EPA 68-06389
JULY 1984
UIC INSPECTION GUIDE
US EPA REGION III
PREPARED BY
KEN E. DAVIS ASSOCIATES
KEDA PROJECT 84-383
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EPA REGION III
UIC INSPECTION GUIDE
EPA CONTRACT NO.
68-06389
SUBMITTED TO:
DR. RICHARD TINLIN
ENGINEERING ENTERPRISES, INC.
AND
MR. GEORGE HOESSEL
WATER SUPPLY BRANCH EPA REGION III
PREPARED FOR:
ENVIRONMENTAL PROTECTION AGENCY (REGION III)
PREPARED BY:
KEN E. DAVIS ASSOCIATES
KEDA PROJECT 84-383
JULY 19, 1984
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TABLE OF CONTENTS
1.0. INTRODUCTION 1- 1
1.1. Purpose of Inspection Guide 1- 1
1.2. Scope of Inspection Guide 1- 1
1.3. How To Use Guide 1- 3
2.0. REVIEW OF INSPECTION REQUIREMENTS 2- 1
2.1. Overview of Regulatory Criteria, Authority
for Inspections, and Priorities of Region III . . . 2- 1
2.2. Kinds of Inspections 2-12
3.0. INSPECTION PRACTICES 3- 1
3.1. Types of Wells in Region III 3- 1
3.2. Emergency or Non-Compliance Inspections 3-13
3.3. Preoperational Inspections 3-29
3.4. Mechanical Integrity Test Inspections 3-55
3.5. Plug and Abandonment Inspections 3-77
3.6. Class IV Closure Inspections 3-102
3.7. Routine Operational Inspections 3-111
4.0. MONITORING METHODS AND PROBLEMS 4- 1
4.1. Equipment and Instrumentation 4- 1
4.2. Trouble Shooting, Analysis and Interpreting
Well Problems 4-16
5.0. GENERAL TECHNIQUES FOR EFFICIENT INSPECTIONS. ...... 5- 1
5.1. Legal Responsibilities 5- 1
5.2. Investigative Techniques and Procedures 5- 3
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5.3. Maintenance of Samples 5-17
5.4. Dealing with the Uncooperative Owner/Operator ... 5-19
5.5. Inspection Report 5-22
6.0. FIELD SAFETY 6- 1
6.1. Personal Protective Equipment 6- 1
6.2. Potential Hazards 6- 7
6.3. Chemical Hazards and Procedures 6-11
7.0. BLOWOUT PREVENTION AND CONTROL OVERVIEW 7- 1
7.1. Primary Control 7- 1
7.2. Secondary Control 7- 3
7.3. Tertiary Control 7- 8
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FIGURES
3.1. UNDERGROUND INJECTION CONTROL PROGRAM CLASSIFICATION OF WELLS
3.2. GENERALIZED SCHEMATIC DIAGRAM OF GEOPHYSICAL WELL-LOGGING
EQUIPMENT
3.3. FRICTION PRESSURE LOSS vs INJECTION RATE FOR COMMON TUBING AND
CASING SIZES
3.4. NOISE LOG SENSING HIGH FLOW RATE BEHIND CASING
3.5. EXAMPLE OF TEMPERATURE LOG SHOWING TOP OF CEMENT
3.6. EXAMPLES OF TEMPERATURE LOGS SHOWING THE NATURAL GEOTHERMAL
GRADIENT AND ANOMALIES CAUSED BY FLOW THROUGH A CHANNEL BEHIND
THE WELL CASING
3.7. RADIOACTIVE TRACER LOG SHOWING DETECTION OF A LEAK IN CASING AND
SUBSEQUENT FLUID MOVEMENT IN A CHANNEL BEHIND THE CASING
3.8 MONOELECTRODE PROBE FOR WATER LEVEL DETECTION
3.9. TYPICAL CLASS II INJECTION WELL (RECENT)
3.10. TYPICAL CLASS II INJECTION WELL PRIOR TO C. 1972
3.11. TYPICAL CLASS II INJECTION WELL C. 1972-1983
3.12. TYPICAL CLASS II INJECTION WELL C. 1981-1984
3.13. COMMON WELL CONFIGURATION AFTER WELL PREPARATION
3.14. PLUG LOCATIONS IN A WELL WITH INSUFFICIENT SUFFACE CASING
3.15. TWO PLUG METHOD SCHEMATIC
3.16. DUMP BAILER METHOD OF PLACING CEMENT PLUG
3.17. EPA DISPOSAL/INJECTION WELL MONITORING REPORT FORM
3.18. INJECTION WELL MONITORING REPORT FORM 7520-8
4.1. TYPICAL WELLHEAD INSTRUMENTATION CLASS I WELL
4.2. TYPICAL WELLHEAD CLASS II WELL
4.3. CONTINUOUS MONITORING INJECTION TEMPERATURE/ANNULUS PRESSURE-
TWENTY-FOUR HOUR RECORD
4.4. CONTINUOUS MONITORING INJECTION PRESSURE/RATE OF FLOW/
ANNULUS PRESSURE - SEVEN DAY RECORD
5.1. PRESENTING NOTICE OF INSPECTION
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TABLES
3.1. EPA REGION III PRIMACY STATUS
3.2. INJECTION WELL INVENTORY PENNSYLVANIA
3.3. INJECTION WELL INVENTORY VIRGINIA
3.4. WELL LOGGING METHODS AND USES
3.5. SOME GEOPHYSICAL WELL LOGGING SERVICES AVAILABLE FROM THREE
COMPANIES PROVIDING WELL LOGGING SERVICES
3.6. CHECK-LIST FOR PLUGGING AND ABANDONMENT
3.7. CERTAIN CLASS IV WELLS IN PENNSYLVANIA
3.8. CAPACITY OF HOLE
4.1. CLASS I WELL PROBLEMS RELATED TO ABANDONMENT IN PENNSYLVANIA
5.1. INSPECTOR RESPONSIBILITIES IN THE INSPECTION PROCESS
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APPENDICES
APPENDIX A - WELL DIAGRAMS ILLUSTRATING PLUG LOCATIONS
APPENDIX B - BASIC BALANCE PLUG OOB
APPENDIX C - PUMP DISCHARGE PRESSURE AND VOLUME DATA
APPENDIX D - SAMPLING CONTAINERS, PRESERVATION AND
ANALYTICAL PARAMETERS
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INTRODUCTION
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The Guide approaches the issues of inspections within the
conceptual framework established in Region Ill's UIC Inspection
Strategy.
After reviewing the general inspection requirements and priorities
in Chapter 2, specific inspection practices are covered in Chapter 3.
Chapter 3 includes important technical aspects of UIC inspections
related to prestart-up operations, mechanical integrity testing,
plugging and abandonment, routine operational and emergency situations.
Monitoring methods and techniques for efficient inspections are
presented in subsequent Chapters 4 and 5. The guide also covers field
safety (Chapter 6) with particular reference to equipment, chemical
hazards and blowout prevention (Chapter 7).
Information presented in this manual should provide a qualified
and experienced inspector with the basic guidance necessary to complete
an accurate inspection. New personnel will find the techniques
discussed in the Guide most useful when coupled with other more basic
publications. The inexperienced user of the guide should be familiar
with and have the following references available:
An Introduction to the Technology of Subsurface Wastewater
Injection, (EPA-600/2-77-240), December 1977.
Injection Well Construction Practices and Technology, Prepared for
the USEPA Office of Drinking Water under Contract No. 68-01-5971,
October 1982.
Other references are cited at the end of each chapter.
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1.0 INTRODUCTION
1.1 PURPOSE OF INSPECTION GUIDE
The Underground Injection Control (UIC) Program is the direct
responsibility of US EPA in those states which have not elected to
pursue regulatory primacy. In Region III the States of Pennsylvania,
Virginia and the District of Columbia have declined primacy. An
integral element of the Direct Implementation effort in these states
will be EPA's field inspection operations which will be the key to the
success of the Region's compliance and enforcement activities.
This Underground Injection Control (UIC) Inspection Guide has been
developed to support Region III inspection personnel conducting these
activities. The information contained in this Guide is comprehensive
and is designed to provide inspectors with standardized procedures for
conducting inspections. The Guide recommends procedures and guidelines
for applying established techniques to the specific tasks of the UIC
inspector.
1.2 SCOPE OF INSPECTION GUIDE
The UIC Inspection Guide has been organized in seven chapters
which outline the responsibilities of EPA Inspectors and technical
Issues to be addressed during field visits. The Guide also provides a
basic overview of Inspection techniques and safety considerations. The
central focus of the document is Class II, oil and gas enhanced
recovery injection operations, but variations of procedures for other
Classes of operations are covered as well.
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1-3 HOW TO USE GUIDE
The specific types of inspections required in Region III are
discussed in detail in Chapter 3. This chapter outlines the specific
steps the inspector should take and discusses general considerations
for effective implementation. General support information may be found
in the other chapters and specific technical support may be found in
the Appendix and References.
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REVIEW OF INSPECTION REQUIREMENTS
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2.0 REVIEW OF INSPECTION REQUIREMENTS
Section 1445 (B) (1) of the Safe Drinking Water Act provides the
Administrator or his designated representative the authority to enter
upon and to inspect any facility subject to Underground Injection
Control (UIC) Program requirements. Additionally, the provisions of 40
CFR Part 144.51 (i) (formerly ง122.7 (i)), specify that the Director or
his authorized representative, upon presentation of documents and
credentials, may:
(1) Enter upon the permittee's premises where a regulated
facility or activity is located or conducted, or where
records must be kept under the conditions of the permit
(2) Have access to and copy at reasonable times any records that
must be kept under the conditions of the permit
(3) Inspect at reasonable times any facilities, equipment
(including monitoring and control equipment), practices, or
operations regulated or required under the permit
(4) Sample or monitor at reasonable times, for the purpose of
assuring permit compliance or as otherwise authorized by the
appropriate Act, any substances or parameters at any
permitted location.
Although these provisions are cited for permittees, the term
permittee and rule-authorized operators may be used interchangeably.
The general UIC regulations (Parts 144, it's amendments and state
sub-parts of Part 147) do cite a number of specific inspection
opportunities made available in the program.
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2.1 OVERVIEW OF REGULATORY CRITERIA, AUTHORITY FOR INSPECTIONS, AND
PRIORITIES OF REGION III
2.1.1 Region III Inspection Strategy Guidelines
An Inspection Strategy has been prepared by Region III to
encapsulate an overview of inspection opportunities, to prioritize
these opportunities according to environmental sensitivity and to
allocate EPA staff and resource commitments to these activities. The
Strategy, by practical necessity, incorporates both a near and long
term perspective by recognizing the unique inspection requirements of
the Program's activities during the first year as well as those that
will be cyclical in nature.
For the purposes of this Strategy, inspection opportunities are
defined and grouped into the following categories:
Priority I - Inspections for Emergencies, Non Compliance Reports and
Class IV Closure
The inspections of this category are given the fullest level of
EPA commitment because this category chiefly addresses instances that
qualify as critical in nature such as emergency response, significant
reports of non-compliance and Class IV closure. Because of the
potentially serious environmental impacts of these activities they are
committed to Priority I. It should also be understood that Class IV
closure is a one-time, first program year activity while other
activities under this priority will be cyclical in nature and are
projected on an annual basis.
For 24-hour non-compliance reports, an actual inspection will be
warranted only in instances where the report does not address
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corrective action(s) undertaken; the situation borders on an emergency;
or the owner/operator requires and requests technical assistance. In
those cases where an actual well workover would be undertaken, EPA
personnel may witness the workover if the situation of non-compliance
or emergency is severe enough to merit such close monitoring.
Class IV closures will constitute a significant commitment of
resources. For each of these wells, an initial reconnaissance trip
followed by an observation of the actual plugging and abandonment will
be conducted, if the well is not already plugged.
Priority II - Pre-Operational Inspections (New Facilities)
The activity of this category focuses on pre-operational
inspections authorized in Section 144.52 (c) (formerly ง122.41(c)) for
new facilities. Owner/operators must notify the Director of completion
of construction and the Director, in turn, must respond within 13 days
of the completion notice and set a reasonable time period in which to
inspect the well(s). If the Director fails to respond within the
specified time, the permittee is then automatically authorized to
initiate injection operations. Because of this provision and the need
to review evidence of compliance with permit requirements, it is
essential that the pre-operational inspection be made as a critical
first step toward effective compliance. These operations will be
cyclical in nature and dependent on the volume of new injection
activity. An integral element of such reviews will be an examination
of the owner/operators conformance to the approved corrective action
pi an.
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Priority III - Inspections for Mechanical Integrity Tests and
Plugging and Abandonment
This category of activities centers on these planned activities
conducted by owner/operators in response to the subject EPA
requirements. This category represents a significant work-load
projected over time because of the number of wells which will be
required to conduct the mechanical integrity test(s). However, since
many of these tests will be repetitive in nature, EPA may not witness
each and every activity. The EPA may prioritize representative samples
when a single field may have many mechanical integrity tests or
plugging and abandonment operations scheduled. It is, however,
expected that these activities will be of major interest to the staff
in the first year of the program because of the significant hands-on
training experience that these inspections would offer. The mechanical
integrity test inspection activity is expected to be on a five-year
basis while plugging and abandonment inspections will be tied to
owner/operator notices of abandonment. EPA has projected that
mechanical integrity tests for the approximately 2500 existing Class
IIR wells will be conducted by owner/operators at a rate of 500 wells
per year for the five-year cycle. This test for new facilities will be
an integral element of the pre-operational review. A testing schedule
for the existing wells is under development and will be based on a
quarterly schedule. Priority will be assigned to wells in accordance
with their construction typologies whereby those wells with minimal
casing and cementing construction will have the highest priority for
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testing as will any other instances where groundwater contamination is
indicated. The priority scheme continues on an annual basis through
each well construction type until all wells have been tested and the
cycle is repeated over the five year intervals required. Region III
has set a minimal goal for witnessing mechanical integrity tests by
requiring that at least 25%, or 125 of the 500 well tests be witnessed
per year, thus covering 25% of the Class IIR wells in five years.
For plugging and abandonment, current trends indicate that about
160 wells are closed down annually either in a single field or
distributed among many projects. Because of the difficulty in
estimating this distribution and the fact that it is dependent on an
owner/operator's notification, EPA has arbitrarily estimated
inspections of 40 well closures per year.
Priority IV - General Housekeeping Inspections
This category of inspection opportunities consist of reviews of
general housekeeping, e.g., simple checklist reviews of equipment
requirements, monitoring summaries and the like. These activities will
generally be accomplished during site visits if and when a higher
priority need dictates that EPA staff be present to conduct another
type of inspection. It is also expected that any facility which does
not receive a general housekeeping review in conjunction with another
priority inspection would be subject to such an inspection at least
once in every five years.
Priority V - Blow Box Inspections
Blow boxes i.e., sumps or pits, used for the disposal of produced
fluids in association with gas production will be inspected as they are
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discovered. For each of these facilities an appropriate course of
action will be decided on a case-by-case basis. Follow-up inspections
will be made later to confirm compliance with any clean-up,
reconstruction or closure orders.
2.1.2 Overview of Safe Drinking Water Act and Amendments
Enforcement Program:
The Safe Drinking Water Act requires that injection well owner/
operators who violate the provisions of the UIC regulations be subject
to either, civil or criminal penalties or both. This section presents
a brief review of the enforcement programs that are being established
to deal with violations and the penalties that may be assessed under
various circumstances.
Enforcement Procedures:
EPA has the authority to seek penalties for owner/operators of
injection wells failing to satisfy regulatory requirements.
Enforcement actions may be taken in several types of situations, for
example:
Failure to apply for permit (where required)
ฐ Failure to comply with permit or rule authorization
requirements
# Failure to take all reasonable steps to minimize or correct
any adverse impact on the environment resulting from
noncompliance.
The detailed responsibilities of permit and/or rule authorized
facility owners/operators regarding compliance are covered in the UIC
regulations.
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The preamble to the regulations indicates that enforcement actions
will be taken in response to instances of noncompliance, but that
discretion will be used in determining how severe a penalty may be in
any given situation. The preamble notes, for example, that where
noncompliance problems are of a trivial nature, severe penalties
probably would not be levied.
EPA has a variety of mechanisms for identifying noncompliance.
First, to identify wells requiring permits, EPA can utilize well
inventories and related well records. Second, inspections of sites by
regulators during construction and after operation begins can provide
information on such noncompliance. Third, material provided to EPA in
permit applications, monitoring reports, and operating records can
provide cases of noncompliance. Finally, EPA may rely on information
provided by interested citizens or by a non-compliance report itself.
Penalties for Noncompliance:
Violators of the regulations may be subjected to either civil or
criminal penalties or both. Criminal penalties are possible where it
is determined that there has been a will full violation of the law.
Penalties may consist either of orders to cease operation or to pay
fines. UIC program has a civil penalty schedule that allows EPA to
fine violators up to $2,500 a day for noncompliance involving UIC
violations. For criminal violations, authority provided to fine
violators of Class I regulations up to $5,000 per day. As suggested
earlier, the severity of any civil or criminal penalty would presumably
reflect a determination by EPA as to the seriousness of the violations
and the causes of it.
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Underground Sources of Drinking Water:
Federal underground injection control regulations promulgated
under the authority of the Safe Drinking Water Act are directed toward
the protection of underground sources of drinking water (USDW). Under
Federal definition, USDW basically are aquifers which contain water
currently used for human consumption, or which contain 10,000 mg/1 or
less total dissolved solids (TDS).
Under the UIC program, it is not necessary to specifically
designate aquifers as USDWs. The Agency has applied a broad and basic
rule that states any aquifer or portion there-of that fits the
definition is, in fact, a USDW. Under an EPA, UIC development grant,
the Commonwealth of Pennsylvania conducted a major study which
delineates those ground water basins in the state which consist of
usable quality groundwater. EPA itself also conducted a study to
determine which of these aquifers would require an exemption because of
the criteria listed below. A list of exempted aquifers, associated
with water-flood operations for oil and gas in Northwestern
Pennsylvania has been incorporated in 40 CFR Part 147 Subpart NN. The
exemption, as authorized, applies solely to Class II operations.
An aquifer or portion of an aquifer may be designated as an
exempted aquifer if the following criteria are met:
A. It does not currently serve as a source of drinking water for
human comsumption, and
B. It will not in the future serve as a source of drinking water
for human consumption because:
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1. It is mineral, hydrocarbon or geothermal energy bearing
with production capability, or
2. It is situated at a depth or location which makes
recovery of water for drinking water purposes
economically or technologically impractical, or
3. It is so contaminated that it would be economically or
technologically impractical to render that water fit for
human consumption; or
4. It is located above a Class III well mining area subject
to subsidence or catastrophic collapse.
Area of Review:
Fluids injected under pressure into a geologic formation that has
been penetrated by improperly completed or plugged wells, could move
laterally through the injection zone, moving formation fluids into
improperly completed or plugged wells and upward into underground
sources of drinking water.
The area of review is the area surrounding an injection well or a
group of injection wells, for which pressure data are calculated and
artificial penetrations are evaluated for possible corrective action.
An area of review for Class II wells will be determined on a
case-by-case basis using an appropriate formula and applicable
geological criteria.
Corrective Action:
EPA may require that corrective action be taken when any well
within the area of review of an injection operation is inadequately
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constructed, plugged, or abandoned so as to pose a hazard to
underground sources of drinking water. In general, the staff will
review data submitted by the applicant, evaluate the proposed
corrective action plan, and if the plan is approvable, incorporate it
as a permit provision.
In the technical portion of the application, the applicant will
submit the following information relevant to corrective action review:
- Chemistry of the injection fluid,
- Anticipated operating limits and expected pressure effects on
the injection reservoir over the life of the project,
- Detailed local geology and hydrology,
- An estimate of the anticipated distance from the injection area
that the injected fluids will travel during the life of the
project,
- Locations, construction details, and plugging and abandonment
records for wells within the area of review.
The applicant will submit a corrective action plan for any wells
within the area of review which may pose a hazard because of the
proposed injection.
EPA's evaluation of the submitted information is in two phases.
In the first phase, submitted data are checked against EPA files,
records, or other sources, for completeness and accuracy. If the data
on which the corrective action plan are based are inadequate, then the
applicant is required to supply additional information as necessary and
submit a revised plan.
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Corrective action plans may require:
A. Physical alteration and correction of any inadequate well
system within the area of review prior to beginning injection
operations, or
B. The operation of the injection facility at reduced pressure
levels until such time as EPA determines that physical
alteration and correction of an inadequate well system is
accomplished, or
C. Reduced pressure operation of the facility for the life of the
project.
2.1.3 Barlow's Guidance, An Overview of Other Federal Regulations:
The Supreme Court decision in Marshall v. Barlow's Inc., US, 98
S. Ct. 1816 (1978) was an important case affecting the conduct of EPA
Inspections. The decision bears upon the need to obtain warrants or
other processes for inspections pursuant to EPA - administered Acts.
In Barlow's, the Supreme Court held that an OSHA inspector was not
entitled to enter the non-public portions of a work site without either
(1) the owner's consent, or (2) a warrant.
In summary, Barlows has two (2) major effects on EPA enforcement
inspections:
- Where aninspector is refused entry, EPA will seek a warrant
through the US Attorney General.
- Sanctions will not be imposed upon the owners of establishments
who insist on a warrant before allowing inspections of the
non-public portions of an establishment.
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The full scope of Barlow's decision is presented in a discussion
of entry procedures included in Chapter 7.0. For additional
information the UIC inspector is encouraged to obtain a copy of the EPA
procedural guidelines concerning this decision from the USEPA Office of
Enforcement.
2.2 KINDS OF INSPECTIONS
As part of the EPA's compliance monitoring program, the UIC staff
may verify that certain injection well facility construction,
completion, operation, maintenance, and closure procedures are
performed according to approved plans and schedules and meet all permit
or rule requirements. On-site inspections will be a major component of
this effort.
Inspections consist of:
Emergency and Non-Compliance Inspections
ฐ Preoperational Inspections
ฐ Mechanical Integrity Test Inspections
0 Plugging and Abandonment Inspections
# Class IV Closure Inspections
* General Housekeeping Inspections
ฐ Blow Box Inspections
2.2.1 Emergency and Non-Compliance Inspections
Emergency and Non-compliance inspections may be conducted at any
time to:
Determine the existence of a violation,
0 Provide basis for enforcement action
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# Define type of violation, or
# Provide data to assist in determining cause of violation.
Complaints alleging improper construction, completion, operation
or maintenance at an injection well facility received by UIC staff will
be thoroughly investigated. Response to complaints may consist of:
0 Establishing the nature of the complaint,
Reviewing appropriate EPA files,
Establishing contact with the operator to verify the complaint
and discuss corrective action,
Performing a site inspection to determine if a problem exists,
or
ฐ Referring the complaint to Regional Counsel for appropriate
enforcement action.
2.2.2 Preoperational Inspections
Site inspections to verify or witness drilling and completion
procedures will be conducted by UIC staff according to a regular
schedule, or in response to a complaint or other indications that a
problem may exist. Construction elements and testing that may be
witnessed or supervised by the staff, provided budget and workload
requirements permit, include:
Well logging,
Setting and cementing surface casing,
# Setting and cementing protection casing,
Formation pressure tests and injectivity tests, and
Mechanical integrity tests.
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2.2.3 Mechanical Integrity Test Inspections
Inspections to verify or witness mechanical integrity tests may
be conducted on a scheduled basis as part of a General Housekeeping
Inspection, prior to commissioning a new well as part of a
Preoperational Inspection or at the conclusion of a well workover. The
scope of the inspection is dependent on well construction typology.
Inspection activities could include:
Review of historical pressure monitoring data,
# Witnessing pressure test of annul us to evaluate internal
mechanical integrity and/or
" Witnessing logging to evaluate external mechanical integrity.
ฐ Witnessing water-in-annulus test
2.2.4 Plugging and Abandonment Inspections
Abandonment of all Classes of injection wells will be witnessed
by UIC Inspectors to insure that closure is performed according to
approved plans and schedules. Inspections will generally follow an
operator's notification of intent to plug and abandon a well but could
result from an enforcement action taken by the Agency. Plugging and
abandonment field activities will generally include both well
preparation and plug emplacement.
2.2.5 Closure of Class IV Wells
Special emphasis has been placed on closure of Class IV wells
since this has been identified as the first priority of Region's III
Direct Implementation Strategy. Proper closure of these wells could be
more complex than other classes of wells depending on the degree of
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contamination and threat to public health. Inspections will be
performed in order to:
ฐ Evaluate previously plugged Class IV facilities,
# Determine if reentry into a previously plug well is required,
0 Evaluate degree of hazard to public health,
ฐ Install monitoring facilities if required, and
9 Witness plugging procedures.
2.2.6 General Housekeeping Inspections
The UIC staff plans to conduct scheduled inspections of
permitted injection facilities on a regular basis in order to:
ฐ Determine the probability of violation and indicate problems
that may be causing a violation,
ฐ Assist in identifying problems that exist or have a potential
for developing, and/or
ฐ Update EPA records on the facilities and on the operation of the
2.2.7 Blow Box Inspections
Generally two types of inspections are possible for these
operations after they have been identified, such as:
Initial inspection to determine whether wells are constructed
and operating in accordance with UIC regulations, and if not, to
determine an appropriate course of action and then to conduct
ฐ A follow-up inspection to determine compliance with required
actions.
The full scope of the various UIC Inspections is addressed in
Chapter 3.0.
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INSPECTION PRACTICES
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3-1 TYPES of WELLS IN REGION III
3.1.1 Introduction
Proper regulation of underground injection operations is crucial
to assure protection of ground water resources existing in each state
regulated by EPA Region III. Either the individual state or the USEPA
is responsible for exercising appropriate regulations depending on
which body has elected UIC primacy. As shown in Table 3.1, three
states out of six have elected to have state primacy. The USEPA has
taken regulatory responsibility in the states of Pennsylvania, Virginia
and the District of Columbia. Of these states, most injection
activities are in the State of Pennsylvania. Whether it is an
individual State or the EPA, five classes of wells would be regulated
by a program that is designed to prevent contamination of underground
sources of drinking water due to injection activities. Section 3.1
describes injection well classifications with particular reference to
Region III.
3.1.2 Injection Well Classification:
(a) Adopt well classification from federal classification
system:
The well classification system developed by the Safe
Drinking Water Act defines five classes of injection wells.
Classification of a well will depend on its use,
hydrogeologic setting and may be complicated by other
regulatory factors such as aquifer exemption.
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TABLE 3.1
EPA REGION III PRIMACY STATUS
State
1. Delaware
Primacy *
State or EPA
State elected
1984
2. Maryland
3. Pennsylvania
State elected
1984
EPA
4. Virginia
EPA
5. West Virginia State Primacy
District of EPA
Columbia
Well Status
0 1984
Geology unfavorable. No
disposal (Class 1) or oil
and gas (Class II) wells.
Class IV & Class V wells to
be regulated, if any.
As above
No Active Class I and III
wells. The state has many 0
& G wells (Class II). Class
IV wells have been
abandoned. Class V wells to
be regulated.
No disposal wells. No Class
II injection wells. However
state has some (primary) oil
wel1s.
One Class I injection well
is operative. Several Class
II wells. Class IV wells
have been abandoned.
No injection activities.
* Covers all injection wells, Class I through V.
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(b) Pay careful attention to the basis of classification:
Class I: Industrial and municipal wells
Class II: Oil and Gas wel1s
Class III: Mining wells
Class IV: Banned (shallow, hazardous fluid) wells
Class V: Any other wells (shallow, non-hazardous
fluid)
Additional factors that form the basis of classification
include (Refer to Figure 3.1):
Source of injected fluid such as industrial wastewater,
municipal water, oilfield brine, surface water, etc.,
* Depth of the well and relative distance from underground
sources of drinking water, and
ฐ Degree of toxicity of the injection fluids.
(c) Examine sub-classifications suitable for Region III:
A typical sub-classification may be presented as
follows:
Class I
(1) Wells used by generators of hazardous waste, or
owners, or operators of hazardous waste management
facilities to inject hazardous waste beneath the
lowermost formation containing an underground source
of drinking water within one quarter mile radius of
the well bore.
3-3
-------
CLASS I
CLASS XX
CLASS XXX
CLASS XV
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UNDERGROUND INJECTION CONTROL PROGRAM CLASSIFICATION OF WELLS
-------
(2) Other Industrial and municipal disposal wells
which inject fluids beneath the lowermost formation
containing an underground source of drinking water
within one quarter mile of the well bore.
Class II
Wells injecting fluids:
(1) Which are brought to the surface in connection
with conventional oil or natural gas production and
may be commingled with waste waters from gas plants
which are an integral part of production operations,
unless those wastes are classified as a hazardous
waste at the time of injection,
(2) For enhanced recovery of oil or natural gas; and
(3) For storage of hydrocarbons which are liquid at
standard temperature and pressure.
Class III
Wells which inject fluids from extraction of minerals
including:
(1) Mining of sulfur by the Frasch process,
(2) In-situ production of uranium or other metals.
This category includes only in-situ production from
ore bodies which have not been conventionally mined.
Solution mining of conventional mines such as stopes
leaching, 1s included in Class V,
3-5
-------
(3) Solution raining of salts or potash,
(4) In-situ combustion of fossil fuel, and
(5) Recovery of geothermal energy to produce electric
power.
Class IV
(1) Wells used by generators of hazardous wastes or
radioactive wastes, by owners or operators of
hazardous waste management facilities, or by owners or
operators of radioactive waste disposal sites to
dispose of hazardous wastes or radioactive wastes into
a formation which, within one quarter mile of the well
bore, contains an underground source of drinking
water.
(2) Wells used by generators of hazardous wastes or
radioactive wastes, by owners or operators of
hazardous waste management facilities, or by owners
or operators of radioactive waste disposal sites to
dispose of hazardous wastes or radioactive wastes
above a formation which within one quarter mile of the
well bore, contains an underground source of drinking
water.
(3) Wells used by generators of hazardous wastes or
by owners or operators of hazardous waste management
facilities, to dispose of hazardous wastes. For
3-6
-------
example, wells used to dispose of hazardous wastes
into, or above a formation which contains an aquifer
which has been exempted pursuant to UIC Regulations.
Class V Well
Injection wells not included in Classes 1, II, III, or
IV. Class V wells include, but are not limited to:
(1) Cesspools, including multiple dwelling, community
or regional cesspools, or other devices that receive
wastes, which have an open bottom and sometimes have
perforated sides. The UIC requirements do not apply
to single family residential cesspools which receive
solely sanitary wastes and have the capacity to serve
fewer than 20 persons a day.
(2) Sand backfill and other backfill wells used to
inject a mixture of water and sand, mill tailings or
other solids into mined out portions of subsurface
mines whether what is injected is a radioactive waste
or not.
(3) Septic system wells used to inject the waste or
effluent from a multiple dwelling, business
establishment, community or regional business
establishment septic tank. The UIC requirements do
not apply to single family residential septic system
wells, nor to non-residential septic system wells
3-7
-------
which are used solely for the disposal of sanitary
waste and have the capacity to serve fewer than 20
persons a day.
(4) Injection wells associated with the recovery of
geothermal energy for heating, aquaculture and
production of electric power.
(5) Radioactive waste disposal wells other than Class
IV.
(6) Wells used for solution mining of conventional
mines such as stopes leaching.
(7) Injection wells used for in situ recovery of
lignite, coal, tar sands, and oil shale.
(8) Wells used to inject spent brine into the same
formation from which it was withdrawn after extraction
of halogens or their salts.
(9) Injection wells used in experimental
technologies.
(10) Wells for waste disposal into solution cavities
in carbonate formations. Well must be dug, drilled or
driven.
(11) Air conditioning return flow wells used to return
(to the supply aquifer) the water used for heating or
cooling in a heat pump.
3-8
-------
(12) Cooling water return flow wells used to inject
water previously used for cooling.
(13) Drainage wells used to drain surface fluid,
primarily storm runoff, into a subsurface formation.
(14) Dry wells used for the injection of wastes into a
subsurface formation.
(15) Recharge wells used to replenish the water in an
aquifer.
(16) Salt water intrusion barrier wells used to inject
water into a fresh water aquifer to prevent the
intrusion of salt water into the fresh water.
(17) Subsidence control wells (not used for the
purpose of oil or natural gas production) used to
inject fluids into a non-oil or-gas producing zone to
reduce or eliminate subsidence associated with the
overdraft of fresh water or mining.
3.1.2 Inventory and Inventory Based Classification
(a) Assist in up-dating well inventories:
The injection well inventory should include all the
injection wells known to exist in a given state.
Maintenance of correct inventory is not a straight forward
task, especially when hundreds of wells are drilled,
abandoned and reclassified in a given area. A special
project is sometimes undertaken to up-date the existing
inventory.
3-9
-------
Obtain regional inventory of injection wells and realize
the importance of inventory based classification:
At the present time very few states have complete,
up-to-date inventories. The situation will improve
considerably as the UIC program progresses.
According to their inventory of 1982, West Virginia
has an estimated 1 Class I, 450 Class II, 17 Class III and
70 Class V wells. There are no Class IV wells known to
exist in this state.
Injection well inventories of the States of
Pennsylvania and Virginia are presented in Table 3.2 and
3.3, respectively. These wells are further classified
according to the following status categories:
Under construction (UC)
Active (AC)
Temporary abandoned (TA)
Plugged and approved (PA)
Abandoned and not approved (AN)
The wells described as abandoned and not approved (AN)
could be problem wells in the future. Similarly, close
vigilance would be required if some wells are temporarily
abandoned, as these wells too could pose problems in the
future. Tables 3.2 and 3.3 provide planning data relative
to the number of wells that would need regular inspections
according to the Region III Inspection Strategy.
3-10
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TABLE 3.2
INJECTION WELL INVENTORY
PENNSYLVANIA, 1933
CLASS TYPE UC AC TA PA AN
CODE TYPE TOTAL WELLS WELLS WELLS WELLS WELLS
I
1-1 Industrial 6 1 5
II
2-D Disposal 230 1 224 14
2-R Enhanced
Recovery 4,186 8 2,880 439 846 13
Subtotal 4,416 9 3,104 439 847 17_
IV
4-H Hazardous 11 5 6_
V
5-A Air Con-
ditioning 21
18
2
1
5-D Storm
Drainage 153
144
5
4
5-S Subsidence
Control 11,643
407
173
10
11,053
5-W Waste
Disposal 39
18
18
3
5-X Other 8,236
1
167
8,068
Subtotal 20,092
408
520
12
19,145
7
TOTAL 24,171
412
3,393
438
18,897
13
UC: Under construction, AC: Active, TA: Temporarily abandoned, PA:
Plugged, approved, AN: Abandoned, not approved.
-------
TABLE 3.3
INJECTION WELL INVENTORY
VIRGINIA, 1983
CLASS TYPE AC TA PA AN
CODE TYPE TOTAL WELLS WELLS WELLS WELLS
IV
Hazardous
V
5-A Air Con-
ditioning 1,507 1,504 3
5-D Storm
Drainage 140 120 20
5-R Recharge 3 12
Waste
5-W Disposal 12 8 13
Subtotal 1,662 1,632 1 4 25
TOTAL
1,663
1,632 2
4 25
-------
3.2 EMERGENCY AND NON-COMPLIANCE SITUATIONS
Emergency and non-compliance situations are most likely to occur
as a result of operating problems. These operating problems may
include workovers, injection pressure limit changes, environmental
clean-up and temporary permits. This section will address
notifications required by the owner/operator as well as those required
of the Agency. Some of the notifications discussed may not be
explicitly addressed in the UIC regulations. Related topics such as
investigative techniques and dealing with the uncooperative
owner/operators are dealt with in Chapter 5.
3.2.1 Review of Requisite Notification Procedures;
(a) Recognize the difference between notifications/reminders
and enforcement orders:
Some well operators may have to be notified or reminded
about the requirements they must fulfill under the UIC
regulations. Notifications could be given at any time from
the early stages of the permitting process through
operation of the well and final abandonment. The
notification process should not be confused with a final
order issued by the Enforcement Office. Administrative
procedures adopted to issue and implement enforcement
orders are not covered in this Guide.
Notifications may be made on the telephone,
particularly in an emergency situation, and followed up by
a letter within a reasonable period of time. This process
3-13
-------
of communication, for instance, is used in several states.
A work-over situation is a good example. An operator
notifies the concerned department about the up-coming
workover. After he gets regulatory approval, the workover
is implemented and a formal report submitted by the
operator within a reasonable time period following
completion of workover. If this report is not issued, the
department has grounds to remind the operator of the
requirements and deadlines and possibly implement
progressive disciplinary action.
Make sure that monitoring and reporting requirement are
clearly specified:
Certain monitoring and reporting requirements must be
specified in all permits. Among these specified
requirements is a description of the required monitoring
program, including the type, intervals and frequency
I
sufficient to yield data which are representative of the
monitored activity (including continuous monitoring
requirements when appropriate). The proper use,
maintenance ahd installation of monitoring equipment or
methods must also be specified when appropriate.
Additionally, the applicable reporting requirements, based
upon the impact of the regulated activity and as specified
in the UIC regulations, must be stated in the permit.
Reporting and monitoring requirements may differ of
course, depending on well classification. A Class I well
3-14
-------
operator, for instance, must operate under strict reporting
requirement, whereas a Class V well operator will have no
monitoring or reporting requirements. Refer to Chapter 4
for details on monitoring parameters which may require EPA
notification.
Specify deadline requirements when serving notices:
All monitoring forms and reports required to be submitted
are generally forwarded to the appropriate regulatory
department. The monitoring forms and reports are then
compared with the scope of permitted activity to verify
compliance. After compliance status has been determined,
information is usually entered into a computerized data
retrieval system and the monitoring forms and reports are
filed.
If reporting forms are not submitted within a
reasonable time following their due dates, a notification
letter will be forwarded to the operator in question
specifying a time by which it must be submitted. If the
required materials have not been submitted by the
established time, or if a history of non-reporting, or late
reporting requiring reminders develops, appropriate action
should be taken.
When the monitoring forms or reports show permit
violations, the facility monitoring records are examined
for trends and future submissions by the violator are
3-15
-------
scrutinized for further violations and trends. If
violations persist or increasing trends develop, an
inspector may be requested to carry out the necessary
investigation of the situation. Investigations which
confirm violations may result in the issuance of an
enforcement order.
3.2.2 Workover:
A. Make certain that an operator notifies the regulatory agency
prior to a workover.
The following steps in the notification process are
only proposed. The permittee should notify the Director
before commencing any workover operation or corrective
maintenance which involves taking the injection well out of
service. The notification should be in writing and should
include plans for the proposed work. The Director may grant
an exception of the written notification when ironediate
action is required.
Approval by the Director shall be obtained before the
permittee may begin any workover operation or corrective
maintenance that involves taking the well out of service.
Within sixty (60) days after the completion of the
workover, a report shall be filed with the Director
including the reason for well workover and the details of
all work performed.
3-16
-------
B. Analyze the objectives of a proposed workover:
A workover according to the terminology of the
petroleum industry refers to well maintenance. Often a
workover is required to take place immediately in order to
avoid an emergency situation. The inspector should receive
workover plans that clearly state the objectives of the
proposed work. Workovers are commonly attempted for the
following purposes:
Well repair workovers:
Tubing: Replace or repair damaged tubing
Packer: Replace or repair damaged packer
Casing: Repair damaged or corroded casing (by a
patch or squeeze cementing technique)
Cementing: Perform remedial cementing jobs
Liner: Install liner (or casing) to modify well
design.
During the above repairs, the injection well must be
taken out of service.
Stimulation workovers:
Flushing/Washing: Flush the wellbore using a
treating chemical, i.e., inject a
slug of wash fluid
Acidizing: Dissolve solids which have plugged
the wellbore.
Fracturing: Improve rock permeability by
splitting the formation
3-17
-------
Backflowing/jetting: Retrieve (back-flow) solids to the
surface that are plugging the
formation pore spaces near the
well bore.
Reperforating: Increase the flow area by
increasing perforated holes (in
wells with protection casing
onl y).
Stimulation work generally does not require pulling the
injection tubing out of the hole except for big jetting
jobs in which large washing tools cannot be introduced
through the tubing.
Recompletion workovers:
Recompletion may involve abandoning the existing
injection zone and using a shallower permitted
interval. On the other hand deepening may be desired
to open up a new interval below the existing injection
zone. If it is decided to use the same injection zone,
or a deeper injection zone, side tracking may be
possible.
C. Be knowledgeable about the common repairs and stimulation
techniques:
Injection well diagnosis and workover include many
techniques requiring consulting expertise and specialty
service companies to repair the well.
3-18
-------
Service companies such as Halliburton, Dowell and
others, furnish tools and manpower to conduct many types of
workovers. These companies also keep records of the local
stimulation conditions and other jobs an operator has
performed in the past. A locally available Oil & Gas
directory would generally provide Classified Services such as
drilling, rental, cementing, stimulation, wireline trucks,
transportation services etc.
If an inspector gets interested in workover state-of-art
technology, reference is made to publications by the Petroleum
Extension Service, University of Texas, Austin, Texas. 3.2.3
Injection Pressure Limit Revision:
A. The operator is required to strictly observe injection
pressure limitations specified in his permit or in the field
rule:
An injection of any fluid at a pressure in excess of
that authorized by the Agency shall constitute a permit
violation. This violation increases the chances of
fracturing the injection zone. If the violations are
repetitive, fractures may propagate to endanger shallow
underground sources of drinking water.
B. Injection pressure limits can be revised, if local geology
and operating conditions are shown to deviate from those
originally assumed:
3-19
-------
If the operator can justify that an injection pressure
limit assigned to his well does not conform with the actual
well conditions, he may request that the Agency revise the
1 imitations.
In most cases, an operator wants flexibility in the
operation and ih some cases technical findings to increase
permitted injection pressure limits are justified. After
adequate investigations, the Agency may approve a new
injection pressure limit. The original permit is then
modified or a new permit is assigned depending on policies
of the regulatory agency.
i
Just as injection pressure limits can be increased,
i
local well operations may dictate a reduction in the
j
limiting pressure. For example, the specific gravity of the
injection fluid could be much greater than originally
assumed. The local fracture gradient may be lower than that
initially anticipated also the well could be recompleted in
a shallower interval.
I
If an operator injects fluids with varying densities,
it should be possible to solve the problem by assigning
pressure limits that are related to injected fluid
densities.
C. Examine site specific data in order to make judgements on
injection pressure limits:
The most important information required here is the
local fracture gradient and the datum level (injection
3-20
-------
depth). Any time the datum level is changed for some
reason, the pressure limit will also change. Generally the
top of the given injection zone, or perforations, is a good
datum level. If local fracture gradients are not reported,
by service companies, it is possible to estimate the
gradient by using historically proven correlations (Herbert
and Willis, 1957).
Hubbert and Willis reasoned that the general condition
of subsurface stress is characterized by three unequal
principal stresses and that hydraulic injection pressure
must be nearly equivalent to the least-principal compressive
stress.
During a typical fracturing job, wellhead as well as
bottom hole pressures are recorded as a function of time.
The bottom hole pressure is increased by pumping fracturing
fluid at a given rate. At a point in time the formation
breaks down at a pressure referred to as the breakdown
pressure or fracture initiation pressure. As the fluid
continues to be pumped into the well, the bottomhole
pressure stabilizes at a level lower than the breakdown
pressure. This pressure is called the treating pressure or
fracture propagation pressure. When the injection is
ceased, and the well shut in, the pressure quickly
stabilizes to a constant value, the instantaneous shut-in
pressure. The difference between the treating pressure and
3-21
-------
instantaneous shut-in pressure may not be always noticeable.
The Hubert and Willis equation allows the prediction of the
treating pressure which can be compared with the actual
field data.
Given the field data, an inspector should specifically
look for the treating pressure or shut-in pressure and
calculate the ratio of pressure to the depth to be expressed
as psi/ft. As an example, at a depth of 5000 feet, the
breakdown and treating pressures could be 3500 and 3300 psi,
I
respectively. Of the two gradients, i.e., 0.70 psi/ft and
j
0.66 psi/ft, the least stress is the vicinity of the well
corresponds to the gradient of 0.66 psi/ft.
3.2.4 Environmental Clean-up:
A. Environmental clean-up has the goal of attaining clean
water, clean air and a healthful environment:
All injection operations should be conducted with full
regard for environmental protection in such diverse
conditions as metropolitan sites or open fields. The
American Petroleum Institute, (API) has published
recommended practices for protection of the environment with
particular emphasis on oil-field operations. The inspector
may find a publication of this type very useful if he
desires greater coverage of methodology and concepts.
B. Examine typical injection well design parameters and
maintenance aspects with respect to environment protection:
3-22
-------
ฐ Injection Wells:
- Plan well casing and cementing programs to ensure
protection of ail fresh water sources. These
procedures are integral to the UIC program.
- Consider characteristics of the subsurface disposal
strata to determine whether strata and fluids contained
therein will be compatible with the injected fluid.
Select a receiving subsurface strata which will accept
the maximum anticipated fluid volume at acceptable
pressures.
- Inject fluid through tubing and below a packer, where
practical.
- Wellheads should be primed and painted for corrosion
protection and appearance.
- In cases where backflowing of injection wells is
required, facilities should be provided for collection
and disposal of waste material.
Injection Facilities:
- The potential for leaks should be minimized through an
effective corrosion control program.
- Drains and sumps should be provided to contain
discharges and leakage.
- Piping all overflow and relief lines, vents, and drains
to a common sump equipped with high level alarm or
shutdown device should be considered.
3-23
-------
- Storage vessels served by pits should be designed so
that fluids are diverted to unlined pits only in
emergencies. Unlined pits should not be used even in
emergencies if water from these pits could seep into
usable potable water sources.
ฐ Injection lines:
- Locating lines downgrade of ponds, lakes, crops, and
dwellings should be considered.
- Lines should be buried below plow depth in farm land
areas.
- Lines should be flushed and pressure tested before
burying.
- Lines should be bridged or supported at stream crossings
or buried to a safe depth below the stream bottom.
- Provisions in lines should be made for thermal expansion
and contraction.
- When corrosive fluids such as salt water are to be
transported, glass reinforced plastic, internally
protected steel pipe, or other suitable corrosion-
resistant piping materials should be considered.
- Where indicated necessary for corrosion protection,
lines should be externally coated, cathodically
protected, or elevated above ground by placing on
concrete blocks, etc. A typical example could be piping
through a brackish formation or soil. Another example
may involve piping design to last 50 years.
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- Conduits and post signs should be provided at stream and
road crossings.
General clean-up:
- Trees, brush, and trash accumulated during the clearing
of the production and water handling facility site
should be disposed of in compliance with existing
regulations. Burning is an acceptable disposal method
where not prohibited by local law or regulations and
where the fire and smoke will not create a hazard or
nuisance.
General Maintenance:
- All equipment leaks should be repaired as soon as the
leak is discovered.
- Facilities should be painted as necessary, to provide
good housekeeping, neat appearance, and to prevent
corrosion.
- Lines should not be blown to the atmosphere or ground
surface except under emergency conditions. Attempts
should be made to bleed pressure or contents into a
storage tank or properly designed and approved disposal
facility prepared for that purpose.
- When leaks occur, attempts should be made to contain and
recover the fluids. Restore the area as far as
practical to its original condition.
- Pits should be used in a manner which will comply with
local, state, and/or federal regulations.
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- Fences and gates should be properly maintained. Gates
should be locked if necessary.
i
- Debris and oil should be removed from pits to improve
conservation of oil and reduce inherent hazards.
- Emergency pits should be used only during equipment
malfunction; otherwise, they may become a source of
pollution. ,
C. Check the following general areas with respect to
environmental protection and clean-up:
- Eliminating potential of surface water contamination.
- All safety considerations.
- Fire protection, as required.
- Pit cleaning,:according to state regulation requirements.
- Ventilation in the operating area to meet air quality
regulations.
- Odor control,| e.g., hydrogen sulfide gases from oil-field
operations.
3.2.5 Emergency Permit Issuance:
A temporary permit for a specific injection operation should be
issued only if an emergency is real and not caused due to improper
planning or similar reasons. Temporary permit issuance should be
handled on a case by case basis:
A. Consider several examples related to water flood injection
wells:
It is possible that an emergency may comprise such
elements as:
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1. An imminent and substantial endangement to the health of
person due to an environmental threat.
2. Substantial loss of oil and gas resources.
3. Substantial delay in production of oil or gas
resources.
In emergency situations the operator may want to change
the design of the well, convert a producing well into an
injection well, (or visa versa) or may have to drill a new
well in order to solve the problem.
Before assigning a temporary permit, pay careful
attention that the proposed operation will not result in the
movement of fluids into underground sources of drinking
water.
Permits granted under (A.l) of the above list should
have their term no longer than required to prevent thซ
hazard. Any permit granted under (A.2) should be for no
longer than a few months. Permits granted under (A.3}
should be issued only after a complete permit application
has been submitted and would be effective until final action
is taken on the application.
Notice of any temporary emergency permit should be
published soon after the issuance of the permit. The
temporary permits could be either oral or written. If oral,
they should be followed by a written temporary emergency
permit.
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B. Under emergency conditions, Class I (and Class ill) well
operators may require a temporary permit;
A temporary permit may be granted or a temporary permit
i
change may be allowed. This is best illustrated by the
following examplie:
The operator of a Class I injection well was permitted
to dispose of corrosive wastewater. This operator
accumulated a substantial wastewater inventory due to poor
pretreatment ofithe waste and subsequent well bore plugging.
The operating problems were compounded by the failure of the
well's fiberglass tubing. A workover was therefore required
to clean the Iwell and replace the damaged tubing and
notification was made to the regulatory agency.
On a temporary basis, this operator was allowed to
operate the well with carbon steel tubing. He was requested
to prove mechanical integrity of the well and inject only
that portion of, his inventory that was compatible with the
carbon steel tubing. It was contemplated that carbon steel
tubing would not fail over a short period of time. The
operator reinstalled the fiberglass tubing as soon as
emergency status was no longer required, in this case, two
weeks later.
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3.3 PREOPERATIONAL INSPECTIONS
After a new UIC permit is granted and prior to start-up, the
inspector may perform several preoperational inspections. The purpose
of these inspections are to (1) assure that the well is constructed in
such a manner as to protect the USDW, (2) assure that any deviations
from the construction prognosis are reported, warranted and approved by
the EPA, (3) determine if the geology and hydrogeology encountered
during drilling is consistent with that projected in the permit
application, and (4) assure that the well has mechanical integrity and
injection potential prior to being commissioned.
With respect to the above objectives there will be critical times
which the inspector may want to witness the construction activities.
These critical benchmark events will include the following:
0 Open hole and cased hole logging,
Primary cementing,
Formation pressure and injectivity testing, and
ฐ Mechanical integrity testing.
In cases where construction inspections are scheduled the operator
should be informed that he is to notify the EPA prior to spudding the
well and prior to each of the above mentioned benchmark events. Notice
should be given far enough in advance to allow the inspector adequate
time to prepare a site visit.
3.3.1 Logging
Several comprehensive references on well log analysis are given
at the end of this chapter. A brief description of logging concepts
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and types of logs common in Region III is presented below. A general
checklist for witnessing well logging in the field is also included.
A. Understand the operation and limitations of injection well
logging:
Injection well logging provides subsurface information
and associated data pertaining to (1) drilling, completion,
and operation of individual wells; (2) formulation of
reservoir models to facilitate efficient injection
operations; and (3) environmental and legal aspects of
injection operations.
Logging tools are designed for either open-hole or
cased-hole operations. Electric logs, borehole caliper
logs, and density logs are limited to open-hole operations
because the techniques require that downhole geophysical
tools, or sondes, be in contact with the rock surfaces (not
shielded by casing). Cement bond and radioactive tracer
logs are used almost exclusively in cased-hole operations.
The basic geophysical logging system in operation is
illustrated on Figure 3.2.
Many logging techniques require circulation of drilling or
workover fluids prior to logging; whereas, other logs can be
run in dry holes. Many of the Class II wells in Region III
are drilled with air resulting in a dry hole. These wells
must be filled with fluid, generally fresh water, before
conducting certain logs. Some logging tools are not
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INSTRUMENTATION
FIGURE 3.2 GENERALIZED SCHEMATIC DIAGRAM OF GEOPHYSICAL WELL-LOGGING
EQUIPMENT (TDWR, 1983)
-------
suitable for use in conductive fluids e.g., drilling mud,
brine, etc., while operation of other logging tools is
adversely affected by nonconductive fluids. When the
various logging methods are properly used, the following
parameters can be directly measured or described:
temperature, pressure, resistivity, flow, depth, hole size,
and lithology. Many of the desired parameters must be
calculated, derived, or inferred from logs. For example, no
logging method can now directly measure permeability, rock
fracturing, or formation mechanical properties.
Well logging can be divided into five general
categories: lithologic, electrical, radioactive,
acoustical, and specialized. The applicability of a
particular logging method to a particular problem or use is
given in Table 3.4. Well servicing companies use various
trade names for equivalent types of geophysical logs. A
comparison of the leading trade names from three different
well logging service companies is presented in Table 3.5.
Other logging companies in the State of Pennsylvania include
Gearhart Industries, Birdwell and Eastern Well Services.
Table 3.5 would help to cross reference equivalent logs
offered by a given company.
B. lithological identification of the formation is possible
when samples of the formation are available:
Rotary drilling provides continuous formation samples
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TABLE 3.4. - WELL LOGGING METHODS AND USES
k-nhological Formation Fluid
Method Type kisntHicaiion parameters flow
Lithologic
Coring
Mud Log
X
X
X
Electrical
Electric
Induction
Spontaneous Potential
Single Point Resistance
X
X
X
X
X
X
Radioactivity
Natural Gamma Bay
Gamma-Gamma (Density)
Neutron
Radioactive Tracer
X
X
X
Acoustic
Sonic Televiewer
Cement Bond
Sonic Logs
X
X
Specialized
Temperature
Directional Survey
Caliper
Flow Meter
Casing-Collar Locator
Casing-Inspection Log
X
X
X
X
X
X
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TABLE 3.5 SOME GEOPHYSICAL WELL LOGGING SERVICES AVAILABLE FROM THREE
COMPANIES PROVIDING WELL LOGGING SERVICES. EQUIVALENT TYPE
LOGS ARE LISTED ON THE SAME LINE ACROSS THE TABLE.
COMPANY
WELEX
SCHLUMBERGER
DRESSER - ATLAS
Electric Log
Electrical Log
Electrolog
Induction Electric Log
Induction Electrical Log
Induction Electrolog
Dual Induction Guard Log
Dual Induction Laterolog
Dual Induction Focused Log
Guard Log
Laterolog -3, Laterolog -7
Laterolog
Contact Log
Microlog
Minilog
UJ
s:
FoRxo Log
Microlaterolog
Micro-Laterolog
c
z
CO
Proximity Log
Proximity Log
o
I
Acoustic Velocity Log
Sonic Log
Acoustilog
Compensated Acoustic Velocity Log
BHC Sonic Log
BHC Acoustilog
Fracture Finder Log
Amplitude Log
Fraclog
Micro-Seismogram Log
Variable Density Log
Variable Amplitude Density Log
Density Log
Formation Density Log
Densilog
Compensated Density Log
Compensated Formation Density
Log
Compensated Densilog
Simultaneous Ganrna Ray-Neutron Log
Gamma Ray-Neutron Log
Gamma Ray-Neutron Log
Side Wall Neutron Log
SNP Neutron Log
Epithermal Sidewall Neutron Log
-------
obtained as cuttings. A sample or mud log is a continuous
description of the geologic character of each stratum and
the depth at which changes occur. It may also include
drilling times and gas content of the mud. Ideally,
representative samples should be collected at measured
depths and at such intervals as will show the lithologic
character of the formations penetrated.
C. Electrical logging is a process by which electrical
measurements provide data on formations penetrated by the
borehole:
This process involves the downhole measurement of
electrical quantities, principally voltage and resistance.
The voltage which is measured is the spontaneous potential
(SP) of the drilling mud column in the borehole with respect
to the ground potential near the drilling rig. The SP is
generated through the operation of several mechanisms which
involve borehole fluids and the boundaries between
subsurface strata. Measurement of this voltage is
accomplished by lowering a sonde that carries one electrode
down the hole, and by recording the difference in voltage
between the sonde-borne electrode and an electrode driven
into the ground at the surface. The SP log is useful in
defining formation fluids and may be correlated to TDS
val ues.
Resistance of subsurface strata is measured in two
general ways. One method involves placing electrodes in
3-35
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various configurations in a sonde in the borehole with an
electrical signal while measuring the voltages between other
electrodes (normal and lateral logs). A variation of this
method is to monitor the amount of current that is actually
forced into the formation from the electrodes. The first
method, such as the SP, requires that the drilling mud be
conductive. The second method involves induction, and thus
nonconducting muds can be used. An induction log uses a
transmitter in one end of a sonde to generate a magnetic
field that induces eddy currents into the formation
surrounding the borehole. These eddy currents in turn
generate their own magnetic fields which are sensed by a
receiver in the other end of the sonde. The magnitude of
the induced eddy currents and their associated magnetic
fields is a function of formation resistivity which allows
the sonde receiver to record the apparent formation
resistivity.
In practice, the electric log usually consists of a
lateral curve, two normal curves, and a SP curve which are
simultaneously recorded on a strip log. The induction log
is commonly a combination of four logs made simultaneously:
SP, short normal, conductivity, and its reciprocal,
resistivity. The gamma ray and single-point resistance
curves are substituted in many instances for the SP and
resistivity. The gamma ray and single-point resistance
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logging systems are very versatile in terms of measurements
which can be made, and when combined with radioactive or
acoustic systems, are very effective in determining
formation parameters.
D. Understand radioactivity logging principles:
Common to all radiation logging devices is some means
of measuring radioactivity in the borehole. The
radioactivity may be either natural or induced, or it can
result from injection of an isotope used as a tracer.
Because certain types of radiation are very penetrating,
many of the radioactivity logs can be used in cased holes.
A natural radiation log measures gamma radiation
produced by decay of uranium, thorium, or potassium
contained in the formation. This log may also be used to
detect a radioactive tracer; however, the chief use of
natural gamua logs is for identification of lithology.
Gamma density (gamma-gamma) and neutron logs are
examples of induced radiation logs. A gamma density tool
includes a source of gamma rays which penetrate into the
formation at the borehole wall. This tool also contains a
detector which is located a short distance away and measures
the flux of gamma rays scattered by the formation. The
detected flux is proportional to the electron density of the
formation which is roughly proportional to formation bulk
density.
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The standard neutron log measures the reduction of
neutron energy resulting from collisions of emitted neutrons
and nuclei of formation materials. The greatest energy
losses occur when neutrons collide with hydrogen nuclei.
Thus, the log is representative of the total water content
of the rocks. This may include pore water between mineral
grains, bound or absorbed water in clay, or water of
crystallization in gypsum. This log gives information
concerning the porosity, or degree of water saturation of
the formation.
There are many other types of radioactivity logs;
however, those commonly used in Region III are natural
gamma, gamrna-gaimia, and standard neutron.
E. Acoustic logs are the standard porosity determining tools in
some areas:
An acoustic-velocity log is a record of the transit
time of an acoustic pulse through a fixed length of rock or
casing parallel to the borehole between transmitters and
receivers in a logging sonde. The chief uses are for
determination of porosity, identification of fractures, and
character of cement bonding between the casing and
formation. Some of the more conenon acoustic logging tools
which have received wide use and acceptance in downhole
acquisition of data are (1) cement bond, (2) borehole
compensated sonic velocity, and (3) the sonic televiewer.
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F. The following logs, not previously discussed, provide
additional information:
1. Temperature log- gives continuous record of temperature
immediately surrounding a sensor in the borehole. This
log can also be used to detect movement of fluids behind
casing and the top of a cement column. The latter log
should be run 12-18 hours after the emplacement of
cement.
2. Directional survey - provides information on borehole
slope and direction and establishes bottom-hole location
with relation to the surface entry point.
3. Caliper log - provides a continuous measurement of
borehole or casing diameters.
4. F1 uid-movement logging - includes the measurement of
natural and artificially induced flow within the
borehole.
5. Casing-collar locator - accurately locates well casing
collars, and perforations in a well.
6. Casing-inspection log - is used to monitor pipe
corrosion.
Well logs can be interpreted to determine lithology,
porosity, resistivity, density, and moisture content of
fluid-bearing rocks. Well logs also permit a valid
quantitative interpretation of reservoir characteristics.
Logging programs allow the evaluation of well construction
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and fluid-flow conditions within the well. Originally
developed for the detection of hydrocarbons, today's logging
methods are applied to all classes of injection well
projects.
G. Witnessing Wire-Line Logging - Procedural Checklist
# Obtain construction details of the well. These will
include the following:
- Well name and number,
- Well location,
- Elevation of drill floor, or reference point,
- Hole diameters and depths,
- Casing information,
- Mud parameters, including type, stoppage of circulation,
viscosity, fluid loss, filter cake, and pH, and
- Hole conditions, including oversized hole, doglegs,
tight spots, and deviation records.
# Make sure that the details on the log headings are correct
and that any log faults that would affect log
interpretation not rectified at the well site, are
included in the "Remarks" section.
# Check the depth and register of logs. The casing shoe may
be used as a correlation point. Any disagreement with
driller's depth and maximum logging depth should be
reconciled immediately.
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ฐ Make sure that the correct speed and time constant are
being used. A gap appears in the line at the margin of
track one, or once per minute, so logging speed can be
checked for consistency and correctness.
Make sure that the time constant is recorded in the log
heading.
Obtain details of the horizontal and vertical scales to be
used. Most logs are run on 1:200 and 1s500 scales.
ฐ Advise the operator of the number of field prints
required.
Check the general character of the logs.
- Logs should be run on one scale or a backup should
appear,
- Cyclic variations, zero values, and constant readings
are suspicious,
- Be suspicious of logs that constantly peak or level out
at less than full-scale deflection, and
- Look especially for events that demonstrate the range of
response of the tool, e.g., high and low-porosity beds,
shales, salts, anhydrite, and washouts.
3.3.2 Cementing
Primary cementing of injection wells involves the pumping of a
cement slurry down through an emplaced well casing. Pump pressure
forces cement out from the bottom of the casing, and then upward into
the annular space outside the casing wall. The current common practice
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in Pennsylvania of merely dumping cement down this annulus out on top
of a packer is inadequate and inappropriate. The aforementioned
concept of circulating cement behind the casing is the acceptable
method of primary cementing. Injection wells are usually cemented
completely through the annular space outside each casing string from
setting depth to the surface. After cement is displaced through the
casing, pumps are shut down and cement outside the casing string is
allowed to set up. Primary cementing restricts fluid
movement between downhole formations, and protects and supports the
casing. Secondary cementing refers either to remedial attempts to
complete an inadequate primary job, or to selectively seal off a
particular injection zone without abandonment of the entire well.
"Squeeze cementing" is a commonly used term for secondary cement jobs
that isolate particular zones.
A. Make the following general considerations:
For all types of cement jobs on deep injection wells,
the operator should be advised to use the services of
established well cementing companies. These companies have
the expertise to design a good cement program for an
injection well and have the materials, equipment, and
personnel to do the job correctly.
As detailed by Smith (1976), the American Petroleum
Institute has established eight classes of deep well cements
based upon suitability for use at various depths and
temperatures. A number of special cements for which the
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American Petroleum Institute standards have not been
established, have certain applications in disposal wells.
Pozzolan-lime cements combine the advantages of light weight
and strength at high temperatures. Sulfate-resistant
cements may be used to cement casing directly above the
injection zone when it is expected that the injected
wastewater will have elevated levels of sulfate. Latex
cements may be used to improve bond strength of cement to
casing and to increase the resistance of the hardened cement
to acid. Epoxy resin cements are particularly resistant to
the corrosive effects of acids and other chemicals. These
resins are mixed with a catalyst and used to cement the
bottom portion of the long-string casing where chemically
active injected wastes may be in contact with the cement.
They are also used for squeeze cementing in wells.
Cementing companies may select from more than 40
additives to obtain optimum cement slurry characteristics
for any downhole condition. The general categories of
cement additives include: accelerators, retarders,
light-weight additives, heavy-weight additives,
loss-circulation control additives, water-lost control
additives, and friction reducers.
The volume of cement needed for a casing job includes
the calculated volume of annular space outside the wall,
plus an excess volume of cement to meet contingencies such
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as lost circulation or unaccounted hole volume anomalies
caused by washouts and high porosity zones. Volume of the
annular space outside the casing wall is considered to be
equal to the hole volume determined from a good caliper log,
minus the volume of the casing string to be cemented. An
additional volume of cement, equal from 20 to 30 percent of
the calculated annular cement volume, should also be on
location and ready for pumping to meet the aforementioned
contingencies. If a good caliper log cannot be obtained for
the borehole, the required cement volume can be calculated
from an estimate of hole diameter based upon drill bit size.
However, the percent of excess cement should then be
increased to allow for the relative inaccuracies of this
method.
To obtain a good primary cement job, a number of
devices can be installed in a casing string as the string is
made up. A guide shoe installed on the bottom of each
casing string helps guide the casing downhole to the setting
depth. The shoe is constructed with a beveled edge on
bottom. A float collar is installed on top of the first, or
lowest, joint of a casing string. This tubular device
contains a valve which allows mud and cement to be pumped
down through the pipe, but prevents back flows of fluid up
inside the casing. The float collar holds the cement slurry
in place outside of the casing and resists the slurry's
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tendency (heavier weight column) to back flow until the
cement sets.
Multiple stage tools, or DV (differential valve) tools,
may be installed in a casing string to allow the casing to
be completely cemented in separate operations, or stages.
Use of such tools may be advisable in certain areas to
prevent downhole formations from being subjected to
excessive cement slurry hydrostatic pressure to cause
formation fracturing at the well bore. The stage tool also
is used to emplace different types of cement in the same
hole i.e., separate epoxy from Portland cements in certain
Class I wells. Typically, a stage tool is placed at an
intermediate depth, or about one-half the total depth of the
well.
With a stage tool, the bottom stage of the casing is
cemented first, allowing the cement to harden before the top
stage is commenced. After the bottom stage slurry has
completely passed through the tool on its way down the
casing bore and is in place outside the casing, ports in the
tool are mechanically opened. Excess cement from the bottom
stage can be circulated out of the hole through these open
ports, and mud circulation can be continued while waiting
for the bottom stage cement to harden. When the top stage
slurry is pumped down the casing, the cement circulates
through the oorts in the stage tool and is displaced upward
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outside the casing to the surface. By mechanically closing
the stage tool ports, the top stage slurry is held in place
outside the casing until the cement hardens.
Other tools, equipment and techniques which may
contribute to a successful cement job include the use of
centralizers on the casing string to hold the casing in the
center of the borehole. Also, scratchers may be installed
on the casing in wells that have been drilled with mud.
This enhances the cement bond by removing mud cake from the
borehole. Use of viscous preflush, or mud flush, ahead of
the cement slurry and casing wiper plugs ahead of and behind
the slurry help keep the slurry free of mud contamination.
Displacement of the slurry at maximal rates at or near
turbulent flow conditions downhole, also increases the
chances for good cement bond. Casing strings can be rotated
or reciprocated by the drilling rig during cementing, to
help obtain a more complete filling of the annular spaces,
with minimal occurrence of uncemented channels.
Despite* precautions, a cement job may end prematurely
because of a downhole loss of circulation. This is usually
caused by the presence of weak formations or thief zones
into which a large portion of the cement flows. When an
operator fails to return cement to the surface, a
temperature log and cement bond log should be run according
to service company recommendations at the optimal time
3-46
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following the cementing job to assess the condition of the
hardened cement downhole. If the bond log indicates that
the injection zone was not safely isolated by the primary
cement job, then it will be necessary to perforate the
casing and squeeze cement through the perforations to obtain
satisfactory isolation of the injection zone. When cement
is not returned to the surface one remedial method would be
cementing directly into the unfilled annul us through a small
work string, sometimes referred to as a tremie pipe;
however, this method is predicted to be effective only to
depths of a few hundred feet.
B. Witnessing Primary Cementing - Procedural Checklist
0 Check cement volumes against integrated caliper log if
caliper log has been run. Otherwise, insure that volume
of cement to be used is adequate based on gauged hole
calculations allowing a safety factor for hole
enlargement. Request that several samples of cement be
caught for later evaluation.
Check preflush and spacer volumes.
Check actual number and placement of centraliz^rs against
construction prognosis.
Note if casing is rotated or reciprocated during
cementing, as this a good practice that helps to displace
drilling mud and obtain uniform contact between the cement
and casing.
Observe mud returns during cement displacement to pick
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return of preflush and cement at the surface (very
important). Items to watch for are color change, odor, pH
change, increased funnel viscosity, and density
measurement using a pressurized mud balance. Record time
and cement volume pumped when cement returns are
observed.
Witness bumping of top plug. Record time, displacement
volume and pressure.
Note if casing is open or closed during waiting on cement
time (WOC). Holding pressure on the inside of the casing
during the WOC period can cause a microannulus at the
casing-cement interface.
At conclusion of job, run material balance on water used
and cement used to confirm that cement was mixed as
designed.
Get copy of cement service companies field report from
owner/operator at conclusion of job.
3.3.3 Injectivity and Aquifer Testing
Permeability, thickness, and porosity are major hydraulic
properties of an aquifer upon which quantitative ground-water reservoir
studies are based. These hydraulic properties may be determined by
means of injectivity and pump tests. The effects on a reservoir from
pumping or injecting at a known rate is measured in the subject well or
in additional observation wells penetrating the reservoir. Graphs of
pressure buildup or drawdown, versus time during pumping or injection
operations are used to determine hydraulic properties of a reservior.
3-48
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A. Bottom hole pressure tests are conducted immediately after
well completion to establish the initial reservoir pressure
before injection operations commence: This may be done with
one of various types of downhole pressure instruments which
are run on an electric line or wireline. A less accurate
method is to measure the top of the fluid in the well (or
pressure) and calculate the hydrostatic pressure. If a
bottom hole pressure determination is made by the latter
method, the wellbore fluid must have a uniform density.
B. Injection or production tests conducted prior to putting a
well into operation can provide a fair estimate of formation
properties:
Because of the transient state of a reservoir during the
early part of an injection test, interpretation of test
results are less precise. Injectivity tests conducted later
in the injection operation when steady-state conditions have
been achieved tend to define the permeability and thickness
more precisely. Average reservoir pressure, permeability
and reservoir volume can be determined from pressure decay
or falloff data measured in the shut-in well following
steady-state injection.
Meaningful injectivity test results require sufficient
injection time to insure that steady-state conditions are
approached in the reservoir. The well is then closed in for
a pressure decay test. Bottom-hole and surface pressure are
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recorded during the flow and shut-in periods. Time required
to establish steady-state conditions can be ascertained
through criterion used in the petroleum industry (Matthews
and Russell, 1967) as follows:
At = .000264kt
0A>cre2
= 0.01*0.1 and
'e
c * B ซ -
where
t = dimensionless time, ratio
k = permeability, millidarcies
t = time, hours
0 = porosity, fraction
a = viscosity, centipoise
c = compressibility, psi -1
re = external radius, feet (225 assumed)
<*= rock compressibility, psi
(2 x lO-o assumed)
B= fluid compressibility, psi~l
(3.3 x 10"b assumed)
Within the range of dimensionless times (0.01 to 0.1),
indicated flow in the reservoir approximates steady state
sufficiently enough to give meaningful pressure decay data.
Under typical test conditions, test fluid may be injected for
about 40 hours at about 5 gallons per minute. Many Class II
wells in Region III inject into reservoirs with permeabilities
of 5 millidarcies and a porosity of 15 percent.
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Under the test conditions assumed, the dimensionless time
is: A"t = (,000264)(5)(40)
(. 15) (1.0) (.0000I66)(50,62 5)
= 0.042
Tests conducted under conditions outlined above would
be adequate except in high permeability reservoirs (25-100
millidarcies). Shorter injection and shut-in periods would
be required for higher permeability reservoirs.
B. The following test procedure is recormiended:
After developing a test procedure and providing a
source of clean injection fluid, constant rate injection
should be initiated. A pressure gauge, preferably a
recording type, should be installed on the well head and a
bottom hole pressure gauge lowered into the well as near to
the injection interval as is practical. The gauge should be
lowered into the well 2 or 3 hours before the completion of
the injection operation. The well is shut-in with the gauge
depth at test depth, and the test is continued for about 48
hours.
C. Pressure decay data should be analyzed:
Pressure decay or falloff data recorded after shutting
in the well can be analyzed using the method developed by
Horner (1951) to determine flow properties of the reservoir.
The pressure-time relationship is plotted on semilog paper
as (t+ A t)/At on the log scale versus the measured
3-51
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pressure on the linear scale. The slope of the straight
line portion of the plot should be determined and the
permeable thickness of the injection interval can be
determined through the following relationship:
where:
k = permeability, millidarcies
h = thickness, feet
q = injection rate, gallons per day
= viscosity, centipoise and
m = slope of pressure versus log (t+At) plot.
At
D. Witnessing Injectivity Tests - Procedural Checklist
ฐ Note that injection (pumping) rate should be kept as near
constant as possible throughout the test. Injected fluid
should have the same density.
ฐ Note the sensitivity of pressure and flow rate recording
instruments.
Note if other pumping or injection operations are being
performed in the aquifer which might influence test
results.
Insure that the well is shut in long enough to collect
sufficient pressure decay data. Data should spread across
3-1og cycles of Horner plot.
3.3.4 Mechanical Integrity Testing
Guidelines for witnessing mechanical integrity tests are
discussed in detail in Section 3.4
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3.3.5 Other Preoperational Inspection
In addition to the preceeding suggestions the following actions
may be taken during the permitting or inspection process.
A. Insist on baseline well data in new injection areas.
Various reporting forms have been developed and are used by
EPA during well inventory and data base development.
B. Obtain formation water samples and analyze for common
anions, cations and TDS concentration. For a field of wells
completed to similar depths only representative samples
should be required.
C. Obtain a copy of the analysis report if cores are taken from
the injection and/or confining zones. For a field of wells
completed to similar depths only representative coring
should be required.
D. Request corrosion data using a representative wastewater
sample for corrosive Class I well projects.
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3.4 MECHANICAL INTEGRITY TEST INSPECTIONS
Mechanical integrity inspections are expected to be a major
activity of the Region III inspection team. Several test methods are
approved under the UIC regulations to determine injection well
integrity. The particular method employed is related to well
construction and the detection sensitivity required. Special
techniques have been proposed for determining the integrity of Class II
wells in Region III which do not have protection casing. The
mechanical integrity tests described in this chapter are either
specified by the EPA (Section 146.08) or are available for use as
alternative methods upon approval by the Director.
Mechanical integrity test inspections of Class II wells in Region
III will be run on a 5 year cycle with priority levels assigned to
wells according to their construction details. Wells with a minimum of
casing and cementing and those located near groundwater contamination
areas will be given first consideration.
3.4.1 Alternative Mechanical Integrity Testing Procedures
By current legal definition there are two aspects to mechanical
integrity. First, a well must be free of significant leaks in the
tubing, casing and packer(s). This is referred to as "internal"
mechanical integrity. Second, there must not be significant fluid
movement outside the casing through vertical channels adjacent to the
wellbore. This is referred to as "external" mechanical integrity.
The practical method used to demonstrate internal mechanical
integrity in most wells is to apply pressure to the area between the
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casing and tubing (called the annulus) and monitor for pressure losses
or gains. A proof of external mechanical integrity generally requires
electric logs, such as radioactive tracer surveys, temperature surveys
or others.
Other procedures for demonstrating mechanical integrity must apply
to many Class II wells in Region III due to existing well construction.
These wells have "open hole" completions and are uncased below the
surface casing depths. There is therefore no closed annular space
between the protection casing and the injection tubing which may be
pressurized. Methods for testing these Class II wells are discussed in
Section 3.4.3.
The procedures which follow are restricted to cased wells with
positive packer and wellhead seals.
Internal Mechanical Integrity - Procedural Checklist:
A. Determine the density of the annulus fluid and fluid in the
injection tubing.
B. Insure that the hydrostatic pressure in the annulus (ie. test
pressure) is 1) greater than the formation pressure and 2)
greater than the hydrostatic pressure in the tubing. That is,
1) SCP + .052 x (CF) x (Depth) > .465 x (Depth) and
2) SCP + .052 x (CF) x (Depth) > .052 x (TF) x (Depth) + SITP
where
SCP - surface pressure on the casing, psi
CF - casing fluid in pounds per gallon (ppg)
Depth - depth to packer, feet
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TF - tubing fluid in pounds per gallon (ppg)
SITP - shut-in surface tubing pressure, psi
For example, if the well has a packer at 3000 ft. with a 10
ppg annul us fluid and 8.5 ppg tubing fluid with no surface
shut-in pressure, then the necessary casing pressure must
satisfy:
1) SCP + 1560 > 1395 and
2) SCP + .052 (10.0) (3000) > .052 (8.5) (3000) + 0
i.e., SCP + 1560 > 1326
C. Determine type of packer.
If the packer in the well is a compression set packer
(i.e., tubing weight is placed on the packer to effect a
seal), then additional annulus pressure will tend to effect a
better seal. However, a tension-set packer (i.e., tubing
tension is needed to effect a seal) will tend to unseat itself
with increased annulus pressure.
It is the owner/operator's judgement as to the
acceptability of the proposed test pressures. The original
tubing tension at the time the well was completed will
determine the possibility of unseating. If the owner/operator
objects, then an alternate test procedure is given under
checklist, item F.
D. Insure that the annulus is absolutely full of water. Air
bubbles will sometimes dissolve in teh annulus fluid during
testing causing a change in the shut-in pressure.
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Apply the pressure test for 45 minutes to one hour. If the
casing holds pressure it can be concluded that the well has
internal mechanical integrity. If the pressure reading has
slightly decreased, it may be an air bubble or perhaps
temperatures in the well bore have not stabilized. In any
case, the next step is to repressure the annul us and monitor
again. If after this second period, the pressure again
decreases, a leak is probable. Pressure increases initially
are also possible, but should stabilize after a while. For
instance, the heating of the pressure gauge itself by sunlight
might cause small readjustments in the gauge reading.
Conduct dynamic test if the injection well can not be tested
statically by the above procedure. Here dynamic means to test
for a leak while injecting. The most dependable method for a
dynamic test is to use continuous monitoring charts taken over
a period of time, usually seven days, and will include a
continuous record of tubing injection pressure and casing
annul us pressure.
Be aware that the continuous monitoring charts will,
unfortumately, include the effects of annul us pressure changes
caused by injection pressure changes, injection temperature
changes, as well as changes due to leaks.
Maintain the annul us pressure such that the hydrostatic
pressure in the annul us at any depth is both greater than
formation pressure and tubing hydrostatic pressure. The case
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where casing hydrostatic pressure is not greater than tubing
hydrostatic pressure will be addressed under checklist item I.
The formation pressure at any depth is given by FP - 0.465 x
(Depth). The tubing hydrostatic pressure is given by:
TH = .052 x (TF) x Depth - FR + STP
where
TF - injection fluid density, ppg
Depth - depth to packer, feet
FR - frictional pressure drop (see Figure 3.3), psi
STP - surface injection pressure, psi
The annul us hydrostatic pressure is given by:
CH = .052 x (CF) x (Depth) + SCP
where
CF - casing fluid density, ppg
SCP - surface casing pressure, psi
For example, tubing injection pressure is 1100 psi,
injecting 2 bbls per minute of 9 ppg water in 2 7/8" tubing
with a packer at 4000 feet. Casing fluid is 10 ppg water,
with a minimum surface pressure of 500 psi as recorded on a
continuous recording device. The frictional pressure drop
(from Fig. 3.3) is 2.5 psi/100 ft for 2 bbls/min., or a total
of 100 psi. Formation pressure is 1860 psi at depth and the
tubing hydrostatic pressure is, TH = 1872 - 100 + 1100 = 1872
psi. Hence, tubing hydrostatic pressure is the greater of the
two. Casing pressure at depth is CH = 2080 + 600 = 2860 psi.
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The above example concludes that the surface casing
pressure is not large enough to conclusively determine
mechanical integrity. Approximately 200 psi additional casing
pressure would result in hydrostatic pressures being equal at
the packer. Consequently, an additional 200 + psi casing
pressure would be recommended. That is, casing pressure
somewhat in excess of 800 psi should be used in the above
example to effectively indicate mechanical integrity from
continuous monitoring records. If this casing pressure is
unacceptable for any reason, the alternate test procedures
under checklist items I and J should be considered.
I. Address the case where annulus hydrostatic pressure does not
exceed tubing hydrostatic pressure. First, at a minimum,
annulus hydrostatic pressure must be greater than formation
pressure to insure against a casing leak. That is,
SCP + .052 (CF) x (Depth) > .465 x (Depth)
where
SCP - surface casing pressure, psi
CF - casing fluid density, ppg
Depth - depth to packer, feet
Once this criteria is met, the question of testing for a
tubing leak can be addressed.
If tubing hydrostatic pressure is greater than casing
hydrostatic pressure both at the surface and at the packer,
then it is normally greater at every depth. This would
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5 6 7 8 10 20
FLOW RATE BPM
80 100
FIGURE 3.3 FRICTION PRESSURE LOSS VS. INJECTION RATE FOR COMMON TUBING
AND CASING SIZES.
-------
suffice to prove the integrity of the tubing, since, if a leak
did exist, casing pressure would rise and hydrostatic
pressures would equalize at some depth.
This criteria is:
STP > SCP
and
STP + .052 (TF) x Depth - FR x Depth > SCP + .052 x (CF)
100
x Depth
where
STP - surface tubing pressure, psi
SCP - surface casing pressure, psi
TF - tubing fluid, ppg
CF - casing fluid, ppg
Depth - depth to packer, feet
FR - frictional pressure loss per 100 feet (see Figure
3.3)
In the previous example of the well injecting 2 bbls per
minute, we see that
SCP + .052 (10) (4000) > .465 (4000)
or
600 + 2080 > 1860
That is, the casing hydrostatic pressure exceeds formation
pressure at any depth. Also, looking at the tubing
hydrostatic pressure, we have
1100 > 600
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and
STP + .052 (9) (4000) - 2.5(40) > 600 + .052 (10) (4000)
or
1100 + 1872 - 100 > 600 + 2080
2872 > 2680
This shows that tubing hydrostatic pressure exceeds
casing hydrostatic pressure by approximately 192 psi. A
pressure differential of this magnitude is a good indication
that no tubing leaks exist.
J. Consider the case where all of the above techniques do not
conclusively prove mechanical integrity. Therefore,
continuous monitoring records cannot be used, but rather,
further testing is required. Another set of values for
surface tubing and casing pressures will suffice. The logic
here is, if a tubing leak does exist, then hydrostatic
pressures would have equalized, and the surface pressures
would take on values reflecting this fact. However, another
set of pressures, either raising or lowering injection or
casing pressure, would upset this equilization and be
reflected in the subsequent observations.
H. Carefully study monitoring records to be certain that a proper
evaluation has been made. Certain pressure fluctuations are
expected if the tubing injection pressure changes.
In view of the above procedures involved in mechanical
integrity testing, it is important to realize that general
statements concerning injection wells as a whole can not be
3-62
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made. Rather, each well is an individual case, and testing
procedures should be carefully engineered to insure against
needless expense and erroneous conclusions.
External Mechanical Integrity
Geophysical Logs
Two geophysical logs are allowed under Section 146.08 to determine
the absence of fluid movement behind the casing. These are the Noise
Log and the Temperature Log. Their interpretations, applications and
limitations are discussed below.
A. Understand the application and interpretation of the Noise Log
The Noise log is used to determine mechanical integrity
of injection wells by measuring and analyzing noise generated
downhole by flowing liquids (or gases). This tool records
sound amplitude and frequency levels versus depth to produce a
log capable of tracing a channel flow pattern. In addition,
the tool is normally capable of discriminating between single
phase (all liquids or all gases) and two-phase (liquid and
gas) flow. In injection wells the flow will almost always be
single phase (liquid).
The amplitude profile is a measure of the amount of noise
generated by a flow which in turn is proportional to the
volume of the flow and the pressure differential acting on the
flow. The greatest pressure differentials occur at the source
of the flow (i.e., the difference in pressure between the
channel and the formation accepting the flow). The Noise log
depicts these differences in pressure as peaks.
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The frequency range of the noise log is approximately 200
to 6000HZ and is registered on the log as amplitude curves
at various frequency levels. The frequency levels are
indicative of the pressure differentials described above. The
greater the pressure difference, the higher the frequency
level and conversely the lower the pressure differential, the
lower the frequency level.
Figure 3.4 illustrates high-rate channeling in an
injection well. High injection pressures are forcing fluid
through a cement channel into receptive upper sands (B-l, A-3,
A-2). Note also that the 200 Hz amplitude curve varies from
a minimum of 4 mv below 6100 feet (the no-leak level) to a
maximum of 1000 mv at 5870 feet where there is an apparent
obstruction in the channel behind the pipe.
B. Understand the application and interpretation of the
Temperature Log:
Temperature log surveys are used to locate cement tops,
tubing or casing leaks, and depicts channeling behind casing.
This log measures the temperature variations in a well which
are dependent on volumes of materials, rate of fluid movement,
temperature differences between the media and length of time
that heat transfer has taken place.
In locating cement column tops, temperature surveys are
run approximately 6 to 12 hours after a string of casing has
been cemented. During the setting process the cement gives
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000.0
5400
A-2
SAND
A-3
SAND
5500
5600
5700
B-l
SAND
5800
5900
000
100
FIGURE 3.4 NOISE LOG SENSING HIGH FLOW RATE BEHIND CASING
-------
off heat and the temperature log responds to this heat by
recording higher temperatures at the depths corresponding to
the cement column outside the casing (See Fig. 3.5).
Tubing or casing leaks can be confirmed and pinpointed
through use of the temperature log. Fluid entering or exiting
a point in the well should result in an identifiable
temperature change. The resulting temperature profile is then
compared with an assumed or normal temperature gradient for
the well. Examples of these types of situations are
illustrated in Fig. 3.6.
In detecting channeling behind the casing, static
conditions are needed in the well. A flowing well would make
it impossible to detect the temperature difference produced by
channeling, because the log would reflect the temperature of
the flowing fluid inside the cased interval too.
C. Understand the limitations of Noise and Temperature Logs:
The Nose and Temperature Logs are both feasible for all
clsases of injection wells. Several construction details of
the well must be considered, however:
The well must be constructed with a protection casing for
either log to be feasible.
# The amplitude of the Noise Log may be effected by different
construction materials, for this reason the Noise log is
charted with teh tool in a stationary position and the
information is recorded on a staged basis.
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COLLAR LOG TEMPERATURE ฐF
107ฎ ;37ฐ
CF-MENT
J TOP
k
K
V
N
FIGURE 3.5
EXAMPLE OF TEMPERATURE LOG SHOWING
TOP OF CEMENT
-------
INCREASING
fluid
ENTRY
TO THE
CHANNEL
FLUID
EX'T
PROM THE
CHANNEL
FLUID
'ENTRY
example a
EXAMPLE B
EXAMPLE C
NATURAL OEOTHERMAL
ORADlENT A3 MEASURED
IN A STABLE WELL
TEMPERATURE ANOMALY
SUPERIMPOSED ON OEO*
THERMAL ORADlENT
INDICATIVE OT OOWNWARO
FLOW THROUGH A CHANNEL
BEHIND THE WELL CASINO
TEMPERATURE ANOMALY
SUPERIMPOSED ON SEO-
*?>ซERMAL orament
9NDICATIVS OF UPWARD
ruDW THROUOH A CHANNEL
BEHIKCTME WELL eASINtt
FIGURE 3.6 EXAMPLES OF TEMPERATURE LOGS SHOWING THE NATURAL GEOTHERMAL
GRADIENT AND ANOMALIES CAUSED BY FLOW THROUGH A CHANNEL BEHIND
THE WELL CASING
-------
The injection tubing must be removed from the well to detect
fluid movement behind the casing before running either log.
ฐ The larger the diameter of the well the less the sensitivity
of the Temperature Log.
D. Understand the application and interpretation of the
Radioactive Tracer Survey:
In cased injection wells with tubing and packer
installed, it is possible to conduct a Radioactive Tracer
Survey in lieu of pulling the tubing string and running a
Temperature or Noise Log. This technique saves the cost and
time involved in pulling the tubing but currently requires
special approval by the Director.
The Radioactive (R/A) Tracer Survey is run utilizing an
iodine isotope solution. Radioactive iodine solution has an
8-day half life and decays totally within a period of 30 days.
Survey is conducted by running a Garmia Ray tool down injection
tubing from total depth up past the zone of interest. This
base log is run initially for comparative purposes against log
runs made while injecting the radioactive solution. R/A
solution is injected into the well bore fluid either from the
surface or directly from the logging tool and then displaced
using either fresh water, brine or effluent fluids. The Gamma
Ray tool is rerun several times to "track" the R/A solution
(1) in the wellbore area, (2) exiting the casing and (3) into
the injectin interval. The logging tool is rerun to obtain
identical repeat measurements of Gamma Ray counts.
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While conducting the Radioactive Tracer Survey, fluid is
pumped into the well at a controlled rate of 10-20 GPM. One
repeat run of the Gamma Ray log is obtained over the injection
interval and immediately above this section. If no change in
Gamma Ray count above the top of the disposal interval is
detected, then no external migration of injected effluent is
present in the well.
An example of the Radioactive Tracer Log in Fig. 3.7
shows the detection of a leak in the casing and subsequent
fluid movement in a channel behind the casing. Note that the
log which was run after injecting R/A material is superimposed
on the base log.
Well Record Evidence of Mechanical Integrity
The mechanical integrity of an injection well may be demonstrated
by well records showing the presence of adequate cement to prevent
fluid migration or by records of injection well monitoring programs.
Mechanical integrity evidence of this kind os reserved for certain
types of Class II and Class III injection wells.
A. Determine whether or not adequate cement exists in teh well by
comparing the emplaced cement volume and the volume of the
space between the outer casing and well bore (annulus). The
annul us volume is calculated from the outside casing diameter
and a caliper log reading of the well bore. An adequate
cement sheath is likely to exist when the injected cement
volume is greater than the calculated annular volume by a
factor of at least 1.2
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INCREASING
GAMMA RADIATION
GAMMA RAY LOG
TAKEN AFTER
INJECTION
i-nsr
I
-FLUID
MOVEMENT
IN CHANNEL
RADIOACTIVE TRACER LP6
WELL DIAGRAM
FIGURE 3.7
RADIOACTIVE TRACER LOG SHOWING THE DETECTION OF A LEAK IN THE
CASING AND SUBEQUENT FLUID MOVEMENT IN A CHANNEL BEHIND THE CASING
-------
B. Evaluate cement bond logs and temperature logs as an
indication of adequate cement in the well. Owners/operators
should keep accurate records of these logs for mechanical
integrity evidence.
C. A record of the cement top in a relatively new shallow well
can be taken by dropping a weighted line down the annul us
space until it hits resistance. This resulting measurement
may indicate the level of cement fill-up.
D. Examine cement records. Cementing records are applicable to
certain Class II injection wells associated with the
production of oil and gas. These exceptions are made so as
not to halt or impede oil and gas production by the
requirement of a geophysical log. The mechanical integrity
of Class III wells with casing that precludes the use of
logging techniques may also be demonstrated by cement
records.
E. Examine monitoring records. Records of injection well
monitoring showing the absence of significant changes in the
relationship between injection pressure and injection flow
rate can be used to demonstrate mechanical integrity for
Class II wells associated with enhanced recovery. These
exceptions include Class II wells completed without either a
packer or protection casing.
3.4.3 Specific Requirements of EPA Region III
Several alternative mechanical integrity testing procedures for
testing certain Class II injection wells have been presented in an EPA
3-72
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sponsored study entitled Mechanical Integrity Tests - Class II Wells,
Review and Recommendation. Due to the competency of the underlying
strata, these wells require no protection casing and thus have
"open-hole" completions below the surface casing. Lack of a protection
casing precludes pressure testing for mechanical integrity because
there is no closed annular space. The following mechanical integrity
test procedure is proposed:
Observation of Water Level Rate-of-Change in the Annul us -
Procedural Checklist
The method consists of two stages of tests lasting approximately
one hour each. Stage one is performed by shutting in the well while
stage two consists of applying a normal injection rate to the tubing.
Prior to proceeding with stage one and stage two of the test, the
annul us of the injection well is filled with water and the resultant
height of the water column inside the surface casing is measured.
A. Adjust the water level in the annul us to about 2 feet below
the surface by adding or removing water while the well is
not active.
B. Observe fluid level for one hour *r>d take periodic
measurements. If no drop occurs there is probably no
significant leak in the surface pipe or water obsorption
into exposed formations. If fluid level drops rapidly go to
checklist itenx D.
C. Initiate injection and continue to monitor the annulur fluid
level. If no increase in fluid level occurs then the well
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has mechanical integrity. If the level does change there is
probably a leak in the tubing, packer-cement combination,
the formation behind the cement, or a combination of these.
D. If the water level, with no injection pressure applied,
drops in the range 5-50 feet/hour consider further testing
using a shielded monoelectrode (Fig. 3.8). If the water
level drops more than 50 ft/hr consider additional testing
utilizing an echometer (sonic device).
E. Examine the well's injection records. If a well develops a
leak in the tubing or cement it will intake more water for a
constant wellhead pressure and the apparent injectivity of
the well (BPD/psi) should increase. In principle then, a
leak should be detectable by periodic monitoring of well
injectivity.
3.4.4 Manifold Monitoring for Mechanical Integrity Testing
The Agency currently contends that injection wells are to be
tested for Mechanical integrity individually. Available evidence
indicates that the sensitivity of a manifold system is not adequate for
mechanical integrity determinations, but may be used for routine
monitoring.
This method of mechanical integrity testing involves continuous
monitoring of the injectivity of a cluster of wells. Permanent flow
rate and pressure recording instruments are set up at a designated
number of manifold sites where each manifold supplies a cluster of
wells in its area.
3-74
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%
s%.
Xv.
V ...
<&*
V
.c^
FIGURE 3.8
MONOELECTRODE PROBE FOR WATER LEVEL DETECTION
f I
Ki:.\ 1%. 11 a v ih
I A Tlx
-------
Manifold monitoring would at best indicate that one of the
proceeding methods of mechanical integrity testing would have to be
performed on each well to locate a leak.
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3.5 PLUGGING & ABANDONMENT (P & A)
Compliance monitoring of plugging and abandonment proceedings is a
primary responsibility of the EPA Region III inspector. Realizing that
proper abandonment consists of more than setting a cement plug in a
hole, the inspector should familiarize himself with the appropriate
regulatory requirements and the technical references listed at the end
of this chapter.
The Underground Injection Control program includes regulations (40
CFR 146.10) to ensure that abandoned injection wells do not endanger
underground sources of drinking water. This is the overall objective
of evaluating all P & A programs. Since the Federal regulations are
not yet specific relative to the placement of cement plugs, the
inspector should be aware of the state regulations used in Region III
prior to inception of the UIC program. The state regulations have
heretofore set the local industry standards for well closures.
A brief summary of the P & A requirements of oil, gas and water
injection wells for the States of Pennsylvania, Virginia and West
Virginia are listed below. In all three states the regulations specify
that the body shall be notified of the intentions to plug and abandon a
well. Most states have forms for this purpose detailing the
information desired.
Pennsylvania - Department of Environmental Resources
Oil and Gas Division - Article II - Section 205-207.
For wells not underlaid by coal seam, the well shall be filled
with sand dumpings or mud, as Division may approve, from bottom of the
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well to a point 20 feet above the top of the lowest production zone.
At this point, place a plug of cement for at least 20 feet. Between
this cement plug and 20 feet above the highest production stratum, fill
the hole in same manner as described above. Place a bridge plug
approximately 30 feet below the surface casing depth and put a 10-foot
cement plug on top of the bridge plug. Withdraw the surface casing and
then place the final plug from 10 feet below surface casing depth to
the surface using mud or sand dumpings.
In a well passing through coal seams, production zones shall be
plugged as described above. A plug shall also be placed 10 feet below
the bottom of the smallest coal protecting string and the hole filled
with 20 feet of rock or gravel. A vent pipe shall be placed on the
gravel to remove any free gas. The space around the vent pipe shall be
filled with 5 feet of sand pumpings, then with cement to 25 feet above
highest workable coal seam.
Virginia - Department of Labor and Industry - Mining Laws - Article 4,
Rules 45.1 - 128 thru 131.
Well shall be plugged in same manner as specified for
Pennsylvania.
West Virginia - Department of Mines - Oil and Gas Division -
Chapter 22-4 - Rules 2.11 - 2.14.
Well shall be plugged in such a manner as to prevent the migration
of oil, gas or water to any strata other than their original strata.
Cement or other suitable plugs may be used. Location and length of
plugs to be approved by Department.
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3.5.1 Basic Considerations
A. Evaluate the P & A program based on well classification.
The Region III inspector will be concerned primarily with
the abandonment of Class II injection wells utilized in the
secondary recovery of oil. The operational status of the
well should also be determined from one of the following:
(1) drilled but never used (2) operating (3) abandoned but
not plugged (4) not operating and plugged (improperly).
The above classification and categories will be helpful in
evaluating the plugging and abandonment program.
B. Judge the abandonment schedule on a case by case basis:
Under certain circumstances the EPA will make a
determination whether to abandon a well immediately upon
cessation of operations. It may be necessary to abandon an
injection well within a determined length of time to avoid
the risk of environmental damage. Current regulations do
not specify the time period required between cessation of
operations and the actual date of abandonment. The
inspector may be involved in determining this time period by
evaluating a given well and the degree of underground
contamination that is likely to occur by the injected
fluid.
C. Focus on the objective:
Note that the abandonment process should utilize procedures
designed to ensure the well's basic mechanical integrity and
3-79
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to emplace one or more effective cement plugs at selected
depths.
D. Recognize major phases in P & A:
An abandonment procedure involves two phases (1) well
preparation and (2) well plugging.
Well preparation involves all activities necessary to ready
the well for plug setting and final abandonment. The
location of aquifers requiring protection and the means of
isolating these aquifers need to be determined. In many
cases, the well can be entered and inspected to ascertain
its condition. Tubing, packer, salvageable casing, and
other materials can be removed. Remedial activities such as
well cleanout, fishing, milling, or squeeze cementing may be
necessary to ensure well integrity and the effective
placement of the cement plug(s).
Plugging involves placing cement in a well either over its
entire depth or at a series of discrete locations. If a
series of plugs is set, a plugging fluid (generally drilling
fluid) is left in the well between the plugs. In addition
to cement plugs, mechanical plugs can also be used. A
variety of placement techniques are available which
generally involve pumping the cement through the drill pipe
or tubing.
E. Examine the well design and configuration particularly after
well preparation:
3-80
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The procedures used for proper abandonment of an injection
well are dependent on well construction especially the
casing and cementing program, and completion method used.
Certain design characteristics however, can be altered in
the final preparation for abandonment. In most cases well
preparation will involve cutting and removal of the tubing
and emplacement of a plug inside the tubing near the cement
packer. Consequently, the inspector may be reviewing a
plugging plan for a well configuration substantially
different from that shown in the well design documents. The
four most common well types are:
1. Open hole with surface pipe not cemented and no
protection casing
2. Open hole with surface pipe partially cemented and no
protection casing
3. Open hole with surface pipe cemented to surface and no
protection casing.
4. Surface pipe cemented and protection string set and
cemented
3.5.2 Considerations While Evaluating the Abandonment Program:
New water-flood injection wells (type 4) may be completed as
shown in Figure 3.9. A casing, typically 5 1/2" to 8 5/8" in diameter
is run to bottom and cemented in place. The injection tubing is
removed from the well prior to P & A proceedings. Plugs are generally
set (at a minimum) above the perforations, across the USDW and at the
surface.
3-81
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In Pennsylvania and New York there are a significant number of
water-flood injection wells drilled prior to 1983 which are completed
without a full string of casing, as shown in Figures 3.10, 3.11 and
3.12. During drilling, the water sands down to about 600' are first
cased off with 7" casing. Cement behind the casing may be nil in type
1 wells completed prior to 1972 (the bottom of the casing sealing in
shale) partially filled as in type 2 wells, or completely filled up to
the conductor pipe as in recent wells (type 3). Drilling then proceeds
to total depth (1000-2000'), typically with air drilling techniques.
When the target injection zone is penetrated, 2" injection tubing is
run in with a packer on bottom and the latter is set against the
formation just above the injection zone. Usually 10 sacks of cement
(about 50') are placed above the packer (using either a 1" "macaroni"
string temporarily run in the annulus, or by simply dumping it in),
although some old wells may have no cement and new wells may have
cement up to the 7" surface casing. Typically Cement Bond Logs are not
run in either casing or tubing, even in new wells, to save expense.
In types 1, 2 and 3 wells the injection tubing must be cut above
the cement anchor in order to remove the tubing from the well. Four
plugs are emplaced at a minimum. Plug locations include the
injection zone, the top of the 2 3/8" tubing stub, in and out of the
surface casing and at the surface. Alternately a mechanical bridge
plug may be set above the injection zone rather than filling it with
cement.
3-82
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iNJECTING
V/J
PLUGGED
FIGURE 3.9
TYPE 4 - TYPICAL CLASS II INJECTION WELL (RECENT) EPA REGION HI
K i<.\ I-:. 11 a v i n
M I fc'0't.*>
-------
INJECTING
PLUGGED
SURFACE
ซATII? MORIZOM
PttOOUOM HORIZON
-BOTTOM Of HOi.1-
FIGURE 3.10
TYPE I " TYPICAL CLASS H INJECTION WELL PRIOR TO c. 1972 EPA REGION HI
Sv !:."ซ> i:. Iปavin
-------
PLUGGED INJECTING
FIGURE 3.11
TYPE 2 " TYPICAL CLASS IT INJECTION WELL c. 1972 - 1983 EPA REGION HI
kซ:.n n.wiN
Ammih i \Ti:w
-------
PLUGGED
FIGURE 3.12
TYPE 3 ~ TYPICAL CLASS 31 INJECTION WELL c
-------
BOREHOLE
CASING
CEMENT
OPEN HOLE
BOREHOLE
SURFACE CASING
CEMENT
BOREHOLE
PROTECTION CASING
CEMENT
OPEN HOLE
CCrv* #ปV t*"
BOREHOLE
CEMENT
SURFACE CASING
BOREHOLE
CEMENT
FIRST INTERMEDIATE
CASING
BOREHOLE
CEMENT
SECOND INTERMEDIATE
CASING
BOEHOLE
CEMENT
LINER
OPEN HOLE
BOREHOLE
CEMENT
SURFACE CASING
0_B
OPEN HOLE
STUB OF CUT CASING
CEMENT
PERFORATED INTERVAL
FIGURE 3.13 COMMON WELL CONFIGURATION AFTER WELL PREPARATION
Ki:n I1 \ is
I VI Kh
-------
FIGURE 3.14
PLUG LOCATIONS IN A WELL WITH INSUFFICENT SURFACE CASING
Ki:.\ K. IUvi
Vmmm I A l l
-------
All P & A procedures require cutting of the conductor casing in
agricultural areas below plow depth (about 3') and the setting of
additional plugs across potentially commercial mineral reserves
(including oil or gas).
While evaluating an effective well-abandonment program, be aware
of the factors that may need particular attention. The following
considerations, are the most important:
A. Review the locations to set cement plugs:
A variety of approaches are used to determine plug
locations. In most cases it is not necessary to install a
continuous plug in a well. A series of plugs set across or
above potential oil and gas producing zones, the base of the
surface casing and at the surface is often sufficient
providing the plugs are separated by an adequate plugging
fluid.
Review the configuration of the well (Figure 3.13) and
determine the changes required prior to actually placing the
plugs. For example consider a situation that an original
well has insufficient surface casing i.e., the base of the
usable water lies below this casing. You shall recommend
about three plugs in this situation. After the plugs are
set, the well diagram will appear as shown in Figure 3.14.
Study the well diagrams included in Appendix A which
illustrate typical plugging problems. This Appendix
represents practices used in the State of Texas. The Region
3-89
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Ill inspector may modify the plug locations for specific
geological conditions and well configurations.
B. Inspect mechanical integrity records with respect to
corrosion:
Injection-well casing and cements are subject to corrosion
and degradation by injection fluids and formation fluids.
Corrosion of the well casing or degradation of primary
cement can significantly impair any attempt to prevent
leakage up the borehole. The placement of plugs to prevent
migration of fluids inside the well casing will serve little
purpose if injection fluids or formation fluids are able to
migrate through a poorly cemented annular space between the
casing and the formation.
The injection wells are also subject to mechanical stresses
during installation and operation that may result in casing
damage and leakage. Deformation of the casing may also
result, weakening the casing, or preventing the entry or
normal functioning of tools necessary to plugging
operations. In addition, the well may contain debris that
may significantly compromise the effectiveness of the
abandonment program.
C. Consider top to bottom cementing of Class III wells, if
practical:
Unlike Class I and Class II wells, Class III mineral
extraction wells could be shallow and, directly installed
3-90
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into an unconsolidated sand and gravel formation. However,
if the Class III well is a deep well, the plugging procedure
would be the same as that of Class II wells.
The relative shallowness and small diameter of Class III
wells have resulted in abandonment practices which typically
differ in several respects from those of Class I and II
wells. Generally, Class III wells are easier and less
expensive to cement from top to bottom using no mechanical
plug or only an inexpensive rubber plug.
D. Make proper cement selection.
The selection of a cement composition for a cement plug will
depend on well depth, temperature and mud properties.
Thickening time is suggested to be job running time plus one
(1) hour at the temperature and pressure conditions for the
plug depth. The cement used should also develop a high
compressive strength and tolerate any mud contamination that
might occur during placement.
Class A cement is most often used as a plugging material for
Class II wells in Region III. This cement is intended for
use from the surface to a depth of 6000'. The recommended
water-cement ratio, according to API is 0.46 by weight (5.2
sks/gallon). It may be densified with a dispersant and the
setting time can be accelerated with the addition of calcium
chloride.
3-91
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3.5.3 Well Preparation & Plug Installation Procedure:
The following general procedure should be helpful in evaluating
a successful P & A plan.
A. Move in work-over rig and remove tubing:
Two initial steps are common to all abandonment operations.
The first step is to move in a work-over rig of a size and
power commensurate with the well depth and diameter. The
next step is to remove any injection tubing in the well.
Where there is tubing and a packer, it is possible eithc to
remove both or to cut off the tubing above the packer after
placing a plug inside the tubing.
B. Have the hole cleaned, if required:
Subsequent steps depend upon the condition of the casing.
If the well casing above the cut off tubing and packer is in
good condition, it is possible to complete abandonment by
placing cement plugs at the required locations. In other
cases, the next step is to clean out the hole to the bottom.
Although this procedure typically is quick, it could involve
removal of debris with a junk basket or fishing operation.
The fishing could be simple or long and arduous. Proper
cleaning of the hole is necessary to set plugs effectively.
C. Achieve static equilibrium by circulating mud.
After cleaning the hole, the next step is to establish a mud
system and, by circulating it, to achieve static
equilibrium. Indicators of the achievement of static
3-92
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equilibrium are the absence of mud movement and the
exclusion of those fluids and gases which would cause
movement. The importance of achieving static equilibrium is
to prevent any contamination or breakup of the cement which
would weaken it and result in a poorly set plug. In wells
under pressure, the mud can we weighted through the use of
additives such as salt, barite, iron oxide ar galena, or a
blowout preventer can be used to overcome the pressure.
When a blowout preventer is used, pressure occurs on its
underside but the mud, nevertheless, can be circulated to
static equilibrium.
D. Clean the casing or open hole surfaces with rotating
scratchers:
The final step in well preparation is to prepare the casing
wall or wall of the open hole for cementing. The lower
portion of the tubing or drill pipe that is lowered in the
hole to set the plug and cement should be equipped with
centralizers and rotating wall scratchers. The rotation of
the scratchers cleans the bore to accomplish better bonding,
allows bypassed mud to mix uniformly with the cement, helps
to minimize or prevent the formation of channels in the
cement, and minimizes mud contamination. This tool may be
used with a scouring type chemical wash which will flush the
sides of the well.
E. Evaluate Plug Placement
The circumstances under which static equilibrium of the mud
3-93
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system has been achieved will affect the manner of plug
placement. If the mud has been brought to static
equilibrium without the use of a blowout preventer, a
mechanical bridge plug is lowered very carefully to the
desired depths. A small cement plug is then spotted on top
of the bridge plug. Additional cement plugs may then be
placed at selected intervals using either the balanced or
two plug method.
Blow-out preventers are not normally used in Region III.
Where a blowout preventer has been used, the plugs are set
through the preventer. After the bottom plug is set the
upward pressure on the underside of the blowout preventer
subsides to zero so that the blowout preventer can be
removed and additional cement plug(s) installed.
F. Be knowledgeable about common methods of plug installation:
Several methods of plug installation are acceptable under
the UIC program. Of these, the Balance Method is the most
common. The Cement Retainer and Two-Plug Methods are seldom
used in Region III. Each of these three methods is
discussed below.
1. The Balance Method
This technique involves the setting of a cement plug in
the bottom of the casing or at some other predetermined
point that may be above the bottom of the casing or in
the open hole below the casing. The cement slurry is
pumped down the drill pipe or tubing and back up to a
3-94
-------
calculated height that will balance the cement inside
and outside the pipe. The pipe is then pulled slowly
out of the top of the cement. When the pipe is a
considerable distance above the top of the cement, the
pipe is cleaned by reverse circulation.
In this method, a small-diameter pipe or tubing string
is used in order to leave as large an annul us area as
possible outside of the cement pipe. This will allow
the cement pipe to be pulled from the well without
causing an excessive drop in the cement or a surge of
the cement plug, thereby decreasing the chance of mud
contamination.
It is essential that the mud system be in static
equilibrium as any fluid movement can cause a poor plug.
In order to do a balanced plug job, calculations must be
conducted to determine cement volumes and heights of
fluid. An example of the calculations involved is
presented in Appendix B.
2. The Cement Retainer Method
This technique involves the installation of a cement
retainer (packer) plug within a cased hole. The cement
can be displaced through the cement retainer so that the
formations below the retainer can be squeezed with
cement. After the cementing of those formations, the
cement retainer can be closed at the bottom and the
3-95
-------
cement pipe backed off from the top of the retainer.
Cement then can be placed on top of the retainer by
slowly withdrawing the cement pipe above it. The
advantages of this system are:
Placement of the cement below the retainer, assuring
an effective plug upon closing the retainer valve,
Forcing of the cement into the formation without
subjecting the old casings to high pressure,
Maintenance of good control of the cement,
Preclusion of gas percolations from the formations
up past the retainer, allowing setting of the cement
above the retainer without any gas diffusion, and
Performance of pressure testing immediately after
the retainer is set.
This method is one that is highly regarded for placing
cement under pressure into a producing formation or
injection zone, either through an open borehole, or
through casing perforations, or screens.
3. The Two-Plug Method
The principal use of this method is in an open hole,
utilizing a plug catcher (Figure 3.15) into which two
separate plugs are injected. It is designed to allow a
bottom cementing plug to pass through the bottom plug
catcher and out of the tubing or drill pipe. Cement is
then pumped out of the string at the plugging depth to
3-96
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Si
Jis
Iฎ
- ,
;.v.V3
J
-PLUG CATCHER
-CEMENT ENTERS ANNULUS
-BOTTOM PLUG PUMPED OUT
ii
!vv.': I;-*
!v\v.v.:.:
II
m
n
W
^ ฆ *
\ r
> ฆ :r
> i f
\r
LL2
-EXCESS SLURRY
-TOP PLUS CAUGHT
-REVERSE CIRCULATION
OUTS OFF "CP CEMENT PLUG
-BOTTOM PLUG
FIGURE 3.15
TWO PLUG METHOD SCHEMATIC
-------
fill the annul us. The top plug is introduced into the
cementing string and, when it lands in the plug catcher,
causes a sharp rise in the surface pressure indicating
that it has closed off the plug catcher. This bottom
plug is latched into place to prevent the cement from
backing up into the string, but it permits reverse
circulation when required. The design permits pulling
the cement string up after cement placement to dress off
the top of the cement at the desired depth by reversing
circulating through the plug catcher. Excess cement is
thereby reversed up and out of the tubing. The cement
string is then pulled, leaving a cement plug that should
last indefinitely.
To minimize contamination, centralizers and
rotating scratchers can be put at the lower end of the
bottom drillpipe or tail pipe. The rotation of the
scratchers cleans the well bore - thus promoting better
bonding - and allows bypassed mud to mix uniformly with
the cement, eliminating mud channels in the unset
cement.
Advantages of the two-plug method are that (1) it
minimizes the likelihood of overdisplacing the cement;
(2) it forms a tight, hard cement structure: and (3) it
permits establishing the top of the plug. All in all,
the two-plug method of plugging is preferred to the
balance method.
3-98
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4. Dump Bailer Method
This method is available (Fig 3.16) for setting
plugs in shallow wells. The method utilizes a bailer
that is lowered into the well using a wireline truck.
Generally, a bridge plug or cement basket is previously
placed in the hole at the specified depth. The bailer
is opened by touching the bridge plug and is raised to
release the cement slurry at this location.
This method has certain advantages in that the tool
is run on wire line and the depth of the cement plug is
easily controlled. The cost of a dump bailer job is
usually low compared with one using conventional pumping
equipment.
Some disadvantages of the dump bailer method are
that (1) it is not readily adaptable to setting deep
plugs; (2) mud can contaminate the cement unless the
hole is circulated before dumping (this is also true of
the balanced method); and (3) there is a limit to the
quantity of slurry that can be placed per run, and an
initial set may be required before the next run can be
made.
3.5.4 Check-list for P & A
Table 3.6 presents a check-list that should be helpful in
witnessing a P & A. If an inspector is available to witness the field
procedures, he may visit the site when events 7 through 11 are being
completed.
3-99
-------
9n"Id 1N3W30 9NI0Vld JO 00H13W H31IVS dWOQ
9i c 3ans>u
-------
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
TABLE 3.6
CHECK-LIST FOR PLUGGING AND ABANDONMENT
Activity
Review drilling records and well construction
records
Review operations history
Review regional hydrogeologic data
Determine plugging intervals
Determine plug height and volume requirements for
each plug: (refer to Appendix E).
Develop preliminary plugging and abandonment plan
Remove tubing, packers, and salvageable casing,
as applicable
Inspect well casings and primary cement for
corrosion breaks and voids
Implement all necessary well repairs and clean
out procedures
Finalize abandonment plan, i.e., make any
necessary modifications based on results of
Events 7 and 8
Establish static equilibrium of plugging fluid,
if necessary
Install bottom plug
Allow cement adequate time to set, if necessary
Pressure test plug for basic integrity
Install intermediate plugs, if necessary
Repeat events 13 and 14 for each intermediate
plug
Install top plug, cut off casing 3' below grade,
install monument if desired.
-------
3.6 CLASS IV CLOSURE
Construction or operation of an injection well to dispose of
hazardous or radioactive waste into or above an underground formation
which contains drinking water will be prohibited after the
implementation date of the Region III UIC program. Region III has
identified the proper closure of all Class IV wells to be of the
highest priority (see Section 2.1.1). Of the 11 Class IV wells
currently identified in Pennsylvania, seven have been permanently
abandoned by methods approved by EPA or the Pennsylvania Department of
Environmental Resources (DER), and 3 wells are being used in remedial
clean-up actions while one well's status is unknown. There are
probably other abandoned Class IV wells that have not yet been
identified.
The proper closure of Pennsylvania's Class IV wells is essentially
a first year program that includes a site evaluation, reconnaissance
trips and actual plugging and abandonment.
Those wells previously closed under other regulatory authority may
be reevaluated and rated in terms of their susceptibility to further
contamination of ground water. If justified, it may be necessary to
reenter such wells in order to effectively plug them or initiate post
closure monitoring to further evaluate the contamination potential.
3.6.1 Location and Typology of Class IV Wells
Most of the identified Class IV wells in Pennsylvania differ
dramatically in construction from Class I or Class II wells. Some may
be more descriptively referred to as cesspools or sumps. In this case,
3-102
-------
the well is an uncased excavation varying in surface dimensions and
ranging in depth from 4' to 20'. Others are cased or partially cased
with large diameter pipe (up to 16") to depths in excess of 500'. A
partial listing of the Pennsylvania Class IV well inventory is given in
Table 3.7.
3.6.2 Plugging Considerations
Due to the many construction variables involved with Class IV
wells, closure procedures must be determined on a case by case basis.
In any case the same standards for protection of groundwater should be
maintained and plugging and abandonment of these wells should be
witnessed by an EPA inspector.
A. Consider the well's construction:
When abandoning a Class IV well an atttempt should be made
to restore the geologic conditions that existed before the
well was drilled and constructed. Because of this, more
than one method of plugging a well may be acceptable.
Ideally each well to be plugged must be examined as a
separate entity and careful consideration should be given to
the original design of the well along with the hydrogeologic
environment in which it is located.
B. Consider the objective of proper closure:
The plugging operation should eliminate vertical movement of
water within the annular space if it exists and within the
well bore. If artesian conditions exist the sealing
operation must confine the water to the aquifer in such a
3-103
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TABLE 3.7
CERTAIN CLASS IV WELLS IN PENNSYLVANIA
Operator Location
1. Butler Mine Tunnel Tittston, Pa.
2. Columbian Stove Co. Columbia, Pa.
3. O'Hara Sanitation
Company
Upper Merion,
Pa.
4. Amtrak
Paoli, PA
5. Square-D
(Rodale Plant)
Etmiaus, Pa.
Comments
Cyanide waste and oil sludge
were injected in the 535'
vertical mine shaft.
Temporarily abandoned by
sealing off mine entrance.
3' x 20' uncased pit. Depth
not known. DER was unable
to establish a Class IV
category.
30'x 30' x 50* uncased pit
underlying a service garage.
Reportedly tank trucks
unloaded various industrial
wastes thru floor drain. P
& A with sand, cement cover
and metal plate.
Oil bearing PCBs were
unloaded through floor
drains. No dimensions
given. Plugged with clay
and cement in 1979.
Three cased wells ranging in
depth from about 250' to
about 641 *. No. 1 is
currently being pumped for
contaminant withdrawal. No.
2 and No. 3 are currently
monitor wells.
-------
TABLE 3.7 (continued)
6.
Operator
Stanley Kessler
Dracket
Grummand Allied
Industries
Location
Upper Merion,
Pa.
E. Stroudsburg,
Pa.
Montgomery, Pa.
Comments
20' x 3' x unknown depth,
uncased. Trichloroethylene
1 aden siudge was removed
from well prior to
backfilling in 1981.
Two wells, uncased 8* x 15'
and 5' x 14'. P & A 1983.
5 year post closure
monitoring by consent
order.
No construction information
Repository for cyanide
bearing wastewater from
electroplating process prior
to closing with 12 tons peat
gravel and cement.
9. Rexroth Corp.
Bethlehem Pa.
Oil Disposal Pit
-------
way as to prevent loss of artesian pressure or circulation
between two distinct aquifers.
C. Remove obstructions from the well
To properly plug a well, all materials which may hinder the
sealing operation must be removed. If possible the casing
should be removed. If the casing cannot be removed, it
should be torn or perforated to allow the grout to
completely fill the annular space if one exists, as well as
the interior of the casing or bore hole.
D. Consider which plugging materials can be used:
Acceptable plugging materials include cement and certain
non-permeable clays. If a non-permeable clay is used, it is
important that the predominant grain size be very small
(diameter less than 1/256 mm.) with a very low amount of
particles in the silt and sand size grades. A quick and
practical way for testing, whether or not a clayey material
contains a significant amount of silt or sand-sized
particles, is to rub the material vigorously in the palm of
the hand. A gritty feeling is the indication of the
presence of larger sized particles.
Cement is an excellent plugging material for Class IV wells.
The cement is to be used without the addition of any
aggregate, such as sand and gravel, which when mixed with
cement forms the product termed concrete. The use of
concrete mix for well plugging is discouraged because, when
3-106
-------
the mix is placed in water, the courser sand and gravel
materials separate from the mix and settle to the bottom
forming a permeable zone in the plug.
E. Consider Plug Placement
Regardless of the type of material that is used to plug a
well, care must be taken to be certain that the material
completely fills the well bore. The easiest way to
accomplish this is to mix the material with water to the
consistency of a heavy slurry. The material should be
introduced into the well at the bottom, or at the interval
to be sealed (or filled) and placed progressively upward to
the top of well.
In preparing a plugging slurry it is recommended that the
mixture be brought to a consistency of about 15 pounds per
gallon. Table 3.8 can be used as a guide in determining the
amount of material required to fill most round boreholes of
nominal size. Taking a well similar to the Square-D Company
wells identified in Table 3.7 as an example, let us suppose
that a well of 6-inch diameter and 250 feet deep is to be
plugged. On the 6-inch diameter line of Table 3.8 we find
that the volume of each linear foot is 0.196 cubic foot and
that each linear foot has a capacity of 1.47 gallons. Thus,
for the 250 foot well, the volume is 49.0 cubic feet (.196 x
250) with a total capacity of 367.5 gallons (1.47 x 250).
If the decision was made to fill this hypothetical well with
3-107
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TABLE3;.ฃ Capacity of Hole
Diameter of Volume per Lin. Capacity per Sacks Cement Lin. Ft. Per
hole (inches Ft. (cu. ft.) Lin. Ft. (gals.) per Lin. Ft.* socks cement
2
0.022
0.16
0.02
50.25
2*5
.034
0.25
.03
32.15
3
.049
0.37
.04
22.52
3h
.067
0.50
.06
16.47
4
.087
0.65
.08
12.64
4*5
.117
0.88
.11
9.94
5
.136
1.02
.12
8.06
5%
.165
1.23
.15
6.67
6
.196
1.47
.18
5.60
6is
.230
1.72
.21
4.77
7
.267
2.00
.24
4.12
7h
.307
2.30
.28
3.59
8
.349
2.61
.32
3.15
%
.394
2.95
.36
2.79
9
.442
3.31
.40
2.49
9h
.492
3.68
.45
2.23
10
.545
4.08
.50
2.02
105s
.601
4.50
.55
1.83
11
.660
4.94
.60
1.67
ll^s
.721
5.39
.66
1.53
12
.785
5.87
.71
1.40
\2h
.852
6.37
.77
1.29
13
.922
6.90
.84
1.19
13%
.994
7.44
.90
1.11
14
1.069
8.00
.97
1.03
15
1.227
9.18
1.12
0.90
16
1.396
10.44
1.27
.79
17
1.576
11.80
1 .43
.70
18
1.766
13.21
1.61
.62
19
1.969
14.73
1.79
.56
20
2.182
15.95
1.98
.50
22
2.640
19.75
2.40
.42
24
3.142
23.50
2.86
. 35
26
3.687
27.58
3.36
.30
28
4.276
31.99
3.89
.26
30
4.909
36.72
4.46
.22
36
7.069
52.88
6.43
.16
* Cement calculations based on the volume of an average cement mixture being
1.1 cubic feet per sack of cement.
-------
cement, we find that each linear foot would require 0.18
sack of cement, or a total of 45 sacks of cement to
completely fill the well.
All sealing materials should be placed by the use of
grout pipe, tremie pipe, cement bucket or dump bailer, in
such a way as to avoid segregation or dilution of the
sealing materials.
If the well is extremely shallow and surface dimensions
are large, backfilling with clay using earth moving
equipment may be acceptable. This type of plugging and
abandonment would be similar to closure of an unlined pond.
A Class IV well similar to the O'Hara Sanitation Company's
(Table 3.7) well might be backfilled in this manner.
If a clay slurry is used in plugging, it is strongly
advised that at least the upper few feet of the well should
be filled with cement. This will prevent thinning of the
mud slurry by surface water and provide a solid upper
surface.
F. Cut casing off below grade if the well is located in an area
where cultivation or construction is probable: The upper
portion of the well casing, if one exists, should be cut off
at the level below plow or construction depth under certain
conditions. This could be done before plugging begins.
With the recommended cement plug in place, fill material can
then be replaced over the wel1.
3-109
-------
3.6.3 Checklist for Evaluating Abandoned Class IV Wells
Evaluation of previously plugged Class IV well facilities could
lead to reentry, restoration and replugging of the well and/or post
closure monitoring. The following criteria should be evaluated in
determining the need and extent of these remedial measures:
A. Population relying on the underground source of drinking
water.
B. local geology and hydrogeology
C. Distance between contamination source and water supply.
D. Depth to water table.
E. Water table gradient from contamination source.
F. Toxicity of injected fluids.
6. Estimate of the maximum inventory of injected wastes and
H Radial movement of the injected fluids.
I. Incidence of flooding in project area.
J. Adequacy of plugging methods to prevent the vertical flow of
wastewater.
K. Results of monitoring program if monitoring system has been
installed.
L. Incidence of run-on or run-off which may errode or otherwise
damage the final cover.
M. Confidence in accuracy of above criteria.
3-110
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3.7. ROUTINE OPERATIONAL INSPECTIONS
Routine site inspections by the Region III UIC Staff to verify or
witness routine facility operations will be conducted on a regular
basis or in response to a complaint or other indications that a
violation may exist. Routine operational inspections of permitted
injection facilities are to be conducted at a minimum, every year
according the Region III UIC Strategy. The following guidelines should
be adhered to when performing these general housekeeping inspections:
ฐ Determination of the potential violations and/or indication of
the conditions that might be a source of a violation.
Aid in evaluation and identification of any unusual conditions
or problems that are prevalent or that might become problems in
the future.
Record and document all relevant information concerning the
operation of the facilities for updating existing records and
inventory.
3.7.1. Central Considerations and Reporting Forms
In general, a routine inspection involves an observation and
evaluation of the site and a review of monitoring summaries and
equipment requirements. A procedural checklist for routine operational
inspections is shown below:
A. Make the following general observations of injection site,
associated facilities and monitoring wells:
This simply involves observing the injection system,
associated facilities and equipment for signs of excess wear,
3-111
-------
corrosion or inappropriate use. Monitoring stations,
recording devices, measuring tools, gauges and any other
instrumentation should be checked for accuracy. Through
observations the inspector should verify that the numbers
and sites of injection wells and pretreatment processes are
in line with permit requirement.
B. Review records to determine permit verifications and
compliance:
In particular the inspector should make certain that all
required information has been recorded, that it is
up-to-date and that it has been accurately recorded. In the
course of the records inspection phase, the facilities
operations should be compared with the permit to verify
compliance. If any injection activities differ from those
stated in the permit the inspector should note whether or
not the EPA was notified. Injection well reports concerning
surface flow rates, injection rates, injection pressures and
fluid volume measurements along with laboratory and sampling
records pertaining to the physical and chemical properties
of the injected fluids, should be reviewed by the inspector
in determining the operational history of the facility. The
efficacy of manifold monitoring, where used, can be tested
or demonstrated during these inspections. Figures 3.17 and
3.18 depict the general operational information that should
be recorded and maintained by an injection facility.
3-112
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Form Approval OMB No. 2000-0041 Approval expires 9-30-86
SEPA
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON. DC 20460
CLASS II
ANNUAL DISPOSAL/INJECTION WELL MONITORING REPORT
NAME AND ADDRESS .OF EXISTING PERMITTEE
NAME ANO ADDRESS OF SURFACE OWNER
LOCATE WELL ANO OUTLINE UNIT ON
SECTION PLAT 640 ACRES
W
STATE
COUNTY
PERMIT NUMBER
SURFACE LOCATION DESCRIPTION
% OF V4 OF
Vi SECTION
TOWNSHIP
RANGE
LOCATE WELL IN TWO DIRECTIONS FROM NEAREST UNES OF QUARTER SECTION AND DRILLING UNIT
Surfaca
Location ft from (N/S) Line of quarter section
mvi h ip /wi i inn m quarter section
WELL ACTIVITY
~ Brine Disposal
~ Enhanced Recovery
~ Hydrocarbon Storage
Lease Name
TYPE OF PERMIT
~ Individual
~ Area
Number of Wells
Well Number
Monitoring Location:
(if manifold oonitoring)
Nature of Inje ion Fluid
FLOW RAZE
INJECTION PRESSURE TOTAL VOLUME INJECTED (BBL/ Day)
MONTH YEAR
AVERAGE PSIG
MAXIMUM PSIG
BBL
MCF
AVERAGE
MAXIMUM
CERTIFICATION
/ certify under the penalty of law that / have personally examined and am familiar with the information submitted in
this document and all attachments and that, based on my inquiry of those individuals immediately responsible for
obtaining the information, I believe that the information is true, accurate, and complete. / am aware that there are
significant penalties for submitting false information, including the possibility of fine and imprisonment. (Ref. 40
CFR 144.32).
NAME AND OFFICIAL TITLE (Pleese type or printI
SIGNATURE
DATE SIGNED
EPAFom.7620-11 (2-84) FIG 3.17: TYPICAL INJECTION WELL OPERATING'RECORD (EPA, 1984)
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
4% _ ma WASHINGTON. DC 20460
**C PA INJECTION WELL MONITORING REPORT
Form Approved
OMB No. 2000-0042
Approval expires 9-30-86
YEAR
MONTH
MONTH
MONTH
Injection Pressure (PSI)
1. Minimum
2. Average
3. Maximum
Injection Rate (Gal/Min)
1. Minimum
2. Average
3. Maximum
Annular Pressure (PSI)
1. Minimum
2. Average
3. Maximum
Injection Volume (Gal)
1. Monthly Total
2. Yearly Cumulative
Temperature (Fฐ)
1. Minimum
2. Average
3. Maximum
PH
1. Minimum
2. Average
3. Maximum
Other
Name and Address of Permittee
Permit Number
Name and Official Title (Please type or print)
Signature
Date Signed
EPAFom,76208(2-84) ^ g ^ TYpICAL MONTHLY OPERATIONAL INFORMATION AND RECORD (EPA, 1984)
-------
Review the self-monitoring system and reporting procedures:
The EPA UIC Program requires that permittees maintain
records and report periodically on the amount and nature of
waste components in the effluent. Routine evaluations
should be conducted at all permitted facilities to assure
that compliance with permit requirements are being met. A
review of facility records should encompass the following
objectives:
ฐ Is all required information available?
ฐ Is the information current?
Is the information being maintained for the required
period of time?
Inspection priorities of a facility's self-monitoring
program include permit verifications, evaluation of
recordkeeping and reporting procedures and compliance with
permit requirements.
Evaluate the operation and maintenance of the facility:
After careful observation and review of a facility and its
performance records, the inspector can determine if any
areas of the facility require a more in-depth investigation.
The inspector should evaluate whether the permittee has
complied with the requirements for the permit or if the
permittee needs assistance in conforming to the rules and
regulations set forth in the permit.
3-115
-------
3.7.2 Checklist for Site Inspection
A. Observation of Injection Facility
1. Inspection observations verify information contained in
permit.
2. Equipment calibration and maintenance are adequate.
3. Backup facilities are adequate.
4. Pre-injection facilities are adequate.
5. Monitoring eqipment is adequate and functional.
6. Manifold monitoring efficacy checked.
B. Permit verification and Compliance Review
1. Name and mailing address of permittee are correct.
2. Facility is correctly described in permit.
3. Notification has been given to EPA/State of any
operational changes.
4. Accurate records of injection volumes and pressures are
maintained.
5. Number and location of wells are as described in the
permit.
6. Name and location of injection waters are correct.
7. All wells are permitted.
C. Self-Monitoring and Reporting Review
1. Monitoring records are adequate and include:
a. Flow, pH, density, etc. as required by permit
b. Monitoring charts
3-116
-------
D. Operation and Maintenance Evaluation
1. All required information is available and current; and
2. Information is maintained for required period.
3. Sampling and Analysis Data are adequate and include:
a. Dates, times, location of sampling,
b. Name(s) of individual(s) performing sampling,
c. Analytical methods and techniques,
d. Results of analysis,
e. Names of personnel performing analysis,
f. Instantaneous flow at grap sample stations.
4. Plant Records are adequate and include
a. 0 & M Manual, and
b. "As-built" engineering drawings.
3-117
-------
REFERENCES CHAPTER 3.0
API Recommended Onshore Production Operating Practices For protection
Recommendation. Consultants Preliminary Report for EPA Regions III and
II, September, 1983.
Donaldson E. C. etal. Subsurface Waste Injection in the United States -
Fifteen Case Histories. United States Department of the Interior
Bureau of Mines, information Circular 8636, 1974.
Florida Department of Environmental Regulation, Bureau of Drinking
Water and Special Programs, State of Florida, Underground Injection
Control Program. January 1982.
Hubbert, M. K. and Willis D. G. Mechanics of Hydraulic Fracturing.
Trans AIME, Vol. 210, 1957, 153-T5S:
Matthews, C. S., and Russell, D. G., Pressure Buildup and Flow Tests in
Wei Is. Soc. Petroleum Engineers, Doherty Series Mon. V.1, '1967.
McPhater, D. and MacTierman B., Well-Site Geologist's Handbook,
Pennwell Publishing Company, Tulsa, Oklahoma, 1983.
Ohio River Valley Water Sanitation Commission. Underground Injection
of Wastewaters in the Ohio Valley Region. ORANSCO, Cincinnati, Ohio.
WIT 2
Pirson, Sylvain J. Handbook of Well Log Analysis. Prentice-Hall Inc.,
Englewood Cliffs, N. J., 1963.
Schlumberger, Schlumberger Log Interpretation, Principles. Volume 1,
New York, Schlumberger Limited, 1972.
Smith, D. K. Cementing. (Monograph Vol. 4 4 of the Henry L. Doberty
Series) Society of Petroleum Engineers of AIME, Dallas, 1976.
Texas Department of Water Resources. Underground Injection Control
Technical Assistance Manual. Report 2/4, bl p.
U.S. Environmental Protection Agency. Technical Manual Injection Well
Abandonment. EPA Office of Drinking Water Contract 68-01-5971, 1980.
U.S. Environmental Protection Agency. Guidance Document on Mechanical
U.S. Environmental Protection Agency. Development of Procedures and
Costs for Proper Abandonment and Plugging of Injection Wells, EPA
Office of Drinking Water Contract 68-01-5971. April, 1980.
-------
MONITORING METHODS AND PROBLEMS
-------
4.1 EQUIPMENT AND INSTRUMENTATION
4.1.1 General Considerations
The principal means of surveillance of wastewater injection is
monitoring critical operating parameters at the wellhead. The
greatest risk of escape of injected fluids is normally through or
around the outside of the injection well itself, rather than from
leakage through semi-impermeable confining beds, fractures, or
unplugged wells. Section 4, therefore, highlights wellhead equipment
and instrumentation used to monitor the integrity at an operating
wel 1.
Pressure and flow measuring instrumentation are of primary
importance in a monitoring system. Miscellaneous parameters such as
pH, temperature, wastewater chemistry, etc. may be measured, as
required in certain Class I well operations.
To get a proper perspective about the location and function of
instrumentation, request the operator to provide a process flow
diagram. For illustration purposes, refer to Figure 4.1 which is a
piping and instrumentation diagram, P & ID, around a Class I wellhead.
Class II wellhead equipment is usually simpler as illustrated in Figure
4.2. Ask for specification sheets of the monitoring instruments. A
manufacturer's catalog will furnish detailed information on instrument
calibration procedures, sensitivity, materials of construction and
parts identification. As you inspect a well facility you shall see
pressure gauges located on the wellhead and/or wellhead piping. A flow
meter will generally be located on the injection pipeline, whereas all
recorders and totalizers can generally be found in a control room or
operation's shelter.
4-1
-------
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-------
4.1.2 Wellhead Configuration
A. Understand the functions of wellhead equipment:
The wellhead is the equipment used to maintain surface
control of the well. It is usually made of steel, cast or
forged, and machined to a close fit; and forms a seal to
prevent well fluids from blowing or leaking at the surface.
The wellhead is sometimes made of many heavy fittings
with certain parts designed to hold pressures up to 20,000
lbs. per sq. in. (psi). Other well heads may be just a
simple assembly to support the weight of the tubing in the
well, and may not be built to hold pressure as in Figure
4.2.
B. Be familiar with wellhead components:
The wellhead is formed of combinations of parts called
the casing head, tubing head, valves and pressure gages.
Casing head:
During the drilling of the well, as each string of
casing is run into the hole it is necessary to install heavy
fittings at the surface to which the casing is attached.
Each string of casing is supported by a casing head which
was installed at the top of the next larger string of casing
when it was run.
Each part of the casing head usually provides for the
use of slips or gripping devices to hold the weight of the
casing.
4-4
-------
The casing head is used during drilling and workover
operations as an anchor base for pressure-control
equipment.
Tubing head:
The tubing head is similar in design and sits on top
the uppermost casing head. Its most important purposes are
to:
1. Support the tubing string.
2. Seal off pressures between the casing and outside
of tubing at the surface.
3. Provide connections at the surface with which the
flowing liquid can be controlled.
In many Region III wells that have only one string of
casing, the casing head is not used and the tubing head is
supported on the top of the casing at or near ground level.
Tubing heads vary in construction depending upon pressure
1imits.
The tubing head must be easily taken apart and put
together to make well-servicing operations easier. Many
different types have been developed for use under high
pressures, with different designs and pressure ratings to
fit expected well conditions.
C. Pay attention to valving and piping above the wellhead.
Injection Wells which are expected to have corrosive
fluid (or high pressure) are usually equipped with special
4-5
-------
heavy valves above the casing head (or tubing head) before
such wells are completed. This group of valves controls the
flow of fluid into the well, and is called a Christmas tree
because of its shape and the large number of fittings that
sometimes branch out above the well head.
Pressure gauges are usually used as a part of the well
head and Christmas tree to measure the casing and tubing
pressures. The pressures are monitored for well control and
also to comply with UIC regulations.
4.1.3 Injection Pressure Measurement
A. Know the objectives of pressure measurements:
Injection pressure is monitored to provide a record of
reservoir performance and as evidence of compliance with
regulatory restrictions. Injection pressures are limited to
prevent hydraulic fracturing of the injection reservoir and
confining beds, or damage to well facilities. As with flow
data, injection pressure should be continuously recorded.
B. Interpret the pressure changes:
A continuous recording provides a valuable means of
determining if injection operations have been smooth in the
past. Changes in wellhead pressures can be the indication
of formation plugging, tubing or packer restriction,
increase in the reservoir pressure, or break through into
another formation.
4-6
-------
C. Do not overlook faulty readings:
Pressure indicators and recorders require periodic
maintenance or replacement. Lack of maintenance could
result in erroneous data. Make sure that the operator is
maintaining the pressure instrument in a good working
condition. The inspector may wish to take a test gauge with
him in order to check the accuracy of the operator's gauge.
D. Be aware of the major types of gauges and leading brands:
The Bourdon Tube pressure gauge is the gauge
predominantly used for measuring wellhead pressures. This
gauge covers a pressure range of 0 to 5000 psi or higher.
They are offered in various materials of construction. If
the fluid to be injected corrodes copper or bronze,
specialty materials like SS316 or monel would be desirable.
Some of the leading manufacturers of pressure gauges are:
Foxboro Company, Babcock & Wilcox Company, Earnest Gaze
Company, Weklser Instrument Corporation, etc.
E. Get familiar with common types of pressure recorders:
Recording pressure in the field can be conveniently
done using circular chart recorders. These devices produce
time based records on flat circular charts. The main
advantage of the recorder is that an entire hour, 12-hour
shift, day or other period of interest is displayed as a
complete cycle (Figure 4.3 and 4.4). The circular charts
can be directly driven by the signal from a primary sensing
element.
4-7
-------
Strip chart recorders are generally used in a control
room. Most commercially available strip chart recorders are
actuated electrically and transform a voltage or current
signal into displacement of the writing mechanism. This
form of out-put has the advantages of an easily read graphic
display while compiling a permanent historical record.
4.1.4 Injection Flow Measurement
A. Let operator know purpose of flow measurement:
The purpose of monitoring the injected volume is to
allow for estimates of the distance of radial dispersion, to
allow for interpretation of pressure data, and to provide a
permanent record. This record is needed as evidence of
compliance as an aid in interpretation of well behavior, in
well maintenance, and as a precaution in the event that a
chemical parameter should deviate from design.
B. Interpret flow rate changes:
Flow rate variations will be associated with corresponding
pressure changes.
C. Make sure that flow readings are accurate:
Like the pressure gauges and recorders, flow meters
require periodic maintenance. Correct flow rate readings
are necessary for the proper interpretation of other
parameters. A ratio of injection flow to pressure may serve
as an index of injectivity. To be meaningful, both the flow
rate and pressure readings have to be correct. Flow rates
4-8
-------
FIGURE 4.3
INJECTION
TEMPERATURE
ANNULUS
PRESSURE
rwd 9
CONTINOUS MONITORING
INJECTION TEMPERATURE/ANNULUS PRESSURE
TWENTY-FOUR HOUR RECORD
-------
FIGURE 4.4
CONTINUOUS MONITORING
INJECTION PRESSURE/RATE OF FLOW/
ANNULUS PRESSURE
SEVEN DAY RECORD
-------
can be roughly checked by comparing the instruments reading
against the time to fill a container of known volume or by
measuring the rate at which a supply tank is dropping.
If positive displacement pumps are used flow
measurements can be checked against the volumetric discharge
of the pump. This involves counting the pump strokes for a
specified period of time, say one minute, and multiplying
the number of strokes times the discharge volume of the pump
in gallons per stroke. Tables containing volumetric
discharge data for various models of duplex and triplex pump
using different liner sizes is given in Appendix C.
D. Determine if the flow is regulated by special equipment:
Where positive displacement pumps are not used, flow
regulation may be accomplished by the use of special
shut-off or check valves and by the use of flow control
chokes. Automatic shutoff valves are used at the well head
to close automatically in response to rpessure changes. The
automatic shut-off mechanism is composed of the valve body,
the acctuator (closing mechanism), and the pilot (sensing
assembly). The function of this mechanism is to protect
both the downhole equipment and the ground-water system.
When a pressure change occurs, indicating a leak, the
shut-off valve arrests the flow. Check valves can be
designed to close gradually to avoid destructive hydraulic
phenomena like water hairmer effects.
4-11
-------
E. Common types of flow meters and recorders:
A propeller or turbine meter and magnetic flow meter are
commonly used to measure flow through a pipe line. Other
types include venturi tube meters, ultrasonic meters and
rotameters. The flow recorders will be identical to those
used for pressure recording. Often flow and pressure will
be traced on a common recorder. In this case different
color ink is used to discriminate the recordings.
4.1.5 Miscellaneous Measurement:
A. Determine if measurements other than flow rate and pressure
are required:
If the injected fluid is corrosive, pH may be
(continuously) measured. Corrosion measurements may be
made, if necessary.
If fluid temperature is not ambient, temperature
measurement may be important.
In some wastewater streams suspended solid measurement is
important in order to prevent plugging problems.
0 Chemical analysis of injection water may be frequently or
periodically conducted on a grab sample to study
compatibility problems and identify an element that may be
troublesome.
B. Check the permit requirements to establish whether special
measurements are specified.
4-12
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4.1.6 Annulus and Manifold Monitoring Systems
A. Be aware of the importance of monitoring a subsurface well
leak:
A proper annulus monitoring system is essential to
detect the sudden loss of mechanical integrity before
environmental damage is done. This is particularly
important in Class 1 injection well operations.
Pressure in the casing-tubing annulus of Class I wells
should be monitored to detect any changes that might
indicate leakage through the injection tubing or the
tubing-casing packer. When a packer is used, three
different operational procedures are possible. If fluid in
the casing-tubing annulus is not pressurized, then the
pressure would be expected to be zero. However, it often
will not be, because of effects such as "balooning" of the
injection tubing and thermal expansion or contraction of the
fluid in the annulus. If fluid in the annulus is
pressurized, it may be kept either below or above the
pressure in the injection tubing. In any of the three
cases, leakage is indicated by an abnormal change in the
annulus fluid pressure.
B. Examine the options in monitoring the annulus;
Alternatively it is possible to design a well without
a packer and monitor the annulus using an electrode
monitoring system. In some cases, such as injection of
4-13
-------
highly acidic pickling liquor, other methods can be
implemented. For example non corrosive fluid may be
injected on the annul us side (Donaldson, 1978) at a pressure
greater than the injection pressure. Another variation
incudes use of hydrocarbon fluid such as Kerosene (Barlow
1972) that floats on water. In this application an
interface is established between a hydrocarbon fluid in the
annulus and an aqueous injection fluid.
Annul us monitoring systems are discussed in greater
detail in Section 3.4 on Mechanical Integrity inspections.
C. Consider simplified manifold monitoring for a cluster of
wells:
Monitoring requirements are not as stringent for Class II
wells. Annulus monitoring is not specifically required.
Injections intended for the secondary recovery of oil
usually involve the operation of a well field. Where well
density is high, manifold monitoring may be practiced. In
this method flow and pressure measuring instruments are
installed at a limited number of manifold locations where
each manifold feeds a number of wells. Here injectivity of
each cluster of wells is monitored continuously. Manifold
monitoring is discussed with respect to mechanical integrity
testing in Section 3.4.
4-14
-------
The facility design would take into account the number
of wells connected to a single manifold. The manifold
design essentially would mean certain savings in piping and
instrumentation. The system can be easy to attend compared
to having instrumentation on all individual wells.
A drawback of the system is that a break-down of total
flow to individual wells cannot be accurately determined.
In other words, the monitoring concept applies to a group of
wells receiving a flow rate recorded at the manifold.
Similarly pressure of the manifold would be resultant of the
group of wells.
4-15
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42 TROUBLE shooting well problems
An injection well operator will be directly involved in solving
inherent operating and maintenance problems. An inspector should
understand the well problems and over-all approach of an operator in
correcting them.
The well problem has first to be identified. This requires the
application of diagonistic procedures to adquately delineate the
problem. Frequently hindrance to successful diagnosis is due to the
lack of available information concerning the condition of a well. This
limitation has to be recognized by both the operator and the UIC
inspector.
The well problems and trouble shooting senarios addressed in this
Section provide a brief glimpse of the types of well problems which may
be encountered. A complete treatment of the topic is beyond the scope
of this Guide. Several commonly occurring problems have been reviewed
followed by case examples.
4.2.1. Types of Problems:
A. Recognize that an operator may have a non-treatable
problem:
Non-treatable problems are analagous to an oil and gas
operator drilling a dry hole. If the well symptom is
determined to be non-treatable, the injection well will
eventually be abandoned. Some examples of non-treatable
problems are:
ฐ local formation is indeed unsuitable to accept injection
fluids, i.e., transmissivity (Kh) is too low to continue
injection.
4-16
-------
because of several injectors in the given area or other
natural reasons the reservoir pressure is too high
0 confining strata protecting underground water is not
really confining.
well repairs are no longer cost effective.
Considerable time, effort and costs on the part of an
operator are required to conclude that the well problem is
non-treatable.
Since many of the Class I injection projects in Pennsylvania
have been abandoned, it appears that high rate disposal of
industrial wastes may be infeasible. Table 4.1 lists the
abandoned Class I wells and reasons why they are no longer
in operation.
B. If the well problem is treatable the operator will
categorize the type of the problem and evaluate diagnostic
and repair procedures.
Efforts for gathering information are often justified
because of the value of this information in the diagonosis
and success of the project. An operator will be interested
in making his "best guess" as to the nature of the problem.
While it is doubtful that any two people approach the
subject in exactly the same manner, there are standard
industry practices that are commonly followed. Broadly
speaking, an operator has to deal with (i) problems
concerning (tubular) equipment, and/or (ii) formation
4-17
-------
TABLE 4.1
CLASS I WELL PROBLEMS RELATED TO ABANDONMENT IN PENNSYLVANIA
Identifica-
tion Number Operator
3ones~& Laugh! in Steel"
Company
P-2 Hammermill Paper Co.
P-3 Hammermill Paper Co.
P-8 Hammermill Paper Co.
P-4 Gulf Research and
Development Company
P-5 Bethlehem Steel Co.
P-6 Koppers Company
P-9 Bethlehem Steel Co.
Operating
History
Oper at i on al" '4/65
to 6/72. Accu-
mulated vol. 33.1
million gals, of
spent pickle liquors
Operated 1963
to 4/68. Accu-
mulated vol.
446.4 million
gals of spent
sulphite liquors
Operational
4/65 to 10/68.
Accumulated vol.
297.9 mil 1 ion
gals, of spent
sulphite liquors
Operated 5/68 to
6/70. Accum-
lated vol. 354.0
million gals, of
spent sulphite
liquors.
Operated 1967-72,
Accumulated vol.
15,500 gallons
drilling fluids.
Was to be used
for mine drainage;
never operational
Never used for
injection
Never used for
injection
Reason for
Abandonment
Frequent tubing
failures and ex-
cessive injection
pressure needed.
Casing and tubing
lifted out of
hole 4/14/68.
(Companion well
to P-2)
(Companion well
to P-2)
Unknown
Tests proved
unsatisfactory
Fell short
of needs
Found wanting
in physical
requirements.
-------
damages. Both equipment failures and formation damage are
approached by first preparing the "prognosis" a written
procedure describing the actions to be taken during the
workover.
Equipment, such as wellhead, tubing, casing and packer may
tend to fail inherently because of wear or corrosion. A
common symptom of equipment failure is the detection of a
leak. Common leak detection techniques are covered in
Section 3.4 on mechanical integrity.
Formation problems may arise due to several different
reasons. The problems can be resolved through specific
tests and investigations. Elements of formation damage can
be identified as follows:
inorganic scale and precipitates
ฐ organic contamination/deposits
0 damage from stimulation materials
# damage from unwanted fluids like floating oils, solvents,
emulsions
damage from workover fluids/polymers
clay swelling due to fresh water
ฐ sand production
# perforation or completion damages
Once the problem is identified, remedies include both
treatment and preventive techniques.
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4.2.2. Common Examples of Trouble Shooting:
The application of trouble shooting aspects analysed in the
foregoing section can be demonstrated by describing illustrative
examples.
Example 1: Tubing Leak
An operator injecting wastewater in a Class I well in Deer
Park, Texas reported communication between the tubing and annul us. An
engineering company performed a mechanical integrity test which
indicated a leak in the injection tubing. The problem was solved as
described by the following workover summary.
The leaking annul us followed a similar failure of this well two
months before. THe previous leak was traced to the injection tubing at
a depth of 3025' which was subsequently repaired with a wireline set
tubing patch (Workover No. 3). The current workover, unlike Workover
No. 3, involved pulling the injection string. A service rig was moved
on location and set up on September 13, 1983. The following
day the injection tubing was removed from the well.
Selected joints of tubing were placed on the pipe rack and
visually inspected. The remainder was stood back in the derrick to
expedite reinstallation. All of the visually inspected tubing appeared
to be in good condition.
The two joints containing the Pengo tubing patch from Workover
No. 3 were set aside. A small 1/8" hole was noted in the body of one
of the joints. This hole was not detected in the caliper log conducted
during Workover No. 3 on July 12, 1983 (the hole was through to be at a
threaded connection).
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The presence of a hole in the body of a joint indicated that a
downhole corrosion problem existed. An Otis Caliper survey was ran to
a depth of 3600'. Results of in-line corrosion coupon testing had
previously indicated a "moderate" corrosion rate of 10 mils per year
(inpy). Perferrential corrosion to have created a hole through the
entire wall of the injection tubing requires a substantially higher
corrosion rate.
Afer pulling all of the tubing out of the well and redressing
the seal assembly, the tubing was run back into the well while
hydrotesting each 60' stand internally to 4000 psi.
A total of 6 joints were replaced with new 3 1/2", 9.3#, J-55
tubing. Counting from the top of the well the following joints were
replaced:
Joint No. Description of Failure/Defect
95 1/8" hole in body - patched during previous workover
96 patched during previous workover
124 1/8" hole in body
129 corroded threads
130 hydrostatic test failure at 3000 psi
183 hydrostatic test failure at 2500 psi
Mechanical integrity was restored to the well after the
four-day workover. The annul us was pressured to 1010 psi on September
16, 1983. There was no measurable loss in 30 minutes on the 2000 psi
field gauge.
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The well was then turned over to operations. A recommendation
was made to inject water compatible with carbon steel tubing or
substitute the existing tubing with corrosion resistant fiberglass
tubing
Example 2: Casing Leak
This example describes the detection and repair of a casing
leak of a Class I injection well in South Louisiana. Continuous
monitoring of the annul us and injection pressures had previously
indicated a leak of either the Dacker, tubing or casing.
A series of nine pressure tests were run on the 7" protection
casing to determine the location of leaks in the casing. This was
accomplished by setting a test packer at different depths and
pressuring up on the casing. The leak was determined to be in the
interval between 4071' and 4081'.
The following day 12 barrels of cement were spotted and
squeezed. The cement was allowed to set, under pressure, overnight,
and was then drilled out and the hole was circulated clean. After
pressure testing the casing, another 4 1/2 barrels of cement were
spotted and squeezed, and allowed to set up.
Four days later the cement was drilled out and the hole was
circulated clean; however, subsequent pressure tests still indicated a
small leak in the casing. It was decided that the best approach to
that problem would be to set the Dacker about 20 feet above the leak.
Verbal concurrence was received from the Louisiana UIC office, with the
understanding that a letter confirming the conversation would be sent
to the UIC office as soon as practicable.
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Thereafter, the cast iron bridge plug at 4196 feet was fished
out and the well was washed and circulated clean.
The Otis RB-1 packer was then redressed, run back in the hole
on 100 joints of 4 1/2" tubing, set at 4035 feet (bottom of packer) and
pressure tested satisfactorily at 515 psi for 4 1/2 hours.
The 4 1/2" x 7" annulus was filled with brine containing
Tretolite corrosion inhibitor and sodium sulfite (oxygen scavenger).
After pressure testing the tubing, the test plug and collar
stop were retrieved, the wellhead was installed and the annulus
pressurized, and the workover rig was released.
Example 3: Seal leak, acidization
This workover was performed to repair an annular leak, restore
injectivity and demonstrate mechanical integrity of a well in South
Texas.
After pulling the 5 1/2" injection tubing it appeared that the
Otis Seal Assembly (which was inserted into the packer) had been
leaking. Bad threads were also found on 6 joints of the tubing by
surface visual inspection.
The injection packer was subsequently retrieved and an
open-ended mule shoe was run to reverse circulate shale and sand from
4347' to 4540'. After cleaning the wellbore, previous difficulty in
seating a test packer was corrected by scraDing the 7" protection
casing.
A radioactive tracer survey established the point of exit from
the casing to be 4460' - 4464'. This survey was conducted to fulfill
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part of the mechanical integrity test requirements set forth by the
Texas Department of Water Resources. The log showed all of the fluid
was moving into the disposal interval and there were no indications of
vertical migration.
The well was acidized next by washing the perforations with
1260 gallons of 28% HC1 and 840 gallons of 15% HC1. This was followed
by 1000 gallons of 15% HC1, 7500 gallons of 22% HC1 plus 6% HF acid,
and 1000 gallons of 15% HCL. The acid was displaced with 32,000
gallons of 9 PPG low-calcium brine. The initial flush rate of 840 gpm
9 1200 psi was reduced to 420 gpm @ 690 psi after 10,000 gallons had
been pumped.
The well was reassembled using a new Brown Oil Tool Type "D"
Liner Hanger Packer. External hydrostatic testing of the tubing
connections was performed while running it into the well. Prior to
setting the new packer, the annul us was filled with 9 PPG brine
inhibited with NL Baroid Coat B-1400. Wellhead modifications were
required to achieve annular pressure integrity.
Example 4: Well Cleanout and Reperforation
This example decribes the methods use to restore injectivity to
a Class I disposal well in Louisiana.
After rigging up the service rig, the well was killed with 100
BBL of brine water. The tree was removed, followed by installation of
the blowout preventer.
The 4 1/2" injection tubing was cleaned and washed form 2375'
to the surface with a 3 7/8" bit, scraper, and hydrojet. The injection
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tubing and 4 1/2" x 7" TIW "LH" packer were pulled out of the well.
The 7" protection casing was cleaned down to 3525' (PBTD) using a
stripper and power swivel. The perforations at 2760'-2766' were
selectively washed, and surged to recover solids from the formation.
This was repeated until the formation appeared to be clean.
To restore the injectivity of the receiving zone, the well was
acidized with a mixture of 15% HC1, and 12% HCl/3% HF, followed by an
injection test. When the injection test proved unsatisfactory, the
well was surged and washed again. This sequence of surging, washing,
acidizing and injection testing was repeated several times without
success. Therefore, it was recommended to perforate the well at the
2400-foot sand above the existing injection interval. This procedure
was approved by the Louisiana Department of Natural Resources.
A block squeeze was made between 2469'-2470' with 100 sacks of
Class "H" cement to prevent upward migration of fluid. The squeeze was
tested to 1800 Dsi. A cement bond log was run from 2620' to the bottom
of the surface casing. A casing caliper log was also run from 2620' to
the surface. The casing was perforated between 2605'-2635' with four
(4) shots per foot. The well was washed, cleaned and an injection test
was conducted satisfactorily.
The 7" x 4 1/2" TIW "LH" packer was set at 2664' after 4 1/2"
injection tubing was run in the hole while hydrostatically testing each
joint to 3000 psi for three (3) minutes. The annulus was filled with
brine and tested for two (2) hours at 1010 psi. A Radioactive Tracer
Log was run to determine the direction of flow. The bottomhole
pressure was also determined. The equipment was rigged down.
The well was returned to service.
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REFERENCES CHAPTER 4
Barlow, A. C., 1972. Waste Disposal Well Design, in Underground Waste
Management Evironmental Imp!ications. Americal Association of
Petroleum Geo!ogists, MemoTr 18, Tulsa, Ok1ahoma.
Donaldson, E.C., 1978. Subsurface Disposal of Oilfield Brines and
Petro-chemical Wastes, Volume I. U.S. DOE, Environmental' Control
Symposium.
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GENERAL TECHNIQUES FOR EFFICIENT INSPECTIONS
-------
5.0 GENERAL TECHNIQUES FOR EFFICIENT INSPECTIONS
A primary goal of the inspector is to assemble information that
can be used for determining compliance with permit conditions,
applicable regulations and other requirements of the EPA Region III UIC
program. This information may ultimately result in enforcement case
development and support. In performing these duties, inspectors should
observe standard procedures and requirements for conducting legal and
effective investigations and in meeting accepted safety practices and
quality assurance responsibilities.
5.1 LEGAL RESPONSIBILITIES FOR EPA REGION III UIC PROGRAM
The Environmental Protection Agency is given authority under the
Safe Drinking Water Act to establish a program to regulate underground
injection, to define control technologies, to obtain information
through compliance inspections and to take civil and/or criminal
enforcement actions when violations of the Act are discovered.
Inspectors should be familiar with the terms and conditions set forth
by this Act and should conduct all investigative operations with its
legal framework in mind. This includes the following activities:
- Presentation of proper credentials
- Presentation of required notices and receipts (Notice of
Inspection Form Figure 5.1)
- Proper handling of necessary warrants when facility entry is
denied
- Ethical handling of confidential information
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U.S. ENVIRONMENTAL PROTECTION AGENCY
Notice of Inspection
Address(EPA Regional Office)
Date
Hour
Firm Name
Firm Address
Inspector Name & Title
Inspector Signature
Notice of Inspection is hereby given according to Section 1445(b)
if Safe Drinking Water Act (42 Y.S.C. ง300 f et seq.).
Reason for Inspection
For the purpose of inspecting records, files, paper, processes, controls
and facilities, and obtaining samples to determine whether the person subject
to an applicable underground injection control program has acted or is acting
in compliance with the Safe Drinking Act and and applicable permit or rule.
Section 1445(b) of the SDWA (42 U.S.C. ง 300 j-4 (b)) is quoted on the
reverse of this form.
FIGURE 5.1: PRESENTING NOTICE OF INSPECTION
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5.2 INVESTIGATIVE TECHNIQUES AND PROCEDURES
This section describes the step by step procedures that should be
followed in making a thorough and efficient inspection. Inspectors
should be familiar with these general investigative procedures to
ensure accurate and concise inspections and to avoid any legal
ramifications that could be brought about on procedural grounds. An
outline of procedural responsibilities in the inspection process is
shown in Table 5.1
5.2.1 Pre-Inspection Planning
Pre-inspection preparation is essential to the effective planning
and overall success of an inspection. Pre-planning an investigation
will ensure that the inspection is properly focused and conducted
efficiently.
The first step is to establish the purpose and scope of the
inspection. This should give an indication of the extensiveness and
degree of involvement required for the inspection.
Next inspectors should completely familiarize themselves with all
facility operations to be inspected and collect and review all
background information that is deemed necessary to conduct an efficient
and thorough investigation. The types of information available to the
inspector for gaining important insight on facility operations are
shown below:
ฐ General Facility Information
- Maps showing facility location, well locations, and
geographic features,
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TABLE 5.1
Inspector Responsibilities in the Inspection Process
1. Pre-Inspection Preparation:
# Establish purpose and scope of inspection.
Review background information and Agency records.
0 Develop plan for inspection.
# Prepare documents and equipment.
# Coordinate schedule with laboratory if samples are to be
collected.
2. Entry:
Present official credentials.
# Manage denial of entry if necessary.
3. Opening Conference:
Discuss inspection objectives and scope.
Establish working relationship with facility officials.
4. Facility Inspection:
Review facility records.
Inspect monitoring equipment and operations.
# Collect samples.
# Prepare documentation of inspection activities.
5. Closing Conference:
Collect missing or additional information.
# Clarify questions with facility officials.
D Prepare necessary receipts.
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- Names, titles, and phone numbers of responsible facility
officials,
- Nature of pretreatment and injection,
- Production levels, past, present and future,
- Hydrological data,
- Geology/hydrogeology of the area, and
- Changes in facility conditions since previous
inspection/permit application.
0 Requirements, Regulations, and Limitations:
- Copies of existing permits, regulations, and requirements-
Federal, State, and localand restrictions placed on
discharges, compliance schedules, monitoring and reporting
requirements, available monitoring equipment and analytical
methods used by facility,
- Special exemptions and waivers, if any,
- Injection stream water quality standards, and
- Previous facility applications for water, air, and solid
waste permits. These files may contain useful data not shown
elsewhere.
ฐ Injection Well and Pre-Treatment Systems
- Description and design data for injection well system and
process operation,
- Sources and characterization of injected fluids,
- Type and amount of fluids injected,
- Spill contingency plans,
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- Available by-passes or diversions and spill containment
facilities, and
-Pollution control, treatment methods, and monitoring
systems.
# Facility Compliance and Enforcement History
- Federal and State compliance files,
- Correspondence among facility, local, State and Federal
agencies,
- Complaints and reports, follow-up studies, findings, remedial
action,
- Previous inspection reports, records, correspondence on past
incidents of violations, exceedences, status of requested
regulatory corrective action, if any, and compliance by
facility,
- Status of current and pending litigation against facility,
- Self-monitoring data and reports,
- Previous EPA, State, and consultant studies and reports,
- Previous deficiency notices issued to facility, and
- Laboratory capabilities.
The above information can be obtained from files of Federal, State
and local agencies in addition to technical libraries and other data
sources like those listed below:
# Laws and Regulations -The Safe Drinking Water Act and related
regulations establish procedures, controls, and other
requirements applicble to a facility. In addition, State laws
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and regulations, and sometimes even local ordinances, are
applicable to the same facility.
# Permits and Permit Applications - Permits provide information on
the limitations, requirements, and restrictions applicable to
underground injection/ compliance schedules; and monitoring,
analytical, and reporting requirements. Applications provide
technical information on facility size, layout, and location of
pollutant sources; treatment and control practices; contingency
plans and emergency procedures; and pollutant characterization-
types, amounts, and points/locations of wells.
ฐ Regional and State Files and Contacts - Files or contacts often
can provide facility self-monitoring data, inspection reports,
and permits and permit applications applicable to individual
facilities. They can provide compliance, enforcement, and
litigation history; special exemptions and waivers applied for
and granted or denied; citizen complaints and action taken;
process and operational problems/solutions; pollution problems/
solutions; laboratory capabilities or inabilities; and other
proposed or historical remedial actions. Consultant reports can
provide design, construction and operation data arid
recommendations for remedial measures and safe operating
parameters.
Technical Reports, Documents, and References - These information
sources provide generic information on enhanced recovery
operations, as well as pertinent specific data on available
pretreatment techniques.
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Other Statutory Requirements - Facility files maintained
pursuant to other requirements.
Once the purpose of the inspection has been established and all
necessary background information has been reviewed, a plan for
inspection should be developed. This should include a comprehensive
assessment of the types of tasks to be performed and the resources
needed to carry out these tasks. Procedural steps and scheduling
should also be addressed in the inspection plan in order to manage an
efficient investigation. The following items should generally be
included in an inspection plan:
Objectives:
- What is the purpose of the inspection?
- What is to be accomplished?
# Tasks:
- What tasks are to be completed?
- What information must be collected?
# Procedures:
- What procedures are to be used?
- Will the inspection require special procedures?
# Resources:
- What personnel will be required?
- What equipment or instruments will be required?
What safety precautions should be taken?
# Schedule:
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- What will be the time requirements for inspection activities?
- What will be the milestones?
The final step in pre-inspection preparation concerns notification
of the proper personnel and agencies that are to be involved in the
inspection process. A notice of inspection usually requests
information regarding specific facility safety regulations and may
include the date of inspection and a schedule of procedures for
coordinating inspection activities with the facility.
Situations involving suspected illegal discharges or emissions
warrant an unannounced inspection for reasons that some crucial
evidence may be altered or destroyed.
5.2.2 Facility Entrance
Consensual entry will be the norm for most inspections and the
following procedures should be applied when entering a facility. The
inspector should arrive during normal working hours and irimediatel,y
locate the facility owner or appropriate agent. The inspector should
early identify himself as an EPA UIC inspector, present the proper
credentials and a notice of inspection (Figure 5.1). Credentials must
be presented before performing any inspection duties.
Inspectors should not sign any "waiver" or "release" that relieves
the facility of responsibility for injury or restricts the use of
information obtained during the course of the inspection. This
approach does not, however, apply to contractors. Denial of entry will
be discussed in Section 5.4.
5.2.3 Opening Conference
The initial meeting with the Permittee should detail the scope
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of the inspection and the schedule to be followed by the inspector.
The authority under which this investigation is being conducted should
be reviewed and the names of all personnel involved with this
inspection should be provided. This opening conference should promote
cooperation and a friendly working atmosphere which will ultimately
contribute to the success of the inspection.
Considerations:
Inspection Objectives: An outline of the inspection objectives
will inform facility officials of the purpose and scope of the
inspection and may help avoid misunderstandings.
ฐ Order of Inspection: A discussion of the order in which
operations will be inspected will help eliminate wasted time by
allowing officials time to make records available and start up
intermittent operations.
ฐ Meeting Schedules: A schedule of meetings with key personnel
will allow them to allocate a clear time to spend with the
inspector.
List of Records: A list of records to be inspected will allow
officials to gather and make them available for the inspector.
ฐ Accompaniment: It is important that a facility official
accompany the inspector during the inspection not only to
describe the site and its principal operating characteristics,
but also for safety and liability considerations.
0 Permit Verification: The inspector should collect the following
information from facility officials for use in verifying the
permit:
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- Correct name and address of facility,
- Correct name and source of injection waters,
- Injection rates, and pressures and,
- Number and location of injection wells.
0 Safety Requirements: The inspector should determine what OSHA
and facility safety regulations will be involved in the
inspection, and should be prepared to meet these requirements.
(See Chapter 6.0).
ฐ Closing Conference: A post-inspection meeting should be
scheduled with appropriate officials to provide a final
opportunity to gather information, answer questions, and
complete administrative duties.
# New Requirements: The inspector should discuss any new rules
and regulations that might affect the facility and answer any
questions pertaining to them. If the inspector is aware of
proposed rules that might affect the facility, he or she may
wish to encourage facility officials to obtain a copy.
ฐ Split Samples: Facility officials should be informed during the
opening conference of their right to receive a split of any
physical sample collected for laboratory analysis. Officials
should indicate at this point the desire to receive split
samples so that arrangements can be made to secure the samples.
9 Photographs: Photographs can be used to prepare a more thorough
and accurate inspection report, as evidence in enforcement
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proceedings, and to better explain conditions found in the
field. The facility, however, may object to the use of cameras
on their property. If a mutually acceptable solution cannot be
reached and photographs are considered essential to the
inspection, Agency supervisory and legal staff should be
contacted for advice.
Facility personnel may also request that any photographs taken
during the visitation be considered confidential. The Agency is
obliged to comply with this request pending further legal
determination. Self-developing film, although of lower quality,
is useful in certain situations. A facility may refuse
permission to take photographs unless they can see the finished
print. Duplicate photographs (one for the inspector and the
other for the Company) should satisfy this need.
5.2.4 Facility Inspection and Documentation
The inspector is responsible for providing documentation of any
suspected permit violations or other discrepancies uncovered during an
inspection. Detailed records of inspection procedures, field
observations and samples collected should be chronicled for later use
as evidence in enforcement proceedings, for written reports or for
examination by compliance personnel. The following types of
information should be recorded during an inspection:
* Observations: All conditions, practices, and other observations
that will be useful in preparing the inspection report or that
will contribute to valid evidence should be recorded.
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Procedures: Inspectors should list all procedures followed
involving entry, sampling, records inspection, and document
preparation. Such information will help avoid damage to case
proceedings or procedural grounds.
ฐ Documents: All documents taken or prepared by the inspector
should be noted and related to specific inspection activities.
Samples: Sampling is one of the most frequently used and widely
accepted methods of obtaining evidence available to the
inspector. A documented connection must be shown between
samples collected and analytical results reported using a system
that records any alterations or loss of samples from the time
they were taken to the time they were analyzed.
ฐ Statements: Formal statements obtained from facility personnel
can be useful for documenting an alleged violation. The person
making the statement should have personal, firsthand knowledge
of the facts pertaining to the situation. The following
procedures and considerations should be taken into account when
documenting a formal statement:
- Determine the need for a statement. Will it provide useful
information? Is the person making the statement qualified
to do so by personal knowledge?
- Ascertain all the facts and record those which are relevant
and which the person can verify in court. Make sure all
information is factual and firsthand. Avoid taking
statements that cannot be personally verified.
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In preparing a statement:
Use a simple narrative style; avoid stilted language.
- Narrate the facts in the words of the person making the
statement,
- Use the first-person singular ("I am manager of
- Present the facts in chronological order (unless the
situation calls for other arrangement,
- Postively identify the person (name, address, position),
- Show why the person is qualified to make the statement,
- Present the pertinent facts,
- Have the person read the statement and make any necessary
corrections before signing. If necessary, read the
statement to the person in the presence of a witness,
- All mistakes that are correctd must be initialed by the
person making the statement,
- Ask the person making the statement to write a brief
concluding paragraph indicating that he or she read and
understood the statement. (This safeguard will counter a
later claim that the person did not know what he or she was
signing.)
- Have the person making the statement sign it, and provide a
carbon copy for record purposes
- If he or she refuses to sign the statement, elicit an
acknowledgement that it is true and correct. Ask for a
statement in his or her own hand ("I have read this
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statement and it is true but I am not signing it because
Failing that, declare at the bottom of the statement
that the facts were recorded as revealed and that the person
read the statement and avowed it to be true. Attempt to
have any witness to the statement sign the statement
including witness' name and address, and
- Provide a copy of the statement to the signer if requested.
0 Photographs: The use of photographs provide an objective view
of facility conditions during inspection proceedings. The
permittees approval should be obtained before photographing any
facility operations, however photographs may always be taken
from areas of public access. All photographs taken during an
inspection should be recovered and identified at the time they
are made. The following details should be recorded when using
photographs during an inspection:
- Name and signature of the photographer and witness,
- Description of film used (i.e., its expiration date, ASA
number, origin, etc.),
- Focal length of the lens being used,
- F-stop and shutter speed at which the camera is set,
- Lighting conditions encountered,
- Time of day, weather conditions,
- Date,
- Location, and
- A brief description of the subject being photographed.
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Drawings and Maps: Graphic records can be useful in identifying
specific facility locations in addition to overall size and
magnitude of objects. Maps drawings and charts are valuable
tools in producing an accurate, schematic representation of the
facility under inspection. Oilfield maps are available showing
the locations of production and injection wells.
ฐ Record and File Copies: This information can provide important
insight into a facility's conditions and operations. Records
and files can be maintained in a number of ways including
written or printed materials, computer or electronic records or
as visual systems. These general considerations should be
applied when copies of records are needed for an inspection
report:
- Originals must be returned to the proper personnel or to their
correct location,
- Related records should be grouped together,
- Confidential business records should be handled according to
the special confidential provisions discussed below,
- All copies of records are to be delivered to the case
proceedings file after completion of the inspection,
- All records are to be kept under lock when not in actual use
by the inspector, and
- The physical location of the record (i.e., address of the
facility, building number, room number).
# Unusual Conditions and Problems: Unusual conditions and
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problems should be noted and described in detail.
# General Information: Names and titles of facility personnel and
the activities they perform should be listed along with
statements they may have made and other general information.
Information about a facility's recordkeeping procedures may be
useful in later inspections.
5.2.5 Closing Conference
Following the inspection process, a review of the results may be
appropriate for discussion with the facilities management team or
operating personnel. Although not required, this discussion could
cover all specific findings of the investigation and where necessary,
the findings should be compared with the facilities UIC permit
requirements.
The inspector must refrain from discussing any legal developments
or enforcement consequences with the permittee and should not recommend
any service company or consultant for alleviating existing or potential
well problems.
5.3 MAINTENANCE OF SAMPLES
5.3.1 Sampling Logistics
A. Determine the Number of Samples to be Taken: The number of
samples naturally depends on the type of site inspected and
information desired. When gathering evidence for possible
legal use, duplicate samples are usually collected. At
least two identical samples are desirable: one sample is
given to the operator; the second sample is submitted to the
EPA laboratory for analysis. Subdividing a Class I
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hazardous waste sample at the site is not recommended. A
laboratory environment is desirable to avoid contamination
and to insure personnel safety. The sample, representative
of the main body of waste, must be adequate in size for all
needs incuding laboratory analyses or splitting with other
organizations. Appendix H presents data on recommended
containers, preservatives and holding times for various
analytical parameters. All sample containers should be
filled to overflowing before capping to reduce the loss of
any volatile components and to reduce possible oxidation.
B. Insure that Sample Containers are Clean: It is critical
that sampling containers and their caps be clean. The EPA
Handbook for Analytical Quality Control in Water and
Wastewater Laboratories (EPA 600/4-79/019) gives special
instructions for the cleaning of bottles to be used for
organic analysis. It is possible to use a new plastic
container and dispose of it after completing the analysis.
C. Determine the Type of Sample: Grab or Composite: A grab
sample is one taken from only one point at one particular
time. Most of the sampling at Class II well facilities will
be grab samples. If sampling points are provided the
wellhead is an ideal place to take a grab sample of injected
fluids. Widemouth sampling jars are preferred to facilitate
rapid collection; the sample volume depends on analytical
work to follow. Grab samples are required if parameters
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such as dissolved gases, residual chlorine, sulfides, or pH
are to be analyzed. These require immediate preservation
and sealing in accordance with Appendix D. A composite
sample is a mixture of individual samples collected "over
time". A composite can be very useful at a Class I well
site if care is taken to make sure the sample is
representative of the entire waste.
A Class I injection stream should be sampled proportional to
the flow rate. A typical ratio is one milliliter sample for
each gallon per minute of flow. Automatic liquid samplers
are available which composite samples on the basis of flow
or time.
D. Follow Chain-of-Custody Procedures: The Agency and
owner/operator must both be in a position to demonstrate the
reliability of evidence by proving the chain of possession
and custody of samples for which analytical test results are
presented. Procedures have been established by the EPA to
create an accurate written record that can be used to trace
the possession of the sample from the moment of its
collection through its introduction into evidence. Details
of sample control are included in the NEIC Policies and
Procedures Manual (EPA-330/9-78-001).
5.4 DEALING WITH THE UNCOOPERATIVE OWNER/OPERATOR
5.4.1 Denial of Entry
Denial of entry into a facility warrrants certain procedural
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steps that should be undertaken by the inspector to ensure that proper
legal guidelines are followed. Upon refusal of entry into a facility
the inspector should explain the authority invested to him for this
inspection and the reasons for the protocols followed. If the right of
entry is still not granted the inspector should leave the premises
immediately and contact the designated Regional Enforcement Attorney as
soon as possible. A professional attitude should prevail at all times
and under no circumstances should an inspector imply that restrictions
or penalties may be pending. The steps shown below are in accordance
with the Safe Drinking Water Act and the 1978 U.S. Supreme Court
decision in Marshal v. Barlow, Inc. and should be followed in the event
entry to a facility is denied for inspection purposes.
Make certain that all credentials and notices have been properly
presented to the facility owner or agent in charge.
If entry is not granted, ask why. Tactfully probe the reason
for the denial to see if obstacles (such as misunderstandings)
can be cleared. If resolution is beyond the authority of the
inspector, he or she may suggest that the officials seek advice
from their attorneys on clarification of the scope of EPA's
inspection authority under the Safe Drinking Water Act.
* If entry is still denied, the inspector should withdraw from the
premises and contact his or her supervisor. The supervisor will
confer with attorneys to discuss the desirability of obtaining
an administrative warrant.
# All observations pertaining to the denial are to be carefully
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noted in the field notebook. Include facility name and exact
address, name and title of person(s) approached, authority of
person(s) who refused entry, time of denial, reason for denial,
facility appearance, any reasonable suspicions that refusal was
based on a desire to cover up regulatory violations, etc. All
such information will be important should a warrant be sought.
If the owner withdraws his consent to the inspection during the
course of the investigation the same procedures stated earlier would
apply. All observations, samples and information acquired before
withdrawal of consent would be valid and admissible in any subsequent
enforcement action.
An inspector may seek to obtain a warrant if denial to enter a
facility for inspection purposes occurs. If this is the case an
inspector should realize under what circumstances a warrant is
necessary and what showing is necessary to obtain a warrant. In
securing a warrant three documents must be detailed:
- An Application for a Warrant
- An Accompanying Affadavit with Facts Supporting the Issuance of
a Warrant
- The Actual Warrant
Once the warrant has been issued, the inspector should proceed to
the establishment and resume the inspection. The inspection should be
conducted strictly in acordance with the warrant. On completion of the
inspection the warrant must be returned to the magistrate.
There are areas where a right of warrantless entry exists. These
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type of inspections are shown below:
- Emergency Situations, Imminent Hazard Situations and Potential
Destruction of Evidence Situations
- "Open Fields" and "In Plain View" Situations
5.4.2 Professional Business Ethics
Inspectors should conduct their inspections with the highest
degree of professionalism and workmanship possible. Since the
inspector is usually the initial or only contact between the operator
and the regulatory agency it is imperative that he be dignified,
tactful, courteous and diplomatic in his dealings with company
personnel. To promote good working relations and establish a
cooperative atmosphere the inspector should employ a firm but
responsive attitude. The following rules should be applied when
inspecting a facility:
- Details of an inspection should be developed and reported with
complete objectivity.
- All information aquired during an inspection is for official use
only.
- No favors or benefits should be accepted under circumstances
that might be construed as influencing the inspectors
performance of duties.
5.5. INSPECTION REPORT
Inspection reports are essential and valuable tools in preparing
evidence reports and in providing clear, concise methods for remedying
problems and deficiencies noted during an inspection. A well organized
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inspection report should follow the general guidelines discussed in
this section.
The organization and arrangement of a report should be:
# Accurate: All information must be factual and based on sound
inspection practices. Observations should be the verifiable
result of firsthand knowledge. Compliance personnel must be
able to depend on the accuracy of all information.
ฐ Relevant: Information in an inspection report should be
pertinent to the subject of the report. Irrelevant facts and
data will clutter a report and may reduce its clarity and
usefulness.
ฐ Comprehensive: Suspected violation(s) should be substantiated
by as much factual, relevant information as feasible to gather.
The more comprehensive the evidence is, the better and easier
the enforcement task will be.
0 Coordinated: All information pertinent to the subject should be
organized into a complete package. Documentary support (e.g.,
photographs, statements, sample documentation, etc.)
accompanying the report should be clearly referenced so that
anyone reading the report will get a complete, clear overview of
the situation.
* Objective: Information should be objective and factual; the
report should not speculate on the ultimate result of any
factual findings.
Clear: The information in the report should be presented in a
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clear, well-organized manner.
0 Neat and Legible: Allow time to prepare a neat, legible report,
type-written if possible.
Basic steps in preparing and writing the inspection report include
the following:
# Reviewing the Information: The first step in preparing the
narrative is to collect all information gathered during the
inspection. The inspector's field notebook should be reviewed
in detail. All evidence should be reviewed for relevance and
completeness. Gaps may need to be filled by a phone call or, in
unusual circumstances, by a follow-up visit.
Organizing the Material: The information may be organized in
many forms depending on the individual need, but should present
the material in a logical, comprehensive manner. The narrative
should be organized so that it will be understood easily by the
reader.
# Referencing Accompanying Material: All documentary support
accompanying a narrative report should be clearly referenced so
that the reader will be able to locate these documents easily.
All documentary support should be checked for clarity prior to
writing the report.
# Writing the Narrative Report: Once the material collected by
the inspector has been reviewed, organized, and referenced, the
narrative can be written. The purpose of the narrative is to
record factually the procedures used in, and findings resulting
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from, the evidence-gathering process. The inspector should
refer to routine procedures and practices used during the
inspection, but should describe facts relating to potential
violations and discrepancies in detail. The field notebook is a
guide for preparing the narrative report.
The main body of the report should contain all pertinent facts and
information aquired during the inspection and more generally the three
basic items listed below:
* Report of Permittee Compliance Activities
ฐ Documentary Support
0 Supplementary Narrative Information
Some useful guidelines in writing a narrative report are
illustrated below:
ฐ General Information
- State the purpose of the inspection and how the facility came
to be inspected (e.g., operator notification, complaint
response, etc.).
* Findings and Conclusions
- State the factual compliance findings of the inspection.
Include any problem areas discovered at the facility which
currently are or potentially may affect compliance.
- State the compliance status with permit requirements including
effluent limitations where appropriate.
- Describe any problems such as entry to the facility,
reluctant, denied, or withdrawn consent for entry or if a
warrant was needed.
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Facility Informaiton
- State location of facility and name, title and phone number of
person in charge.
- Give the size of the facility based on observations and
previous data in both production and injection flows, and
number of wells.
- Describe the injection system and the operations.
- Describe adequacy of permit or permit application in relation
to actual facility conditions, (e.g., sampling points and
monitoring locations).
Documentation
- List the records reviewed, noting the reasons for their
review, and referencing documents that were borrowed or
copied.
- Describe any inadequacies in recordkeeping procedures, or if
any required information was unavailable, incomplete or
inaccurate. Specific attention should be paid to pressure and
flow measurement records, and construction schedules (if
relevant).
- Note and reference any statements taken during the
inspection.
- Reference photographs taken during the inspection if they are
relevant to possible discrepancies.
- Reference any drawings, maps, charts, or other documents made
or taken during the inspection.
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8 Monitoring Information
- Describe sampling points and techniques used.
- Note if split samples were taken.
- Describe methods of an annul us and injection pressure
monitoring.
- Describe chain-of-custody procedures used in handling
samples.
Attachments
- Prepare list of all documentary support attached to the
report. A general index list, rather than detailed
descriptions, will aid compliance personnel in locating
specific documents.
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REFERENCES CHAPTER 5.0
Unites States Environmental Protection Agency. NPDES Compliance
Inspection Manual. Draft report, EPA office of Water Enforcement and
Permits, Washington, D. C. March, 1984.
United States Environmental Protection Agency. Underground Injection
Control Packaged Training Course for Owners and Operators. EPA
68-01-642^1 Office of Drinking Water, Washington, D. C. March, 1983.
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FIELD SAFETY
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6.0 FIELD SAFETY
The UIC inspector is required to visit many different types of
injection sites operating under constantly changing conditions. Heavy
machinery and tools are used to perform most injection well
construction and servicing, and many times in adverse weather and other
hostile environmental conditions. Fortunately direct exposure to
hazardous situations is minimized by his role as an inspector. Safety
in the highly competitive well drilling field is however often
perfunctory and becomes an individual's primary responsibility to
himself. One cannot always rely on the well operator or his
contractors to specify what equipment and precautions are required.
6.1 PERSONAL PROTECTIVE EQUIPMENT
In general certain personal protective equipment are always
required in the field. This includes head protection, eye protection
and foot protection. Where special circumstances warrant hand
protection, and hearing protection may also be needed. Breathing
equipment will probably never be needed by the Region III UIC field
inspector.
A. Head Protection
1. An approved helmet (safety hard hat) is required to be
worn by all inspectors while within a control area with
the exception of self contained areas such as truck cabs
and field offices.
2. Helmets (safety hard hats) for the protection of heads
from limited electric shock and burn should comply with
the requirements and specifications established in
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American National Standards Safety Requirements for
Industrial Head Protection, Z89.1-1969. (Class A helmets
are recommended).
3. Employees should inspect and maintain liners in helmets to
comply with standards and should be worn properly.
4. Helmets should not be modified in any manner.
B. Eye and Face Protection
Safety glasses, worn at all times during field
inspections, and that meet the ANSI Eye Protection
Standard Z87.1-1979.
C. Foot Protection
1. Safety shoes or safety boots are required for all field
inspections.
2. Safety-toe footwear must meet the requirements and
specifications in American National Standard for Safety -
Safety-Toewear, Z41.1-1967 and must be properly
maintained.
D. General Protective Equipment
1. Unreasonably loose, poorly fitted or torn clothing should
not be worn.
2. Hazardous jewelry, such as finger rings, chain bracelets,
etc., should not be worn. This is not intended to mean
wrist watches equipped with bands which will easily
break.
3. When conditions warrant, typically during drilling and
workover, gloves and hearing protectors should be worn.
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4. Hair of such length that it may become entangled in moving
or rotating machinery should be contained in a suitable
manner. Beards and sideburns should be kept in such
condition and of such length so as not to interfere with
the proper and efficient use of gas masks, air masks, or
other safety apparel or equipment, otherwise equipment
giving full head coverage should be worn.
6.1.1 Suggested Personal Protective Equipment Specifications
The following is designed to supply information on features
needed in all types of personal protective equipment used in drilling
and well servicing operations (API, 1981). This equipment is not
needed or necessary in all circumstances. But, if in the exercise of
your own judgment such equipment is necessary, the following
description of equipment may prove helpful.
A. Head Protection
1. Field personnel should use a high density polyethylene
hat. The shell should have three major features:
a. A rain trough to prevent water from running down the
back of the neck.
b. Structured ribs molded into the crown to assure
maximum strength and rigidity.
c. A flat facade to accommodate hot stamping of EPA
identification. The Hard Hat should weigh 13 ounces
and have adjustable headband and four point
suspension.
2. Winter liners should be designed to fit under most brands
of safety caps or hats. They should be sized to cover the
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back of the neck. Universal size (one size fits all), and
flame retardant.
An additional advantage should be that the liner folds up,
out of the way on the outside of the cap or hat, when not in
use.
B. Eye Protection Equipment
1. Eye protection must meet the requirements of American
National Standard Z 87.1-1979, each lens should have
been subjected to a rigorous drop-ball test before it
leaves the factory.
Lenses that should be accepted are as follows:
a. True Color - neutral grey lenses primarily used as
anti-glare lenses outdoors.
b. Clear - to be used indoors and outdoors.
c. Calobar - green lenses designed to be worn as a
safeguard against glare, ultraviolet and infrared
radiators.
2. All eye protection should use side shields made of 24 or
40 wire mesh with plastic binding, reinforcing brace
bar, to provide maximum lateral protection.
3. Cover goggles should have (4) slotted air vents (or air
directing baffles) to control air flow and prevent inner
fogging. Goggles should meet the requirements of ANSI
X871-1979 for eye protection devices. The lens should
be a molded polycarbonate material and be ophthalmically
correct and free of distortion and aberrations.
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C. Hearing Protectors:
1. Muff-type hearing protectors, lightweight, rotational unit
that can be worn over the head, behind the head, or under
the chin. The unit should have been tested in accordance
with ANSI Z24.22-1957.
2. Self-adjusting hearing protectors, should be lightweight,
easy-to-wear, automatically and gently sway for proper
fit, disposable and individually wrapped. Attenuation
tested in accordance with ANSI Z24.22-a957.
3. Self-fitting in-the-ear hearing protector attached to a
stainless steel head strap. Should be non-toxic,
non-allergenic; high tear strength silicone rubber
fabrication. A stainless steel headband with vinyl cover.
The hearing protection should be able to be worn over
head, under chin, or behind head. Attenuation tested in
accordance with ANSI S-3.19,1975.
D. Hand Protection:
Select the right glove. Glove usage falls into one of three
categories; General Purpose, Liquidproof or Product
Protection.
1. General Purpose:
a. Determine the physical conditions to which the glove
will be subjected (cutting, puncturing, abrasion,
etc.).
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b. Consider the glove features required to perform the
work (dexterity, protection, grip, etc.).
c. Choose the style which provides the best combination
of features and resistance to physical conditions.
2. Liquid Proof Uses:
a. Choose glove type with highest rating for the
chemical and physical conditions involved. Use two
sets of gloves while the outer should be appropriate
to the types of fluids involved.
b. Select unsupported gloves for extra dexterity and
sense of touch. If cut, snag, puncture or abrasion
resistance are important, pick a fabric lined style.
c. Select a palm finish to provide the grip needed for
the job-smooth, sprayed, dipped or embossed. Sprayed
and dipped finishes grip best when wet.
d. Choose glove length by depth of which arm will be
immersed, and to protect against chemical splash.
e. Select thin gauge gloves for jobs demanding
sensitivity and high flexibility. If greater
protection or durability is wanted, choose a heavy
duty style, particularly in dealing with organic
solvents.
f. Choose the glove size or sizes that will assure
optimum wear, dexterity, working ease, comfort and
employee satisfaction.
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3. Production Protection:
Determine the degree of glove toughness, sheerness, fit,
sensitivity and disposability required. Then select the
glove which provides those benefits in order of their
importance.
6.1.2 Other General Considerations for Personal Safety;
A. Wearing special protective clothing can decrease an
individual's hearing, vision and agility and greatly increase
the chance of "heavy metal contamination" (injury by drilling
tools, equipment and vehicles).
B. Personnel must not eat, drink, chew gum or tobacco, smoke,
take medicines or perform any other practice that might
increase hand to mouth transfer of toxic materials from
gloves, unwashed hands or equipment.
C. If respirators are required, personnel should not have
excessive facial hair (heavy mustaches, beards) which can
prevent the proper fit of respirators.
D. The inspectors car should be parked well clear of the control
area with keys left inside so that it may be moved in the
event of an emergency situation.
6.2 POTENTIAL HAZARDS
The UIC inspector will encounter different types of hazards
depending on the type of inspection being conducted. As far as safety
is concerned these may be treated in three categories:
# Safety During Well Treating Operations
ฐ Drilling and Well Workover Safety
# Safety During Routine Inspections
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6.2.1 Safety During Well Treating Operations
Well treating usually consist of hydraulic fracturing,
acidization or both. The primary hazards involve both high pressures
and corrosive materials. Treating pressures of up to 5,000 psi are not
uncommon. When lines give way under this type pressure flying objects
can become deadly projectiles. For this reason all pressurized hoses
should be hydrostatically tested, secured by chains and sometimes
covered with hose covers to deflect fluid leaks. Normally as an added
precaution well treating is scheduled during daylight hours. A face
shield is required whenever acids are to be handled.
The major types or acids used in well stimulation work includes
hydrochloric, acetic acid, formic acid and hydrofluoric acid. Some
special acids such as sulfamic, citric, lactic and others are used on
occasions for particular applications. A description of the chemical
hazards of the common materials is presented in Section 6-3.
During well treating the inspector should should stay clear of the
controlled area which should be plainly designated. The most
advantageous location to witness treating is on the treating truck
where injection pressures can be monitored. It is an industry standard
for treating trucks and tanks to be located a minimum distance of 100'
from the well and out of fall line of the derrick.
6.2.2 Drilling and Well Workover Safety
The inspector's greatest exposure to accidents is probably
during well drilling and workover operations. In order to prevent his
involvement in a serious accident he must be able to recognize unsafe
conditions and unsafe practices.
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A. The following general safety rules should apply anytime the
inspector is involved in monitoring construction, workovers,
plug and abandonment or other activities where a drilling or
workover rig is operating.
1. Park outside of guylines.
2. Wear hard hat, safety shoes and safety glasses at all
times within the guylines.
3. Note location of fire extinguishers. They could be stored
at different locations on each job but are normally at an
obvious and easily accessible place.
4. Never smoke near flammable materials.
5. Insure that pipe stored on pipe rack is adequately chocked
with a chock pin.
6. Stay clear of shear relief valves and lines when under
pressure.
B. Normally an inspector's duties will not require him to go on
the rig floor, however should this become necessary, he must
be accompanied by the operator or his representative. While
in the immediate working area the following safety rules
should be exercised:
1. Wear gloves due to greasy and slippery handrails and to
protect against potential hand injuries.
2. Keep hands off of and feet clear of all lines that are
moving.
3. Watch for greasy or slippery floor.
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4. Stand clear of rig crew members which are breaking
connection of tools or tubular goods.
5. Watch for wickers on wire rope.
6. Note that guard rails on ladders and platforms must be in
pi ace.
7. Stay alert. Consider the safety implications of the work
being peformed.
3 Safety During Routine Inspections
A. Hard hat, safety glasses, outer protective coveralls and
safety shoes are the minimum requirements for entering any
operating area.
B. Insist that any gauge calibration or sampling be performed by
the operator's personnel. Waste streams associated with Class
II injection operations are not usually of a hazardous nature.
High pressures or faulty equipment however could be dangerous.
The well operator should know the best manner to procure a
sample, what safety measures his personnel should take and
what isolation points are necessary to swap out gauges if this
is required.
C. Class I injection operations will require an added element of
safety since hazardous or toxic chemicals may be involved.
There are currently no active Class I wells in Pennsylvania
and it is not possible to predict what types of chemicals may
some day be injected. It is safe to assume that during
sampling or testing of Class I wells the inspector may come
into contact with high concentrations of hazardous materials.
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Sampling equipment will, in many cases, become unavoidably
contaminated. These items must be thoroughly cleaned before
the next use. The decontamination procedure will vary greatly
depending on the nature of the hazardous materials (degree,
type and form of the hazard), and the nature of site
activities. In general, the more harmful the contaminant, the
more extensive or thorough the decontamination should be.
Contaminated equipment must not be taken home where it may
expose others to hazardous substances. If splashed during
testing operations personnel should shower themselves
immediately.
D. Utilize disposable clothing and sampling devices to minimize
the amount of equipment to be cleaned and volumes of
decontaminants and rinse solutions to be disposed of.
E. Steam cleaning or high pressure spraying utilizing water with
a general purpose low sudsing soap or detergent, is the
decontamination method of choice (Maslansky, 1983). Physical
scrubbing by disposable or easily decontaminated brushes may
be necessary to loosen caked-on materials. In most instances
hot water (120-180#F) is more effective than cold. Flushing
should be done under high pressure taking care not to damage
items on the equipment such as dials and gauges and loosely
hanging wires or hoses.
6.3 CHEMICAL HAZARDS AND PROCEDURES
Chemical data forms are available from sources such as
manufacturer's catalog and specific handling guides for potentially
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hazardous materials such as Baskin (1975). The documents cover
information important for the safe handling of chemical materials used
in injection well construction and treatment. Additionally, fire
hazard, chemical reactivity and first aid are also presented iri the
data forms so that steps necessary for accident prevention may be
taken. The following list of chemicals will be of interest to the
inspector but may not be all inclusive.
0 Hydrocloric Acid (HC1)
ฐ Hydroflouric Acid (HF)
ฐ Acetic Acid (CH3COOH)
0 Formic Acid (HCOOH)
" Sodium Hydroxide (NaOH)
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REFERENCES CHAPTER 6
American Petroleum Institute. Recommended Practices for Occupational
Safety and Health for Oil and Gas Well Drilling and ServiceUperationsT
API RP54, Dallas, Texas, 19817
Association of Oilwell Servicing Contractors, Recommended Safe
Procedures and Guidelines for Oil and Gas Well Servicing. AOSC,
Dallas, Texas, 1980.
Baskin, David A. Handling Guide for Potentially Hazardous Materials.
Material Management and Safety, Incorporated, Niles, Illinois, 1975.
Maslansky, S.P. Well Drilling and Hazardous Material Sites. Waste
Water Journal, April 1983, pp 46-50.
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BLOWOUT PREVENTION AND CONTROL OVERVIEW
-------
7.0 BLOWOUT PREVENTION AND CONTROL OVEWVIEW
A blowout is by definition the uncontrolled flow of formation
fluids to the surface or another underground zone. They can occur
during drilling or workover if excessive formation pressures are
encountered.
It is unlikely that the Region III UIC inspector will ever see a
blowout. This is because of the absence of abnormally pressured zones
in Region III and other conditions that have resulted in blowout in
other states and offshore. However, since a single blowout or spill,
unfortunate in its magnitude, time or place, can do irreparable
environmental harm a basic discussion on blowout prevention needs to be
addressed. This section of the Inspection Guide is obviously not
intended as a course to train the inspector how to prevent or control a
blowout. Blowout control can be quite complex, requires detailed
planning, practice and precise execution. It is a primary
responsibility of the drilling or workover crew working under
potentially high pressure conditions.
Every phase of well control follows logical concepts. These
concepts can be placed into one of three levels of well-control:
1. Primary Control
2. Secondary Control
3. Tertiary Cotrol
7.1 PRIMARY CONTROL
Primary Control is the prevention of kicks. A kick is the entry
of formation fluids into the wellbore in large enough quantity to
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require shutting in the well under pressure. This level of control is
the most critical - if kicks are prevented, blowouts cannot occur.
Formation fluids cannot enter the hole at a given point as long as
the hydrostatic pressure of the mud in the annul us is greater than the
formation pressure. Hydrostatic pressure depends on only two variables
- density and height of the fluid column. The density conveniently is
expressed in lbs per gal or psi/ft. The height simply is to the depth
to a datum level. In directional wells, the fluid column height is the
true vertical depth.
Causes of Kicks - Any event or chain of events that results in
insufficient hydrostatic pressure can cause a kick. The most common
causes are:
1. Failure to keep the hole full on trips,
2. Excessive swab pressures,
3. Insufficient mud density,
4. Loss of circulation, and
5. Abnormally-pressured formations.
Several drilling studies have shown that the most frequent cause
of kicks is insufficient mud weight. This is obviously not a problem
in the enhanced recovery areas of Region III since much of the drilling
is done with air.
Another frequent cause of blowouts is kicks encountered while
drilling shallow, gas accumulations. Reaction time is short; minimum
blowout prevention equipment is being used; total containment of
formation pressure is difficult, if not impossible; and the hole can be
unloaded in a very short time.
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In some Class I disposal wells kicks and even blowouts have
occurred during workovers. This has been due to gas accumulations
resulting from interactions between the wastewater and formation, i.e.,
acidic wastewater reacting with carbonate rocks to form carbon
dioxide.
Kicks can be minimized if the rig crews;
1. Understand the causes of kicks,
2. Use proper equipment and techniques to detect an unplanned
reduction in hydrostatic pressure,
7.2 SECONDARY CONTROL
Loss of Primary Control does not mean that the well is "out of
control". As long as the kick is properly handled, control can be
maintained until the invading fluids are circulated out and Primary
Control restored. This is called Secondary Control. A kick that is
not contained can rapidly deteriorate into a blowout.
Closing-In the Well - Shutting in the well quickly is the first
and most important step in Secondary Control. This requires continual
practice by the drilling or workover crews. Blowout preventer (BOP)
drills should be conducted routinely for crews working in high pressure
areas.
Not all wells should be shut-in. If casing is set shallow or
fracture gradients are especially low, shutting-in the well may cause
immediate broaching to the surface or an underground blowout.
Diverting of flow away from the rig may be the best alternative. The
well eventually may be killed by pumping heavy mud at a fast rate,
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setting a cement or barite plug, or natural bridging of the formation.
BOP Equipment - Control cannot be maintained without equipment.
The blowout preventers, closing unit, manifolding, choke and auxiliary
equipment all are important. To insure that each segment will operate
in an emergency, the equipment must be maintained and tested
periodically. All preventers and related equipment should be tested
with water to full rated pressure, with the exception of the annular
preventer. Testing of the annular preventer to more than 70% of the
working pressure could damage the sealing element.
In addition to pressure testing, ram-type preventers should be
actuated on the drill pipe once each trip, but not less than once each
day. The annular preventer should be actuated on the drill pipe once
each week. An inside BOP and work/drill string safety valves should be
kept in an accessible location on the rig floor at all times.
Stripping or Snubbing: It is difficult to kill a well if the
drill string is not on bottom. If the kick was detected while
tripping, the drill string may have to be stripped or snubbed into the
hole. Excessive pressures should be bled off to prevent breaking down
the formation or exceeding surface equipment pressure rating.
Circulating Out the Kick: Full Primary Control is not restored
until the kick is circulated out and mud balances the pressure in the
kicking formation. The two important concerns while accomplishing
these two tasks are:
1. Keep the bottomhole pressure imposed on the formation higher
than the formation pressure. If it is not, more formation
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fluids can enter the hole.
2. Do not let surface pressures get too high while trying to
overbalance the formation pressure. Excessive surface
pressure can fracture the formation, or rupture casing and
blowout prevention equipment.
Well-Control Methods - The only proper way to circulate out a kick
is to maintain a constant bottomhole pressure. Conventional industry
methods are special cases of a more general Constant Bottomhole
Pressure Method. They differ, in a practical sense, by the mud weight
selected for the first circulation:
1. DRILLER'S METHOD
New Mud Weight = Original Mud Weight
2. WAIT AND WEIGHT (ENGINEER'S) METHOD
New Mud Weight = Kill Mud Weight
3. CONCURRENT (COMPOSITE) METHOD
New Mud Weight increasing from Original Mud Weight to Kill Mud
Weight
Each version has advantages and disadvantages. The proper value
to use for the new mud weight depends on well conditions, crew
capability, barite supplies, mixing facilities and company policy.
Standpipe Pressure Control - Changes in the bottomhole pressure
imposed on the formation are monitored by the standpipe or drill pipe
pressure gauge. In order to maintain the proper bottomhole pressure,
the required standpipe pressure must be determined at the beginning of
circulation. The final standpipe pressure should be maintained from
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the time the new mud reaches the bit until it is detected at the
surface.
The initial standpipe pressure is the reduced pump pressure plus
the shut-in drill pipe pressure. This is valid regardless of the
"method" chosen. The final standpipe pressure depends on the new mud
weight. If the mud is not weighted up (Driller's Method), the initial
and final pressures are the same. If the mud is weighted to kill mud
weight (Wait and Weight Method), the final standpipe pressure is equal
to the new reduced pump pressure (old value modified by a mud weight
ratio).
The reduced pump pressure values should be taken and recorded
hourly to insure they are available in an emergency. For wells using
subsea stacks, it is also important to measure the choke-line pressure
losses at the kill pump rate. The kill pump rate is reduced from the
normal rate, usually to about a half or a third. The selected kill
pump rate should be maintained constant throughout the kick-circulation
process.
A schedule can be prepared to show the required standpipe
pressures as new mud is circulated. (The Driller's Method does not
require a schedule). Essentially, we need to know how much new mud is
in the drill string, when the new mud reaches the bit, and the
associated standpipe pressures. One method of developing the standpipe
pressure schedule is to use graph paper. An alternate is to calculate
a pressure reduction per 100 strokes.
Potential Difficulties - Even with the best planning and training,
7-6
-------
certain difficulties can be encountered while killing the well. The
crew should look for problem signs and take appropriate action. Among
these difficulties are:
1.
Starting up the Pump,
2.
Barite Contamination,
3.
Loss of Circulation,
4.
Hole in the Pipe,
5.
Plugged Pipe or Bit Nozzle
6.
Changing Pump Rate,
7.
Pump Failure,
8.
Choke Plug or Washout,
9.
Stuck Pipe,
10.
Sour Gas (H2S), and
11.
Drill String Off Bottom
Effect of Influx - Formation fluids entering the wellbore can be
gas, oil, saltwater, or a combination of all three. The type of influx
can affect the well behavior.
The constant bottomhole pressure method is not affected by the
type of influx. Essentially each kick is treated as gas, the worst
case. The differences that do exist include pit volume changes,
required casing pressures and disposal at the surface.
Gas is compressible; oil and saltwater are not. Gas must be
allowed to expand as it is circulated out of the hole. Otherwise,
pressures in the hole increase and endanger fracturing the formation.
Most of the gas expansion occurs in the top 1000-2000 ft. The gas
7-7
-------
expansion reduces the hydrostatic pressure in the annul us. Thus,
casing pressures on a gas kick will be higher throughout the kill
operation.
If the invading fluid cannot be incorporated into the mud easily
(such as small amounts of saltwater or oil), the kick fluid physically
must be removed from the mud system. Gas is processed through a
mud-gas separator and degasser, and flared. Large volumes of oil and
water can be routed away from the active circulating system and
disposed of carefully.
7.3 TERTIARY CONTROL
Tertiary Control is the proper use of equipment and techniques to
regain control after a blowout has occurred. The blowout can be a
surface or underground blowout. In either case, control of the well
has been lost.
If the casing and at least part of. the wellhead equipment are
still intact, a blowout at the surface is generally capped. Otherwise,
a relief well must be drilled. A relief well is directionally drilled
in an attempt to establish communications with the blowout. This can
be quite difficult if multishot surveys are not available. Once the
relief well is close to the flowing wellbore, thousands of barrels of
water usually are pumped to establish communications and "load" the
hole. The water is followed by heavy mud and later by cement, if
necessary.
Underground blowouts are usually controlled by relief wells also.
In some situations, however, the well can be killed by pumping heavy
7-8
-------
mud down the drill pipe at a relatively high rate. Others may require
that a liner be driled and cemented across the loss zone.
7-9
-------
REFERENCES CHAPTER 7.0
IADC, "Blowout Prevention", Lessons in Rotary Drilling, Unit III,
Lesson 3, Petroleum Extension Service, University of Texas, Austin.
Zamora, Mario and Kimball, Mike, "New CBHP Method Solves Kick-Control
Problems", Oil and Gas Journal, March 6, 1978.
Hamby, T. W. and Smith, J. R. "Contingency Planning for Drilling and
Producing High Pressure, Sour Gas Wells", SPE 2512, 1971.
Nelson, R. F., "The Bay Marchand Fire", Journal of Petroleum
Technology, March, 1972.
7-10
-------
APPENDICES
-------
APPENDIX A
WELL DIAGRAMS ILLUSTRATING
PLUG LOCATIONS
-------
WELLS WITHOUT PRODUCTIVE CASING
-------
WELLS WITH PRODUCTION CASING &
CEMENTED USING MULTI-CASING
HOLE
SURFACE CASING
PRODUCTION CASING
BASE OF USABLE WATER
MULTI-STAGE TOOL
PERFORATIONS
-------
WELLS WITH PRODUCTIVE CASING
AND CEMENTED THROUGH ALL
USABLE WATER & PRODUCTIVE HORIZONS
HOLE
SURFACE CASING
PRODUCTION CASING
BASE OF USABLE WATER
PERFORATIONS
-------
WELLS WITH PRODUCTION CASING
NOT CEMENTED THROUGH ALL
USABLE WATER & PRODUCTIVE HORIZONS
HOLE
SURFACE CASING
50'
* PERFORATIONS
PRODUCTION CASING
BASE OF USABLF. WATER
PERFORATIONS
PERFORATIONS
-------
INTERMEDIATE CASING NOT CEMENTED THROUGH
ALL USABLE WATER & PRODUCTIVE HORIZONS
-------
INSUFFICIENT SURFACE CASING SET
PROTECT ALL USABLE WATER
TO
HOLE
CEMENT
CASING
THIS PLUG MUST BE TAGGED
BASE OF USABLE WATER
-------
SUFFICIENT SURFACE CASING SET TO
PROTECT ALL USABLE WATER
HOLE
CEMENT
SURFACE CASING
TOP OF USABLE WATER
BASE OF USABLE WATER
-------
SURFACE CASING SET DEEPER THAN 200'
BELOW BASE OF USABLE WATER
HOLE
CEMENT
CASING
BASE OF USABLE WATER
-------
WELLS WITH INTERMEDIATE CASING & CEMENTED
THROUGH ALL USABLE & PRODUCTIVE HORIZONS
-------
APPENDIX B
BASIC BALANCE PLUG JOB
-------
Basic Balance Plug Job
A cement plug may be set anywhere in a hole that is static. To
set a balanced plug, the height of each fluid inside and outside the
work string must be equal. In order to do a balanced plug job, cer-
tain volumes and heights of fluids must be calculated. These in-
clude volume of cement in cubic feet and sacks, mixing water for the
cement, displacement fluid required to spot the cement, and (if
water is run ahead of the cement) the volume of water required be-
hind the cement to balance the water ahead.
A plug job could be as follows: set a 200 ft plug of Class A
cement, 15.6 lb/gal, in an 8 3/4 in. open hole with 15 bbl of water
run ahead of the cement. The plug is to be spotted through a work
string of 4 1/2 in. EU 16.6 lb/ft drill pipe. The drill pipe is
run to a depth of 6,000 ft (which will be the bottom of the cement
plug). There is mud in the hole.
The first calculation would be the cubic feet of e'ement re-
quired for the job. Since a 200 ft plug is to be left in the open
hole, go to the Cementing Tables, Section 210, for capacity of the
open hole in cu ft/lin ft and find
.4176 cu ft/lin ft x 200 ft = 83.52 cu ft
Class A cement mixed at 15.6 lb/gal is to be used for the job.
Slurry properties for Class A cement are in Section 230 of the
Cementing Tables. For 15.6 lb/gal, the water requirement is 5.2
gal/sk and the yield is 1.18 cu ft/sk. With this information, the
sacks of cement can be determined by dividing the cubic feet re-
quired by the yield of a sack of cement.
83.52 cu ft * 1.18 cu ft/sk * 70.78 sk
Once the number of sacks has been determined, the volume of
mixing water can be calculated from the slurry properties obtained
for the Class A cement in Section 230. Each sack of cement requires
5.2 gal/sk; therefore,
70.78 sk x 5.2 gal/sk ฆ 368.06 gal of water
then
368.06 gal of water * 42 gal/bbl ป 8.76 bbl of water
Ken E. Davis
Amomk-iatix
-------
L
Since 15 bbl of water are to be pumped ahead of the cement, we
need to determine the height of this water in the annulus. The
height of 15 bbl of water in the annulus must be balanced by the
same height of water inside the drill pipe. The 15 bbl of water
ahead of the cement will end up in the annulus between the drill
pipe and the hole; therefore, go to Section 122 (volume and height
between drill pipe and hole) in the column headed lin ft/bbl and
find 18.2804 lin ft/bbl. Calculate
15 bbl x 18.2804 lin ft/bbl ซ 274.206 ft of water in
the annulus
There must be 274.206 ft of water inside the drill pipe to
have equal balance. The volume required in the drill pipe is de-
termined by going to Section 210 in the column bbl/lin ft to find
.0142 bbl/lin ft for 4 1/2 in. EU 16.0 lb/ft drill pipe. Since
each foot of this drill pipe will hold .0142 bbls, then
.0142 bbl/lin ft x 274.206 ft = 3.89 bbl of water
will be required in the drill pipe behind the cement or above the
cement.
The displacement necessary to spot the cement plug must now
be calculated. In order to calculate the displacement to spot the
plug, the height of the cement must be determined. Cement height
must be the same in the annulus and in the drill pipe when the plug
is set. Therefore, for each foot of cement height in the annulus,
there should be one foot of cement height in the drill pipe. The
volume required to fill one linear foot of annulus can be found in
Section 122. For the 4 1/2 in. to 8 3/4 in. annulus, under the
column headed cu ft/lin ft, this value is .3071 cu ft/lin ft. To
balance the one foot in the annulus, one foot in the drill pipe
will require .0798 cu ft/lin ft. This is found in Section 21C in
the column headed cu ft/lin ft for 4 1/2 in. EU 16.6 lb/ft drill
pipe. Therefore, one linear foot of hole with the drill pipe in
the hole has a volume of
.3071 cu ft/lin ft (annular volume)
~.0798 cu ft/lin ft (drill pipe capacity)
.3869 cu ft/lin ft of hole with drill pipe in the hole.
Since the volume of cement for the job was calculated as
83.52 cu ft, the height of cement can be calculated by dividing:
83.52 cu ft * .3869 cu ft/ft ซ 215.87 ft
With the bottom of the drill pipe at 6,000 ft, then
6,000 ft - 215.87 ft (cement height) - 274.206 ft (water
height) ฆ 5,509.924 ft (mud displacement depth) g Davis
-------
The volume of mud required for displacement is calculated by
going to Section 210 for capacity of 4 1/2 in. EU 16.6 lb/ft drill
pipe. In the column marked bbl/lin ft, find .0142 bbl/lin ft.
With this figure, the calculation is
.0142 bbl/lin ft x 5,509.924 ft ซ 78.25 bbl of mud
displacement to spot the plug
L
BASIC BALANCE PLUG JOB is calculated as follows:
4-Vi IN., 16.6 LB /FT
DRILL PIPE
8-'/ซ IN. HOLE
PLUG JOB
Set 200 ft plug in 8 3/4 in.
hole.
4 1/2 in. EU 16.6 lb/ft drill
pipe to 6,000 ft
Class A cement mixed at
15.6 lb/gal
15 bbl of water ahead
Calculate:
1. Volume of cement in cu ft
83.52 cu ft
2. Number of cement sacks
70.78 sk
3. Mixing water in bbl
8.76 bbl
4. Water behind cement in
bbl
3.89 bbl
5. Mud displacement in bbl
78.24 bbl
Ken E. Davis
Amwociatkk
-------
Capacity of 8 3/4 in hole
.4176 cu ft/ft x 200 ft ป 83.52 cu ft
Sacks of cement
83.52 cu ft * 1.18 cu ft/sk ซ 70.78 sk
Mixing water
70.78 sk x 5.2 gal/sk ฆ 368.056 gal
then
368.056 gal * 42 gal/bbl = 8.76 bbl
Water behind
V and H 18.2804 ft/bbl x 15 bbl = 274.206 ft
Capacity 4 1/2 in. drill pipe .0142 bbl/ft x 274.206 ft ป
3.894 bbl
Mud displacement
Height of cement - V and H
4 1/2 in. x 8 3/4 in. .3071 cu ft/lin ft
Capacity 4 1/2 in., 16.6 lb/ft ~ .0798 cu ft/lin ft
drill pipe .3869 cu ft/lin ft
83.52 cu ft t .3869 cu ft/lin ft ฆ 215.87 ft of cement
6,000 ft - 215.87 ft of cement - 274.206 ft of water =
5,509.924 ft of drill pipe to be displaced with mud
Capacity 4 1/2 in. EU 16.6 lb/ft drill pipe
.0142 bbl/ft x 5,509.924 ft ซ 78.24 bbl
Ken E. Davis
Anhi}(i.\ti:h
-------
USEFUL BALANCE PLUG FORMULA
1. BARRLES OF FRESH WATER AHEAD WHEN BARRELS OF FRESH WATER BEHIND IS
ETVOT
The total volume of fresh water ahead of the cement plug 1s the
product of the annulus capacity times the volume of fresh water
behind the plug divided by the volume of the drill pipe. To
calculate this volume in barrels use the following formula:
VFWA = (VA) (VFWB)
(VDPJ
Volume of fresh water ahead of the cement plug in barrels.
Volume (capacity) of the drill pipe in barrel/foot.
Volume of annular space between the drill pipe and open
hole or casing in barrels per foot.
Volume of fresh water behind the cement plug in barrels.
or:
Barrels of fresh water ahead of cement = (feet/barrel of drill
pipe) x (barrel/feet of annulus) x (barrels of fresh water
behind).
2. BARRELS OF FRESH WATER BEHIND WHEN BARRELS OF FRESH WATER AHEAD IS
GIVEN.
The total volume of fresh water behind the cement plug is the
volume of the fresh water ahead divided by the product of the
drill pipe capacity times the annulus capacity. To calculate this
volume in barrels use the following formula:
VFWB = VFWA
(VDPJ (VA)
the symbols and units are the same as in 1. above.
or:
(feet/barrel in annulus) x (barrels of fresh water ahead ซ Height
of fresh water in annulus (HFWA) 1n feet; and (HFWA) x
(barrel/foot in drill pipe) = Barrel of fresh water behind the
cement.
where:
VFWA =
VDP =
VA =
VFWB =
Ken E. Davis
Ahwkiatks
-------
jj
3. HEIGHT OF CEMENT WITH DRILL PIPE IN L
The vertical distance covered by a cement plug before the drill
pipe is withdrawn from it 1s the total cement slurry volume
divided by the sum of the capacities of the drill pipe plus the
annular space between the open hole or casing. To calculate this
distance in feet use the following formula:
HDC = TSV
(VDP) + (VA)
where:
HOC = Height of cement column in feet
TSD ฆ Total cement slurry volume In barrels.
VDP = Volume (capacity) of drill pipe in barrels/foot
VA = Volume of annular space between the drill pipe and casing or
open hole in barrels/foot.
or:
(barrel/foot of drill pipe) + (barrel/foot of annulus) = total
barrels per foot (TBPF), and the (total slurry of volume in
barrels) - (TBPF) = height of cement (HOC).
4. MUD TO BALANCE
The volume of mud required to displace and balance the cement plug
is the sum of the total depth of the drill pipe minus the height
of cement minus the height of water times the volume (capacity) of
the drill pipe. To calculate the volume of mud required to
balance the system in barrels use the following formula:
MTB = (TDP - HOC - HOW) x (VDP)
where:
MTB = Volume of mud to balance in barrels
TDP = Total depth of drill pipe in feet
HOC = Height of cement plug in feet
HOW = Height of water in feet
or:
(total footage of drill pipe) - (height of cement column in feet)
- (height of water column in feet) ซ height of mud column (HOM),
and (HOM) x (barrel/feet of drill pipe) = mud to balance.
Kkn K. Davih
Ahhikiatim
-------
APPENDIX C
PUMP DISCHARGE PRESSURE AND VOLUME DATA
TAKEN FROM SECURITY - DRESSER HYDRAULICS MANUAL
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer: BETHLEHEM - Duplex
| Model
Max
Max
Stroke
Rod
Liner Size (in)
I
I.H.P.
S.P.M.
Length
Size
4-3/4
5
5-1/4
5-1/2
5-3/4
6
6-1/4
6-1/2
6-3/4
7
7-1/4
7-1/2
7 m
8
225
225
60
14
2
-
1249
1121
1016
924
845
775
714
650
610
568
528
49a
463
-
4.4
4.9
5.4
59
6.5
7.1
7.7
8.3
8.9
9.6
10.3
11.0
11.8
I 325
325
60
16
2-1/4
-
1610
1450
1310
1190
1085
995
910
845
780
725
675
600
590
1
-
4.9
5.5
6.0
6.6
7.2
7.9
8.6
9.3
10.0
10.8
11.6
12.4
13.2
J 450
450
60
16
2 1/2
-
2300
2055
1855
1680
'10
1400
1287
1186
1098
1018
945
884
826
L
-
4.8
5.3
5.9
6.5
7.1
7.8
8.5
9.2
70.0
10.8
11.6
12.3
13.1
I 600
600
55
18
2-1/2
-
2965
2650
2395
2293
1972
1808
1660
1530
1415
1312
1220
i 141
1068
1
-
5.3
6.0
6.6
7.3
80
8.8
9.5
10.4
11.2
12.1
13.0
139
14.8
B-1640
1999
90
16
3-1/2
-
-
-
-
-
4570
-
3900
-
3360
_
2920
-
2570
ฆ
-
-
-
-
6.5
-
7.9
9.3
-
10.9
-
12.6
I G-35
468
100
14
2 1/8
-
1485
1227
-
1031
-
878
-
757
-
660
-
580
F
-
4.3
-
5.3
-
6.4
-
7.6
"
8.9
-
10.3
-
11.8
1 G-45
606
100
16
2-1/2
-
1091
-
1397
-
1174
-
1001
_
863
751
..
660
I
-
4.8
-
59
-
7.1
-
8.5
',0.0
-
11.6
-
13.1
1 G65
874
100
16
2 1/2
-
2460
-
2033
-
1708
_
1456
.255
_
1093
361
1
-
4.8
-
5.9
-
7.1
-
8.5
!9.0
-
11.6
-
13.1
1 G-85
1212
100
18
2 3/4
-
3066
-
2534
-
2129
_
1814
-
'564
_
1363
_
1198
I
-
5.2
-
6.5
-
7.9
-
9.4
-
'1.1
-
12.8
-
14.7
1 H-25
336
100
12
2
1383
-
1132
-
944
-
799
_
685
593
_
.
1
3.4
-
4 2
-
5.1
-
6.1
-
7.1
-
&2
-
-
L H-150
177
65
12
2
1180
-
948
855
779
711
653
600
555
515
478
_
_
I
3.4
-
4.2
4 6
5.1
5.5
6.1
66
7.1
8.2
-
-
-
Manufacturer: CONTINENTAL EMSCO - Duplex
1 Model
Max
Max
Stroke
Rod
Liner Size (
in)
I.H.P.
S.P.M.
Length
Size
4 1/2
4-3/4
5
5-1/4
5-1/2
5-3/4
6
6-1/4
t- V'?
6-3/4
7
7-1/4
7-1/2
L D-125
125
85
10
1-3/4
840
748
670
604
548
499
456
419
:m
357
326
:>08
_
2 5
2.9
3.2
3.5
3.9
4 3
4.7
5.1
5.5
6.0
6.4
6.9
-
1 D-175
175
75
12
17/8
1130
!000
8SS
H07
731
666
608
558
614
475
_
_
_
3.0
3.4
38
4.2
4.6
5.1
5.6
6.1
66
7.1
-
-
-
| D-225
225
70
12
1-7/8
1551
1379
1234
1111
1007
916
838
769
70S
654
607
565
_
3.0
J 4
3.8
4.2
4.6
5.1
5.6
6.1
C.6
7.1
7.7
8.3
-
1 D-300
300
70
14
2
_
1300
1430
1280
1162
1060
965
886
315
754
698
650
602
-
3.9
4.4
49
5.4
5.9
6.5
7.1
1.7
8.3
8.9
9.6
10.3
ฆ D-375
375
70
14
2
-
1391
1777
1600
1451
1318
1156
1104
-018
939
871
810
744
1
-
39
4.4
4.9
5.4
5.9
6.5
7.1
7.7
8.3
8.9
9.6
10.3
DA 500
500
65
16
21/2
-
2720
2330
2100
1902
1710
1566
1435
1317
1225
1122
1035
970
-
4 2
4.a
5,3
59
6.5
7.1
7.8
6 5
9.2
10.0
10.Fi
11.6
1 DB550
550
65
16
2-1/2
-
2915
2590
2317
2090
1894
1727
1577
1449
1336
1235
1148
1067
| 0 550
-
4 2
4 S
5.3
59
6.5
7.1
7.8
C. i
9.2
10.0
10.8
11.6
DB-700
700
65
16
2 3/4
-
-
-
-
2727
2463
2236
2044
375
1726
1593
1478
1374
, DA-700
-
-
-
-
5 8
64
7.0
7.7
B4
9.1
9.8
10.6
11.4
1 DB 850
850
60
18
3
-
-
-
-
-
2954
2680
2440
2055
1895
1758
1629
I DA-850
-
-
-
-
-
7.0
7.7
8.4
9.2
10.0
10.9
11.7
12.7
DC-1000
1000
60
18
3
-
-
-
-
-
3480
3153
2871
2635
2418
2229
206B
1917
| D-1000
-
-
-
-
-
7.0
7.7
8.4
9.2
10.0
10.9
11.7
12.7
1 DC 1350
1350
60
18
3-1/2
-
-
-
-
-
_
4474
4058
3706
3392
3123
2880
2669
F D 1350
-
-
-
-
-
-
7.3
8.1
8.8
9.6
10.5
11.4
12.3
1 DC 1650
1650
60
18
3-1/2
-
-
-
-
-
-
5469
4960
4530
4146
3817
3520
3262
I 0 1650
-
-
-
-
-
-
7.3
8.1
8.8
9.6
10.5
11.4
12.3
|q.j.ฃ Top Value: Discharge Pressure
Bottom Value: Discharge Volume
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer
CONTINENT AL-EMSCO
Triplex
.
Model
Rated
Rated
Stroke
Liner Size (in)
I.H.P.
S.P.M.
Length
3'<4
3V.
4
4
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer GARDNER-DENVER Duplex (cont'd)
Model
Max
Max
Stroke
Rod
Liner Size (in)
I.H.P.
SP.M.
Length
Size
5
5-1 '4
5-1/2
5-3/4
6
6-1/4
6-1/2
6-3/4
7
7-1/4
7-1/2
7-3/4
5
GXH
1250
60
18
3-1/4
_
_
_
3942
3281
3035
2793
2580
2400
2232
-
7.7
92
10 1
10 9
11.8
12.7
13.6
GXN
500
70
14
2-1/4
2435
1974
1633
_
1377
1271
1177
1C94
..
4 3
5 3
64
76
82
88
95
GXP
700
70
16
2-1/2
3060
2470
2040
_
1712
1578
1460
1357
1171
_
--
48
59
7.1
85
92
100
10 8
116
'
GXQ
350
70
16
2-1/4
1470
1195
1000
_
843
778
720
668
_
49
60
_
73
86
93
10.1
10 9
GXR
1000
60
18
2-3/4
_
3113
2815
2578
2373
2194
2035
1903
1172
78
86
94
10 2
111
119
128
13.7
KXF
700
70
16
2-1/2
2470
_
2040
_
1712
1578
1460
1357
1171
59
_
7 1
8 5
92
10.0
10 8
116
-
KXG
1000
60
18
2-3' 4
_
3113
2815
2578
2373
2194
2035
1903
1172
_
_
7,8
8.6
9.4
10.2
111
119
12 8
13.7
--
KXJ
1500
60
18
3-1/4
_
4845
_
4025
3640
3350
3095
_
7.5
30
10.0
10 9
118
Manufacturer GARDNER-DENVER Triplex
Model
Rated
Rated
Stroke
Liner Size On)
I.H.P.
S.PM.
Length
3
3'/.
314
4
4)4
5
5H
6
6Vi
6W
7
PJ-8
275
175
8
3118
7
2657
9
2290
10
1753
1 3
1386
16
1122
20
I
PY-7
500
160
7
3150
14
2550
1.8
2110
22
1770
26
1510
3.0
1300
3.5
PZ-7
550
165
7
3556
14
2880
18
2380 ]
2 2 1
2000
26
__
1705
3.0
1470
35
PZ-8
750
165
8
5381
1 3
4238
16
3433
20
2843
2.5
2385
29
2200
3.2
_
PZ-9
1000
150
9
5530
19
4485
23
3710
28
3110
33
2875
36
2650
3.9
2285
45
PZ-10
1350
130
10
5200
3.1
4400
3 7
3700
43
320Ci
50
PZ-11
1600
130
11
5595
3.4
4702
40
4006
4.7
3454
5 b
Manufacturer HALLIBURTON
Triplex
Liner Size (in)
Model
Rated
I.H.P.
Rated
S.P.M.
Stroke
Length
5
5V4
6
HT-4000
275
75
8
4500
2.0
3000
2.5
3000
29
Top Value: Discharge Pressure
Bottom Value: Discharge Volume
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer: IDECO
Duplex
Model
Max
Max
Stroke
Rod
Liner Size (in)
I.H.P.
S.P.M. Length
Size
3-3/4
4
4-1/2
4-3/4
5
5-1/4
5-1/2
5-3/4
6
8-1/4 6-1/2 6-3/4
7
7-1/4
7-1/2
7-3/4
e
MM-200
200
80
10
1-7/8
2000
1825
1460
1163
970
864
790
667
617
17
20
25
3 1
38
42
46
55
59
MM-300
300
80
12
2
2500
2380
1830
_
1458
1185
_
985
832
712
662
_
MM-300GB
2,0
23
30
3 7
46
55
66
7 7
8 2
MM-450
450
80
12
2-1/4
2830
2510
2225
1810
_
1500
_
1265
1165
!082
1000
2.8
3 2
3 7
45
5 5
65
7 0
76
82
MM-550
550
65
15
2-1'2
3120
2775
2480
2235
2020
1645
1690
1550
1425
1320
1220
MM-550F
40
45
50
55
6.1
6.7
73
80
87
9 4
10 1
MM-600
600
65
16
2-12
2830
2540
2280
2060
1880
_
1582
1348
1250
1165
_
_
4 8
53
59
65
7.1
85
32
10.0
10 8
MM-700
700
65
16
2-3-4
3038
2730
2470
2246
1878
1595
1487
1375
1285
MM-700F
5 2
58
6 3
70
8 4
99
106
114
12 2
MM-900
900
65
16
3
3810
3250
2950
2459
2085
1933
1795
1670
1562
52
6 0
6.8
32
:> 7
10 4
112
12.1
12 9
MM-1000
1000
65
16
3
_
_
_
_
4020
3280
2735
2510
2325
2155
2000
1860
1740
MM-1000GB
52
6.8
82
89
3 7
10 4
11.2
12 1
129
MM-1250
1250
65
18
3-1/8
3680
3350
3065
2820
2600
?400
2230
2079
1940
7 6
84
92
10 0
1C 8
1 17
12 6
13 5
14 5
MM-1450F
1450
65
18
3-1/8
4270
3880
3560
3270
3010
2790
2590
_
76
84
9 1
10 0
10 8
117
125
MM-1625
1625
65
'3
3-3/8
4920
4060
3790
j430
3170
2940
7 4
89
9 7
K':6
11 5
124
MM-1750F
1750
65
18
3-3. 8
5000
4800
4380
4020
3700
3410
3175
_
7.4
82
90
98
10 6
11 5
12.3
Manufacturer IDECO Triplex
Model
Rated
Liner Size (in)
I.H.P.
S.P.M.
Length
4
4'.2
5
5>4
6
6'5
7
7!4
T-500
500
165
8
3588
1.3
2826
1 6
2289
20
1895
2 5
1591
2 9
1356
3 4
1169
4
T-800
800
150
9
4424
1 9
3588
23
2960
2.8
2488
33
2121
39
1828
45
T-1000 H P.
1000
140
10
. 5339
1 2 1
4322
25
3580
3.1
3002
38
2559
43
2204
5
T-1300 H P
1300
120
12
5462
3.0
4514
3.7
3793
44
3232
52
2787
60
2428
6 9
T-1600 HP
1600
120
12
3 1
5556
3 7
4669
4 4
3978
5 2
3430
6.0
2988
69
NOTE
Top Value: Discharge Pressure
Bottom Value Discharge Volume
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer: NATIONAL SUPPLY
- Duplex
Model
Max
Max
Stroke
Rod
liMr Size (in)
I.H.P.
S.P.M.
Length
Site
4
4-1/4
4-1/2
4-3/4
5
5-1/4
5-1/2
5-3/4
6
6-1/4
6-1/2
6-3/4
7
7-1/4
7-1/2
7-3/4
8
C-150-B
185
70
12
1-7/8
-
-
-
-
1205
1085
985
895
820
750
690
640
595
550
-
-
-
-
-
-
-
38
4.2
4.6
5.1
5.6
6.1
6.6
?.!
7.7
8.3
-
-
-
C-250
320
65
15
2-1/4
-
-
_
-
1810
1625
1465
1330
1215
1115
1025
945
875
810
-
-
-
-
-
-
-
4.6
5.1
5.6
6.2
6.8
7.4
8.1
8.8
9.5
10.2
-
-
-
C-350
495
60
18
2-3/8
-
-
-
-
2685
2405
2170
1965
1790
1640
1510
1390
1290
1195
1115
1040
-
-
-
-
-
5.4
6.0
6.7
7.4
8.1
8.9
9.7
10.5
11.3
12.2
13.1
14.0
-
E500
590
70
14
25/8
-
-
-
-
3000
2670
2400
2170
1970
1805
1660
1530
1415
1310
1215
1135
1060
-
-
-
-
4.1
4.6
5.3
6.3
6.2
6.8
7.4
80
8.7
9.4
10.1
10.8
11.5
E 700
825
65
16
3-1/8
3000
2480
2085
1780
1535
1260
-
-
-
-
6.1
6.8
7.4
8?
8.8
9.6
-
-
-
-
G700
700
70
14
25/8
-
-
-
3535
3175
2855
2585
2350
2150
1S70
1815
1680
1560
1450
1350
1265
-
-
-
-
4.1
4.6
53
5.6
6.2
6.8
7.4
8.0
8.7
9.4
10.1
10.8
11.5
G 1000-C
1000
65
16
3-1/8
3310
3010
2755
2530
2335
2160
2010
>865
-
-
-
-
-
-
-
-
-
68
7.4
8 l
5.8
9.6
10.4
11.2
12.1
-
H 850-A
850
70
15
2 7/8
3320
2995
2720
2480
2275
2035
1935
1790
1665
1550
1450
-
-
-
-
-
-
5.3
5.9
6.5
7.1
7.8
8.4
9.1
9.8
10.6
11.4
12.2
H 1250
1250
65
16
3-1/8
4135
3765
3445
3165
2915
2700
2505
2335
-
6.8
7.4
8 i
8.8
9.6
10.4
11.2
12.0
-
K 180
180
80
10
2
_
-
_
1170
1050
945
855
775
710
650
600
555
515
475
-
-
-
-
-
2.8
3.1
3.5
3.8
4.2
4.6
5.0
5.5
5.9
6.4
6.9
-
-
--
K 280
280
75
12
2
_
_
1620
1450
1305
1180
1075
980
900
830
770
710
660
-
-
-
3.3
3.7
4.2
4.6
5.1
5.5
6.0
6.6
7.1
7.7
8.2
-
-
-
K 380
380
70
14
2-3/8
-
-
-
2100
.1875
1675
1520
1370
1255
1145
10S5
970
900
835
-
-
-
-
-
-
3.8
4.2
4.7
5.2
5.8
6.3
6.9
7.6
8.1
8.8
9.5
-
-
-
KSOO
513
70
15
2 5/8
_
- ฆ
_
2735
2425
2170
1950
1765
1605
1470
1350
1245
1150
1065
990
_
-
K500-A
-
-
-
3.9
4.4
4.9
5.5
6.0
6.6
7.3
7.9
8.6
9.3
10.0
l6.8
-
-
K-700
700
65
16
2 7/8
2760
2490
2265
2065
1890
1740
1605
1490
1385
1290
1205
K-700-A
-
-
-
-
-
-
5.7
6.3
6.9
7.6
8.3
9.0
9.8
10.5
11.4
12.2
13.0
KSH180
180
80
10
2
1725
1510
1320
1170
1050
945
855
775
710
1.9
2.2
2.5
2.8
3 1
35
3.8
4.2
4.6
-
-
KSH-280
280
75
12
2
2400
2070
1820
1620
1450
1305
1180
1075
980
2.3
2.6
3.0
3.3
37
4.2
4.6
5.1
5.5
-
N-1000
1000
65
16
2 7/8
3945
3560
3235
2950
2705
2485
2295
2130
-
-
-
-
-
-
-
5.7
6.3
6.9
7.6
8.3
90
9.8
10.5
-
-
-
N-1300
1300
65
16
3-1/8
_
_
_
_
_
-
-
4750
4300
3915
3580
3290
3030
2810
-
6.1
6.8
7.4
8.1
8.8
9.6
10.4
-
-
-
N-1600
1600
65
16
3-3/8
5440
4940
4505
4135
3810
3515
-
-
-
-
-
-
-
-
-
-
6.6
7.3
7.9
8.7
9.4
10.2
-
-
-
Top Value: Discharge Pressure
Bottom Value: Discharge Volume
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer: NATIONAL SUPPLY - Triplex
Modal
7-P-60
Ratad Rattd Stroka
I.H.P. SPM. Length
Liner Sin (in)
TO 4 4*
4ft 4ซ 8
6X SH 5%
1955 -
- 2.4 -
mm
8* 7 714
500 165 7%
4830 3695 -
1.0 1.3 -
2920 - 2365
1.6 - Z0
1645 1516 -
2.8 3.1 -
- - -
8-P-80
800 160 8%
- 492S
1.6
4395 3945 3560
1.8 10 2.2
3230 2940 2690
2.4 2.6 2.9
2470 2280 -
XI 3.4 -
_
9-P-100
1000 150 9%
- - -
5385 4830 4360
1.9 2.1 2.4
3955 3605 3300
2.6 29 3.1
3030 2790 2580
3.4 17 4.0
2395 -
4.3 - -
10-P-130
1300 140 10
- - -
- - -
5095 4645 4250
2.8 XI 3.4
3900 3596 3325
3.7 4.0 4.3
3085 -
4.6 - -
12-P-160
1600 120 12
- - -
_
5555 5085
3.7 4.0
4670 4305 3980
4.4 4.8 &2
3690 3430 3200
5.6 5.0 6.4
Manufacturer: OIL WELL Dupiax
Modal
Max
Max
Stroka
Rod
Linar Sin (in.)
I.H.P.
S.P.M.
Length
Site
5
5-1/2
6
6-1/2
6-3/4
7
7-1/4
7-3/4
8
212-P
220
70
12
1-7/8
1200
3.8
_
820
5.6
690
6.6
640
7.1
600
7.7
550
8.3
-
214-P
3S0
70
14
2-1/4
-
1375
5.3
1140
6.4
960
7.6
690
8.2
820
8.8
765
9.5
-
-
218-P
500
65
18
2-1/4
2040
5.5
-
1370
&2
1155
9.7
1065
10.5
985
11.3
915
12.2
-
-
220-P
600
60
20
2-1/2
2650
5.9
-
1765
8.9
1485
10.6
1370
11.5
1270
12.5
1175
13.4
1020
1&4
955
16.6
816-P
700
65
16
2-3/4
-
2725
5.8
2235
7.0
1875
8.4
1725
9.1
1598
9.8
1478
10.6
1280
1X2
1197
13.1
818-P
925
65
18
3-1/4
2990
7.5
2480
9.0
2275
9.9
2100
10.7
1940
11.6
1676
13.4
1560
14.4
1400-P
1400
65
18
3-1/2
:
:
4310
7.3
3560
8.8
3000
10.5
_ _ _
1700-P
1700
65
18
3-1/2
5000
7.3
4320
8.8
_
3640
10.5
_ _
7000-P
-
65
18
3-1/4
:
3660
6.1
2990
7.5
2480
9.0
2275
9.9
2100
10.7
1940
11.6
1675
13.4
_
A700-P
700
65
16
2-3/4
-
2725
5.8
2235
7.0
1875
8.4
1725
9.1
1593
9.8
1478
10.6
1280
12.2
:
A-850-P
850
65
16
3-1/4
-
3500
5.4
2850
6.7
2370
8.0
2175
&8
2005
9.5
1870
10.2
1600
11.9
A-1000-P
1000
65
18
3-1/4
3660
6.1
2990
7.5
2480
9.0
2275
9.9
2100
10.7
1940
11.6
1675
1X4
NOTE* Top Value: Discharge Pressure
Bottom Value: Discharge Volume
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacturer: OIL WELL Triplex
Modal
Max
Max
Stroke
Liner Sue (in)
I.H.P.
S.P.M.
Length
4
4-1/2
6
5-1/2
S-3/4
6
6-1/2
6-3/4
7
7-1/4
7-1/2
7-3/4
350-PT
350
175
8
2400
1900
1500
1250
1144
1050
900
_
770
_
_
_
1.3
1.6
2.0
25
2.7
2.9
3.4
-
4.0
-
-
-
850PT
850
160
9
eooo
4400
3560
7940
- ฆ
2470
2110
-
-
-
-
_
1.5
1.9
2.3
28
-
3.3
3 9
-
-
-
-
-
1100-PT
1100
150
10
-
5000
4500
3700
-
3110
2650
_
-
_
-
-
2.1
2.6
3 1
-
3 7
4.3
-
-
-
-
-
AB60-PT
660
-.75
8
3780
2990
2420
2000
1830
1680
1430
_
1240
_
_
1.3
1.6
20
2.5
2.7
2.9
3.4
-
4.0
-
-
-
A1400-PT
1400
IliO
10
-
-
5000
4723
4321
3968
3381
3135
2915
2718
2540
2378
-
-
2.5
31
34
37
4.3
4.6
5.0
54
57
6.1
A1700-PT
1700
150
12
-
-
5000
4723
4321
3968
3361
3135
2915
2718
2540
2378
-
-
3.1
37
40
4.4
5.2
5.6
6.0
6.4
6.9
7. j
Manufacturer: OPI INC. (GIST) Triplex
Model
Rated Rated Stroke
S.P.M. Length
Liner Sue (in)
IK 2 2*
3 354 4
454 5 5Vi
6 654 7 7*
OPI 1600
160 230 6
- - -
1096
1.0
866
12
_
OPI 300
200 400 6
5650 3183 2031
0.1 0.2 0.4
1415 103d 796
0.5 0.7 1.0
_ _
_
OPI 3500
350 120 8
-
-
2610 2114 1747
1.6 2.0 2 5
1469 -
3.0 -
OPI 7000
OPI 700HDL
OPI 7000L
700 150 8
_
_
4089 3312 2737
1.6 2.0 2.5
2300 1960 1690 -
3.0 3.4 40 -
OPI 1000DL
1000 132 10
_
_
4585 3790
2.6 3.0
3184 2713 2340 203*
3.7 4.3 50 5.7
Manufecturer
:SKYTOPBREWSTER -
Duplex
Model
Rated
Rated
Stroke
Liner Size (in)
I.H.P.
S.P.M.
Length
4K
5
554
554
5K
6 __]
6%
654
6*
7
B550F
550
70
14
2997
2678
2404
2171
1969
1796
1648
1515
1363
1293
3.8
4.3
4.7
5.3
5.8
6.4
6.9
7.6
8.:1
88
B750F
750
65
16
-
3642
3255
2920
2645
2400
2185
2010
185P
1710
-
4.6
5.2
5.8
6.4
7.00
7.7
8.4
E.t
9.9
B1000F
1000
60
18
-
-
-
3885
3510
3167
28S4
2648
2425
2241
6.2
6.9
7.7
84
9.2
IPO
10.8
Manufacturer
: SKYTOP-BREWSTER -
Triplex
Model
Rated
Rated
Stroke
Liner Size (in)
I.H.P.
S.P.M.
Length
4
454
5
554
6
654
7
B1300T
1300
120
12
5000
5000
6000
4558
3790
3234
2785
2.0
2.5
3.1
3.7
4.4
5.2
6.0
B1600T
1600
120
12
5000
5000
5000
5000
4664
3980
3427
2.0
2.5
3.1
3.7
4.4
5.2
6.0
NOTE' Top Value: Diidiine Preiture
Bottom Value: Discharge Volume
-------
Pump Discharge Pressure (psi)
Pump Discharge Volume (gal./stroke)
Manufacture
r: WHELAND-
Duplex
Model
Max
Max
Stroke
Rod
Liner Size (in)
I.H.P.
S.P.M
Length
Size
5
5-1/2
5-3/4
6
6-1/4
6-1/2
6-3/4
7
7-1/4
7-1/2
7-3/4
HP 8000
343
70
12
2
1220
995
-
826
-
698
644
597
555
-
3.7
4.6
-
5 5
-
6.6
7.1
7.7
8.2
-
:
HP 14000
574
65
14
2-1/4
-
1558
-
1290
-
1035
1000
927
862
802
... ^
-
5.3
-
6.4
-
7 6
82
88
9.5
10 2
-
HP 16000
600
65
16
2-1/2
-
2337
-
1921
1751
1608
1480
1387
1268
1178
1098
-
5.9
-
7 1
7.8
8.5
9.2
100
108
11.6
12.4
HP 18000
750
60
18
2 3/4
-
2700
-
2314
2113
1937
1782
1648
1526
1419
1322
-
6.5
-
7.9
86
9.4
10.2
11.1
11.9
128
13 8
HP8000A
200
60
12
2
-
995
-
826
-
698
644
597
555
-
'1
-
4.6
-
5.5
-
6.6
7 1
7 7
8.2
-
-
HP 14000A
353
60
14
2 1/4
-
1627
1476
1346
1233
1135
1047
970
900
838
-
5 3
5.8
6.4
7.0
7.6
82
3.8
9.5
10.2
"
Manufacturer: WILSON Duplex
Model
Max
Max
Stroke
Rod
Liner Size (in)
I.H.P.
S.P.M.
Length
Size
4
4-12
5
5-1/2
6
6-1/2
7
7-1/2
8
600
600
95
14
2-1/4
3000
2500
2050
1700
1400
1200
_
_
-
600H
26
34
4.3
5.3
6.4
7.6
-
-
-
900
900
80
16
2-3/4
-
-
3300
2730
2300
1960
_
-
-
-
-
4.6
5.8
7.0
8.4
-
-
-
1250
1300
78
18
2-3/4
-
_
4250
3500
2490
2500'
2160
-
-
-
-
5.2
6.5
7.9
9.4
11.1
-
-
Giant
595
95
14
2 1/4
3000
2500
2050
1700
1400
1200
1050
900
-
2.6
3.4
4.3
5.3
6.4
7.6
8.8
10.2
-
Titan
1237
75
18
2-3/4
_
4000
3500
2940
2500
2160
1880
1660
-
5.2
6.5
7.9
9.4
11.1
12.8
14.7
Top Value: Discharge Pressure
Bottom Value: Discharge Volume
-------
APPENDIX D
SAMPLING CONTAINERS, PRESERVATIVES
AND ANALYTICAL PARAMETER
-------
RECOMMENDED CONTAINERS, PRESERVATIVES, AND HOLDING TIMES FOR
ANALYTICAL PARAMETERS*
Measurement
Priority
Pollutants
Asbestos
Volative
Organics
Physical Properties
Color
Conductance
Hardness
Odor
PH
Residue
Filterable
Non-
Filterable
Total
Volatile
Settleable Matter
Temperature
Turbidity
Metals
Dissolved
Suspended
Total
Vol
Req.
(ml)
Container"' Preservative
2% gal. G
Cool, 4ฐC
Holding
Timew
24 hours
11. P None
100 ml. G(serum vile) Cool, 4ฐC
24 hours
50 P.G Cool, 4*C 24 Hrs.
100 P.G Cool, 4*C 24 Hrs.'4'
100 P,G Cool, 4*C 6 Mos..(,)
HNOj to pH<2
200 G only Cool, 4*C 24 Hrs.
25 P,G Det. on site 6 Hrs.
100 P,G Cool. 4*C 7 Days
100 P,G Cool, 4"C 7 Days
100 P.G Cool, 4*C 7 Days
100 P,G Cool. 4*C 7 Days
1000 P.G None Req. 24 Hrs.
1000 P,G Det. on site No Holding
100 P.G Cool, 4*C 7 Days
200 P.G Filter on site 6 Mos."1
HNOj to pH<2
200 Filter on site 6 Mos.
100 P.G HNOj to pH<2 6 Mos.'"
-------
Measurement
Vol.
Req.
(ml)
Container{I> Preservative
Holding
Time(,)
Mercury
Dissolved
100
P.G
Total
100
Inorganics. Non-Metallics
Acidity
Alkalinity
Bromide
Chloride
Chlorine
Cyanides
Fluoride
Iodide
Nitrogen
Ammonia
Kjeldahl, Total
Nitrate
Nitrite
100
100
100
50
200
500
100
50
P.G
P.G
P.G
P.G
P.G
P.G
P.G
300 P.G
100 P.G
400 P.G
500 P,G
Nitrate plus Nitrite 100 P.G
P.G
P.G
Filter on site
HNO, to pH<2
HNOj to pH<2.
None Req
Cool. 4*C
Cool. 4*C
None Req.
Det. on site
Cool, 4*C
NaOH to PH 12
None Req.
Cool. 4"C
Cool.4*C
H2S04 to pH<2
Cool. 4"C
H2S04 to pH<2
Cool, 4*C
H,S04 to pH<2
Cool. 4*C
Cool, 4*C
38 Days
(Glass)
13 Days
(Hard
Plastic)
38 Days
(Glass)
13 Days
(Hard
Plastic)
24 Hrs.
24 Hrs.
24 Hrs.
7 Days
No Holding
24 Hrs.
7 Days
24 Hrs.
24 Hrs.
24 Hrs."'
24 Hre.
ซ>
24 Hrs.
48 Hrs.
-------
Measurement
Vol.
Req.
(ml)
Container Preservative
Holding
Time(,)
Dissolved Oxygen
Probe
Winkler
Phosphorus
Ortho-
phosphate,
Dissolved
Hydrolyzable
Total
Total,
Dissolved
Silica
Sulfate
Sulfide
Sulfite
Organics
BOD
COD
Oil & Grease
Organic carbon
Phenolics
MB AS
300
300
50
50
50
50
50
50
500
50
1000
50
1000
25
500
250
G only
G only
P.G
P.G
P.G
P.G
P only
P.G
P.G
P.G
P.G
P.G
G only
P.G
G only
P.G
DeL on site
Fix on site
Filter on site
Cool, 4"C
Cool, 4*C
H2S04 to pH<2
Cool. 4ฐC
HjS04 to pH<2
Filter on site
Cool. 4*C
HjS04 to pH <2
Cool, 4ฐC
Cool, 4*C
2 ml zinc
acetate
Det. on site
Cool, 4*C
H,S04 to pH <2
Cool. 4*C
H2S04 or HC1 to pH<2
Cool, 4*C
H2S04 or HC1 to pH<2
Cool, 4*C
HjPOซ to pH <4
I.0 g CuSOซ/l
No Holding
4-8 Hours
24 Hrs.
24 Hrs.(i>
24 Hrs.w
24 Hrs.
<ซ
Cool, 4*C
7 Days
7 Days
24 Hrs.
No Holding
24 Hrs.
7 Days<6)
24 Hrs.
24 Hrs.
24 Hrs.
24 Hrs.
-------
Vol.
Req.
Measurement (ml) Container0' Preservative
Holding
Timew
NTA
50 P.G
Cool, 4*C
24 Hrc.
1. More specific instructions for preservation and sampling are found with each procedure as
detailed in this manual. A general discussion on sampling water and industrial wastewater may
be found in ASTM, Part 31, p. 72-82 (1976) Method D-3370.
2. Plastic (P) or Glass (G). For metals, polyethylene with a polypropylene cap (no liner) is
preferred.
3. It should be pointed out that holding times listed above are recommended for properly
preserved samples based on currently available data. It is recognized that for some sample
types, extension of these times may be possible while for other types, these times may be too
long. Where shipping regulations prevent the use of the proper preservation technique or the
holding time is exceeded, such as the case of a 24-hour composite, the final reported data for
these samples should indicate the specific variance
4. If the sample is stabilized by cooling, it should be warmed to 25ฐC for reading, or temperature
correction made and results reporled at 25ฐC.
5. Where HNOj cannot be used because of shipping restrictions, the sample may be initially
preserved by icing and immediately shipped to the laboratory. Upon receipt in the laboratory,
the sample must be acidified to a pH <2 with HNOj (normally 3 ml 1:1 HNOj/liter is
sufficient). At the time of analysis, the sample container should be thoroughly rinsed with 1:1
HNOj and the washings added to the sample (volume correction may be required).
6. Data obtained from National Enforcement Investigations Center-Denver, Colorado, support a
four-week holding time for this parameter in Sewerage Systems. (SIC 4952).
~Adapted from the EPA "Recommendation for Sampling and Preservation of
Samples According to Measurement"
-------
SAMPLING POINTS FOR WASTE CONTAINERS
Container
Drum, bung on one end*
Drum, bung on side*
Barrel, fiberdrum,
buckets, sacks, bags
Vacuum truck and
similar containers
Pond, pit, or lagoon
Waste pile
Storage tank
Soil
Sampling Point
Withdraw sample through the bung opening.
Lay drum on side with bung up. Withdraw sample
through the bung opening.
Withdraw samples through the top of barrel, fiber-
drums, buckets, and similar containers. Withdraw
samples through fill openings of bags and sacks.
Sample through the center of the containers and to
different points diagonally opposite the point of
entry.
Withdraw sample through open hatch,
other hatches.
Sample all
Divide surface area into an imaginary grid.ฎ Take
three samples if possible; one at the surface, one at
mid-depth, and one near the bottom. Repeat the
sampling at each grid over the entire pond or site.
Withdraw samples through at least three different
points near the top of the pile to points diagonally
opposite the point of entry.
Sample from the top through the sampling hole.
Withdraw three samples; one at the top, one at mid-
depth, and one near the bottom.
Divide the surface area into an imaginary grid.ฎ
Sample each grid.
* THE EPA STATES THAT DRUMS ARE NOT TO BE OPENED EXCEPT BY
REMOTE DEVICES.
a The number of grids is determined by the desired number of samples to be
collected which when combined should give a representative sample of the
wastes.
------- |