be
permitted.
However, site-specific conditions will often arise that are not addressed in
detail in the course materials provided in these slides and notes.
Additional reference materials are provided in the appendices to this
manual. You should familiarize yourself with them, so you can reference
them later as the need arises.
EPA has produced a large number of guidance documents that will be
valuable references when dealing with permitting issues. You can view a
list of all available guidance documents on the Web at:
~ www.epa.gov/OGWDW/uic/uicguid.html
* If the guidance document you need is not available through a link,
check with others in your Region to see if they have copies.
We have noted repeatedly that experienced co-workers are a great resource
for information. Members of the national UIC Technical Workgroup can
also be contacted for a variety of questions. Your Region has a member on
the Workgroup who can answer your question or put you in touch with
other members across the country with diverse areas of expertise.
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November 2001
Conclusions
Consult other technical resources (see
appendices to this training manual)
Ask questions of the owner/operator
Use a team approach to deal with areas
that are new to you
A variety of other technical resources are listed in the appendices to this
training course. Many of the topics we covered are highly technical, and
additional training in some of these areas (either formal or informal) may be
necessary.
The owner/operator submitting the application should be able to answer
many questions regarding the specifics of the proposed well and operations.
Definitely ask for additional information where the application is not clear
or does not provide enough specific detail. The permit needs to be as clear
as possible about how the well will be constructed, operated, maintained
and monitored.
Use a team approach by utilizing the experience of others, not only in UIC
but also in other programmatic areas that are relevant, to deal with
permitting issues that are not familiar to you.
It is to everyone's advantage to have a clear and strongly enforceable
permit. The owner/operator needs to know what is and is not allowed, and
the conditions of the permit need to ensure that USDWs are protected.
Refer often to resources such as this training manual and your co-workers,
and you should be able to master the art of effective permitting!
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