EPA R2-73 280a
August 1973 Environmental Protection Technology Series
Petroleum Systems Reliabilty Analysis
Volume I - Engineering Report
Office of Research and Monitoring
U.S. Environmental Protection Agency
Washington. D.C. 20460
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and
Monitoring, Environmental Protection Agency, iiave
been grouped into five series. These five broad
categories were established to facilitate further
development and application of environmental
technology. Elimination of traditional grouping
was consciously planned to foster technology
transfer and a maximum interface in related
fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL
PROTECTION TECHNOLOGY series. This series
describes research performed to develop and
demonstrate instrumentation, equipment . and
methodology to repair or prevent environmental
degradation from point and non-point sources of
pollution. This work provides the new or improved
technology required for the control and treatment
of pollution sources to meet environmental quality
standards.
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EPA-R2-73-280a
August 1973
PETROLEUM SYSTEMS RELIABILITY ANALYSIS
A Program for Prevention of Oil Spills Using an Engineering Approach
to a Study of Offshore and Onshore Crude Oil Petroleum Systems
VOLUME I - ENGINEERING REPORT
Prepared by
J. E. Ritchie, Jr.
F. J. Allen, Jr. (Consultant), R. M. Feltes,
R. Q. Foote, W. A. Shortt, E. B. Bell and J. Winn
Project #15080 HOC
Contract #68-01-0121
Project Officer
Henry D. Van Cleave
Division of Oil and Hazardous Materials
Office of Water Program Operations
Environmental Protection Agency
Washington, D. C.
Prepared for
Office of Research and Monitoring
and
Office of Water Program Operations
U. S. Environmental Protection Agency
Washington, D. C. 20460
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EPA Review Notice
This report-lias been reviewed by the Office of Water
Programs Operations, EPA, and approved for publica-
tion. Approval does not signify that the contents nec-
essarily reflect the views and policies of the Environ-
mental Protection.Agency, nor does mention of trade
names or commercial products constitute endorsement
or recommendation for use.
11
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FOREWORD
The 1970 and 1972 amendments to the Federal Water Pollution Control Act
required that the President issue regulations establishing procedures,
methods and equipment and other requirements for equipment to prevent
discharges of oil into the navigable waters of the United States. The
responsibility of issuing these regulations for nontransportation-related
facilities was delegated to the Environmental Protection Agency.
An examination of reported oil spills was begun by EPA in order to draft
workable and effective regulations. There was a great deal of data on
oil spills, especially from production and transportation facilities,
which indicated a similarity of spills from certain classes of facilities.
However, these data were widely scattered among a number of different
governmental sources, and the individual agency sources had varying elements
of information within their spill reports, depending upon management needs
and emphasis.
It was apparent that a careful collection and examination of available spill
data, and a technical analysis of spill patterns and equipment failure was
needed. This need generated a contract which in turn produced this study
entitled, "Petroleum Systems Reliability Analysis."
The analysis examined in detail the causes of polluting spills from selected
petroleum systems (onshore and offshore crude oil drilling, production, and
gathering/distribution systems). The study included the compilation of
data from Federal, State and industrial spill reports, a field survey of
the various types of facilities, and an analysis of spill-causing failures.
EPA prevention regulations presently under consideration envision the
preparation of prevention plans (called Spill Prevention, Control and
Countermeasure Plans, or SPCC Plans) by facilities to prevent discharges
of oil. The analysis contained in this study should be ^valuable in pre-
paring and evaluating these plans. The results will indicate operating
procedures and equipment which are spill prone, and failures which can be
anticipated and, in many cases, prevented. In addition, the application of
preventive maintenance, operating procedures and, in some cases, equipment
which have been used effectively by the industry to successfully combat
failures are discussed.
This study has been prepared in two volumes; Volume I contains the
Engineering Report, and Volume II contains Appendices.
The Engineering Report presents, in four sections, the findings resulting
from the study. The conclusions and recommendations are presented in
Sections 1 and 2, respectively. Section 3 describes a systems approach to
spill prevention, and documents application of the approach to Drilling,
Production, and Gathering/distribution Systems. Section 4 presents a
iii
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spill prevention program for crude oil systems, based on a review of
petroleum facility SPOC plans and using techniques developed during the
study. The Engineering Report also includes a bibliography and glossary.
Volune II contains eleven appendices that provide the detailed infor-
aation upon which the report is based. Relationships between appendices
are shown by the following diagram.
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APPENDIX I
MGULATMN WVIWS
Thomas J. Char1ton, P.E.
Division of Oil $ Hazardous Materials
Office of Water Programs Operations
Environmental Protection Agency
Washington, D.C. 20460
iv
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ABSTRACT
EPA's oil spill prevention program has been advanced with methodology for
evaluating Drilling, Production, and Gathering/Distribution Systems plans to prevent
spillage of crude oil. The program responds to the Federal Water Pollution Control
Act, as amended in 1972. The methodology has been designed for use by EPA Regional
personnel, and to minimize requirements for the special skills of a petroleum engineer
or systems analyst. The scope of the study included offshore and onshore facilities in
the Gulf of Mexico, Louisiana, Texas, California, and Alaska. Field surveys providing
firsthand observation of selected facilities are documented in the report. Approximately
15,000 spill records were collected from 20 data sources covering major oil-producing
States. Half of these records were identified as being useful to the study and are included
in the report.
The report presents, for use by EPA Regional O&HM personnel, a set of checklists
which identify system points of spill vulnerability, and spill prevention guidelines appli-
cable to these points. Application of these guidelines to a specific facility will require
judgment and allow innovative spill prevention measures.
This report was submitted by Computer Sciences Corporation in fulfillment of
Project Number 1508HOC, Contract 68-01-0121, under the sponsorship of the EPA
Office of Water Programs Operations.
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MASTER TABLE OF CONTENTS
VOLUME I - ENGINEERING REPORT
Section
1 Conclusions
2 Recommendations
3 Introduction - Systems Approach to a Spill Prevention Program
4 A Spill Prevention Program for Crude Oil Systems
BL Bibliography
GL Glossary
VOLUME II - APPENDICES
Appendix
A Field Survey Trips
B Subsystem Descriptions
C Source Data Bank Description
D Tabulation of Oil Spill Record Data
E Presentation of Spill Data
F Failure Modes and Effects Analysis (FMEA)
G Considerations of Hazardous Natural Environment on Petroleum Systems
H Corrosion of Petroleum System Equipment
I Regulation Reviews Summary Reports
J Safety Shutdown Devices
K Data Code Book
vii
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TABLE OF CONTENTS
Section 1 - Conclusions. 1-1
Section 2 - Recommendations 2-1
Section 3 - Introduction - Systems Approach to a Spill Prevention Program 3-1
3.1 Summary 3-1
3.2 Definition and Limitations of the Problem . . . . . . 3-1
3.3 The Systems Approach .,.. ..... . . ... . . . . . . . . . . . 3-2
3.4 Findings Resulting from the Systems Approach. . . 3-3
3.4.1 Design 3-3
3.4.2 Natural Environment 3-4
3.4.3 Operation and Maintenance 3-4
3.4.4 Third Parly Actions or Events . . . 3-6
3.4.5 Documentation and Reporting of Spills. 3-7
Section 4 - A Spill Preventive Program for Crude Oil Systems 4-1
4.1 Program Overview 4-1
4.1.1 Summary Description 4-1
4.1. 2 Rationale . 4-1
4.1.3 Application . . 4-3
4.2 System Definition 4-5
4.2.1 Boundary and Interface Considerations ,;. . 4-5
4.2.2 Drilling System 4-9
4.2.3 Production System 4-10
4.2.4 Gathering/Distribution (Q/D) System . . .... ....;, . i ........ 4-13
4.3 Summary of Petroleum System Spill Event Data 4-14
4.3.1 Purpose and Scope . . ........ 1 4-14
4.3.2 Production System Summary Spill Data . ..>.... . 4-15
4.3.3 Gathering/Distribution System Summary Spill Data 4-17
4.4 Spill Vulnerability Checklists ....'. 4-18
4.4.1 Introductory Summary . , . .,. . . 4-18
4.4.2 Production System Checklists 4-20
4.4.3 Gathering/Distribution System Checklists . .' 4-20
4.5 Spill Prevention Guidelines 4-21
4.5.1 Overview 4 4-21
4.5.2 Drilling Plans and Operations Spill Prevention Guidelines 4-24
4.5.3 Production System Spill Prevention Guidelines 4-24
4.5.4 Gathering/Distribution System Spill Prevention Guidelines 4-25
viii
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TABLE OF CONTENTS (Cont'd)
Bibliography BL-1
Glossary . . GL-1
ix
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LIST OF ILLUSTRATIONS
4-1 Operational Boundaries for the Various Crude Oil Handling Phases. ... 4-8
4-2 Subsystem Breakdown for Drilling, Production, and Gathering/
Distribution Systems ...- . 4-11
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LIST OF TABLES
Table
3-1 Supplementary Design Review Guidelines 3-5
4-1 Elements of a Spill Prevention Program 4-2
4-2 Facility Documentation for SPCC Plan Review 4-4
4-3 Recommended SPCC Plan Review Procedure 4-6
4-4 Total Spill Events by Systenvand Shore Code 4-15
4-5 Spill Events for Offshore Production Systems by Subsystem and Spill
Category .-....' 4-16
4-6 Spill Events for Onshore Production Systems by Subsystem and Spill
Category 4-16
4-7 Spill Events for Offshore Gathering/Distribution Systems by Subsystem
and Spill Category 4-17
4-8 Spill Events for Onshore Gathering/Distribution Systems by Subsystem
and Spill Category 4-18
4-9 Spill Criticality Rating Guide 4-19
4-10 Production System Spill Vulnerability Checklist, Well Subsystem .... 4-26
4-11 Production System Spill Vulnerability Checklist, Wellhead Subsystem. . 4-26
4-12 Production System Spill Vulnerability Checklist, Gathering Sub-
system 4-27
4-13 Production System Spill Vulnerability Checklist, Separation Sub-
system 4-28
4-14 Production System Spill Vulnerability Checklist, Treater Subsystem . . 4-29
4-15 Production System Spill Vulnerability Checklist, Local Storage Sub-
system 4-30
4-16 Production System Spill Vulnerability Checklist, Custody Transfer
Subsystem 4-31
4-17 Production System Spill Vulnerability Checklist, Safety Subsystem . . . 4-31
4-18 Production System Spill Vulnerability Checklist, Water Disposal
Subsystem 4-31
4-19 Gathering/Distribution System Spill Vulnerability Checklist, Pipeline
Subsystem 4-32
4-20 Gathering/Distribution System Spill Vulnerability Checklist, Storage
Subsystem 4-33
4-21 Gathering/Distribution System Spill Vulnerability Checklist, Pump
Station Subsystem 4-33
4-22 Gathering/Distribution System Spill Vulnerability Checklist,
Gathering Subsystem 4-33
4-23 Blowout Prevention Guidelines for Evaluation of Drilling Plans and
Operations 4-34
4-24 Production System Spill Prevention Guidelines, Gathering Subsystem . . 4-38
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LIST OF TABLES (Cont'd)
Table
4-25 Production System Spill Prevention Guidelines, Treater Subsystem . . . 4-41
4-26 Production System Spill Prevention Guidelines, Local Storage Sub-
system 4-44
4-27 Production System Spill Prevention Guidelines, Separation Subsystems . 4-46
4-28 Production System Spill Prevention Guidelines, Safety Subsystem .... 4-49
4-29 Gathering/Distribution System Spill Prevention Guidelines, Pipeline
and Gathering Subsystems 4-51
4-30 Gathering/Distribution System Spill Prevention Guidelines, Storage
Subsystem 4-53
xii
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SECTION 1
CONCLUSIONS
This study has resulted in the development of methodology to be applied by EPA Regional
personnel in the review of Spill Prevention Control and Countermeasures (SPCC) plans.
The methodology is presented in Section 4. Significant findings resulting from the study
are summarized in this section.
Conclusion 1; The spill vulnerability checklists developed through this study are
important to the spill prevention program since they provide a basis for determining
if all spill vulnerability points have been identified in facility SPCC plans*
1. Spillage from Drilling Systems is concerned with one major eventblowout
and its significant causative factors. Since they occur infrequently, data are
insufficient to establish spill vulnerable points. However, when they do occur,
they are often catastrophic, and extensive blowout prevention guidelines are
provided.
2. Spillage from Production Systems usually occurs as a result of faulty equipment
or operations. Vulnerable points include wellhead chokes, flowline pipe,
separator and treater dump valves, high liquid level sensors and safety pres-
sure relief devices, local storage tanks, and sump systems for offshore plat-
forms.
3. Spillage from Gathering/Distribution Systems is usually associated with
corrosion of line pipe. However, relatively few incidents of either pipe
failure or corrosion have been reported for offshore facilities. This is due
largely to the relatively young age of offshore facilities, and to strong cor-
rosion prevention measures taken by offshore facility operators.
Checklists providing detailed findings of spill vulnerability points in the Production and
Gathering/Distribution Systems are given in Paragraph 4.4.
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Conclusion 2; The spill prevention guidelines developed in this study are important to
the spill prevention program since they provide a basis for determining if reasonable
and effective spill prevention measures have been applied in facility SPCC plans.
1. Methods are provided for reviewing facility SPCC plans. They are designed
for a reviewer with technical training, but do not require that he be an engi-
neer or systems analyst. The procedures compare the features of each
facility to a set of spill vulnerability checklists and spill prevention guidelines.
The comparison provides independent criteria to identify effective preventive
measures. As a result, review of the SPCC plan using these criteria evaluates
whether the planned preventive measures effectively cover all facility spill
vulnerability points. The review provides for discussion of apparent short-
comings with facility personnel prior to a decision on SPCC plan modification
or certification.
The methods, procedures, and spill prevention guidelines are given in Section 4.
Conclusion 3; A systems approach using reliability engineering principles is effective
for developing a methodology of SPCC plan review. Application of this approach resulted
in the development of the methodology detailed in Section 4, and provided the following
spill prevention program support capability:
1. Development of petroleum system definitions, boundaries, interfaces, and
functions which permit the study and comparison of specific facilities to
other facilities on a consistent basis, given the differences between facilities.
2, Design of a structured data system which has been used for collection, com-
puter processing, and analysis of spill data, given wide variations in data
sources and content.
3. Use of failure modes and effects analysis (FMEA) techniques to establish
cause/effect/corrective action relationships for preventing spills from
petroleum systems.
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4. Recognition of additional general system design considerations for prevention
of spills, and development of design review guidelines for their implementa-
tion.
Discussion of the systems approach and additional detailed findings is presented in
Section 3.
Conclusion 4; Spill event data from present spill reporting systems do not provide an
effective basis for spill prevention program evaluation and direction, since they have
severe deficiencies, both technically and administratively. Reporting and analysis of
crude oil spill events should identify the needs and problems of a spill prevention
program. These data should also provide a measure of the effectiveness of implemented
prevention measures to guide the direction of future prevention activity. To accomplish
these essential functions, spill reporting must:
1. Have technical information (elements) to support analysis
2. Possess a structure that will allow analysis (probably computer-aided)
of large volumes of data
3. Be applied uniformly within a system of standard and nonduplicative
reporting and analysis procedures.
Existing data sources exhibit wide variation in format, technical content, systems
covered, maintenance and use of data, and reporting discipline, as shown in Appendices
C and D. As a result, existing spill data are deficient from the standpoint of providing
effective evaluation and direction for a spill prevention program.
Conclusion 5; The field survey, through oil company cooperation during this study,
disclosed that owners/operators are already implementing measures which will result
in spill prevention. Some of these measures include:
1. Formal training schools for drilling personnel.
2. Improved drilling technology, instrumentation, and equipment.
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3. Surface-controlled subsurface safety devices.
4. Safety valve test and evaluation programs.
5. Inspection and preventive maintenance programs.
6. Improved structural design and corrosion prevention for pipelines and
platforms.
Detailed findings of the field survey are provided in Appendix A.
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SECTION 2
RECOMMENDATIONS
The recommendations in this section were developed from the Petroleum Systems
Reliability Analysis for application to the spill prevention program:
Recommendation 1; The spill vulnerability checklists and spill prevention guidelines
identified in Section 4 should be used and augmented by industry and government for the
improvement of petroleum systems and the prevention of spills.
Recommendation 2; The method for evaluating petroleum facility spill prevention
measures and plans should be implemented on a trial basis by EPA Regional personnel,
with provisions for improving and refining as experience is gained. An initial program
of familiarization or training of personnel in this method should be considered.
Recommendation 3; Further application of systems engineering principles should be
considered. Possible areas of application include development of a handbook of spill
prevention techniques and an analysis of facilities and systems for handling refined
petroleum products. Spill problems existing in other areas of the petroleum industry
should be examined using the approach developed and applied in this study.
Recommendation 4; Studies leading to the development and coordination of a specification
and preliminary design for a unified spill reporting and analysis system should be
initiated at the earliest practicable date. Appendix K presents a reasonable point of
departure for developing a spill reporting and analysis system capable of providing
effective spill prevention program evaluation and direction.
Detailed recommendations for prevention of spills from systems are included in Section
3 and Paragraph 4.5.
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SECTIONS
INTRODUCTION - SYSTEMS APPROACH TO A SPILL PREVENTION PROGRAM
3.1 SUMMARY
A systems approach using reliability engineering principles has been used in the develop-
ment of a spill prevention program. The approach not only resulted in the spill prevention
program elements described in this report but provided additional findings, discussed
later in this section, also considered important to spill prevention. This approach is
reflected in the spill vulnerability checklists and spill prevention guidelines given in
Section 4. The remainder of this section describes how the approach was applied to petro-
leum systems and presents findings which may be effective in further developing the spill
prevention program.
3. 2 DEFINITION AND LIMITATIONS OF THE PROBLEM
Spillage of crude oil or condensate is considered in three petroleum systems: Drilling,
Production (includes local storage), and Gathering/Distribution (includes storage). Whether
any particular spill event is a pollution event is beyond the scope of this study.
The method of study, applying reliability engineering principles, asks the question:
"Given a system which is performing within its specifications, what is the probability that
it will continue to function this way, without failing, for some defined period of time?"
In reviewing the problem, it was concluded that the development of meaningful numerical
probability values would add little to this study. From a practical standpoint, this study
asks: "Given that a system fails more often than desired, what can be done, and where
should the effort be concentrated to reduce the number of spill vulnerable failures to an
acceptable level?" Answering this question requires knowing:
What failed - what are the most frequent problems?
How did it fail - what are the most frequent modes of failure ?
Why did it fail - what are the most frequent causes of each failure mode?
3-1
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The principles of a reliability product improvement program were employed to answer
these questions using spillage of crude oil or condensate as the definition of failure and to
guide the systems approach described in the following paragraph.
3.3 THE SYSTEMS APPROACH
Under the systems approach, the following tasks provided exposure to a wide variety of
existing facilities and significant crude oil spillage problems:
1. Field Surveys - Observe a number of facilities in operation, hold discussions
with operator personnel, and experience some of the local operating and
environmental conditions. Summaries of these surveys are contained in
in Appendix A.
2. Detailed System Descriptions and Definitions - Aided by Tasks 1 and 6, define
system boundaries, interfaces, and functions. The results are documented in
Paragraph 4.2 and Appendix B.
3. Spill Event Data Collection Planning - Develop a plan for obtaining oil spill
data on existing facilities, considering what data to seek, where to seek it,
and what data elements are needed to support the analysis. The resulting
data requirements are documented in Appendix K.
4. Data Collection and Processing - Investigate data sources, identify and collect
oil spill data classified according to system function and operation, and use
computer processing to organize and sort the data. A description of these data
sources is given in Appendix C; tabulations of the source data and the data used
for analyses are presented in Appendix D.
5. Spill Analyses - Examine the data for similarities, differences, and trends
which identify possible spill problem areas. The analysis is documented in
Appendix E.
6. Failure Modes and Effects Analysis (FMEA) - Using observed and theoretical
information, provide a framework which will allow the study to compare any
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specific facility to other facilities on a consistent basis, given that each
facility has its own tfpersonality." The results permitted development of the
guidelines in Paragraph 4.5. The development of the FMEA for petroleum
systems uses fault tree analysis (FTA) techniques and is documented in
Appendix F.
3.4 FINDINGS RESULTING FROM THE SYSTEMS APPROACH
Through this systems approach, two groups of findings have been developed:
1. Findings regarding petroleum systems which have been presented by the
checklists and guidelines for evaluation of facility spill prevention measures
given in Paragraphs 4.4 and 4.5.
2. Findings of a more general nature which may be useful in developing spill
prevention programs; these are discussed in the remaining paragraphs of
this section.
3.4.1 Design
Few design recommendations were made, since the operator is best qualified to determine
the facility design best suited to local conditions and requirements of his operation. How-
ever, the following observations and recommendations have general utility:
1. The reaction time of a safety shut-in system, operating according to design,
is sufficiently long from sensor signal to completion of shut-in to allow
significant spillage to occur (see Paragraph J.4, Appendix J).
2. Spills involving pressure vessels have more frequently been attributed to
mounted accessory equipment than to the pressure vessels themselves.
Vessel design is controlled by strict specifications and standards while
accessory equipment (e. g., valves, gages, and other fittings and instrumenta-
tion) are not similarly controlled by either industry or individual operators.
3. Facility and system secondary containment during abnormal operations such
as malfunction or heavy rainfall was inadequate in some instances. This
observation is applicable to secondary containment, both offshore (including
platform sumps) and onshore (including tank firewalls).
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Discovery and correction of these conditions could be done by the owner/operator during
his design review of either new or existing facilities. Table 3-1 presents supplementary
design review guidelines recommended for detecting and considering this type of problem.
3.4.2 Natural Environment
Elements of the local natural environment are major spill prevention considerations in
the design and operation of a facility. They include hazards from storms, ice, tsunamis,
and earthquakes, and have resulted in considerable structural design analysis, particularly
for offshore platforms. This problem was not studied since only a few of the 8473 spill
events were attributed to environmental hazards. However, a potential for future signifi-
cant spillage cannot be overlooked. Appendix G discusses these hazards and identifies
areas in the United States where each has been prominent.
Additional elements of the natural environment concern corrosion, the largest single
cause of oil spills exhibited by the data. Appendix H presents a summary discussion of
the types of corrosion and areas in the United States which exhibit each type. Consider-
able attention has been given to the prevention of corrosion, particularly for offshore
pipelines and platforms as observed during the field surveys. In addition, the Department
of Transportation's Office of Pipeline Safety has instituted strong corrosion prevention
measures applicable to carrier trunk lines as documented in Title 49, Code of Federal
Regulations, Chapter 1, Part 195. These regulations also provide for detailed accident
reporting*
As part of the spill prevention program, selective application of the corrosion prevention
measures identified in 49 CFR Part 195 should be encouraged for gathering subsystems
(in both Production and Gathering/Distribution Systems) which develop a history of spill
events affecting navigable water.
3.4.3 Operation and Maintenance
Operation and maintenance (O/M) personnel errors must be considered since they result
in a significant number of spill events. Personnel error is considered the greatest cause
for loss of well control during drilling operations. In Production and Gathering/Distribu-
tion Systems, the failure to open or close a manual valve is a common cause of spillage.
Two reasons have been cited:
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Table 3-1. Supplementary Design Review Guidelines
1. Verify that the system or facility does the job during normal operations, given
that It will operate when desired and will meet design specifications.
2. Assuming normal operations, consider one specific malfunction or undesired event,
e. g., a treater salt water dump valve hangs open, the high liquid level sensing
device on a specific vessel fails to Indicate an existing high liquid level, or a hard
rain occurs.
3. Ask the question, "considering, as a minimum, flow rates, alternate paths,
capabilities, safety devices, and manning status, will the system avoid spillage
until the malfunction or undesired event no longer is present?"
4. If the answer to Step 3 is Yes, go to Step 10; otherwise, go to Step 5.
5. Can conditions leading to the occurrence of the malfunction reasonably be
avoided?
6. Can the system reasonably be altered, without jeopardizing normal operation,
to avoid spillage?
7. Can adequate secondary containment be provided, considering the expected
rate and duration of flow?
8. Can safety shutdown or alarm provisions be established with sufficiently short
reaction time to avoid, or at least limit, the spillage to minor quantities, given
the expected spill flow rate? (See Appendix J.)
9. Must strong contingency plans be Invoked ? (See Appendix L)
10. Repeat Steps 3 through 9 for each malfunction or undesired event for which
there is a history of, or a potential for, spillage.
11. Document the supplementary review and decisions made as part of the system
description and preventive measures taken.
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1. The turnover of personnel (particularly roughnecks) results in the use of some
untrained personnel.
2. The long stretches of routine operation can result in lessening of alertness
by experienced personnel.
For Production and Gathering/Distribution Systems, increased use of written job descrip-
tions and periodic drills of nonroutine operating procedures are recommended.
For the Drilling System, continued use should be made of existing training programs
(providing both classroom and rig floor training) to update the skills of drilling personnel
in current well control technology and equipment. It is recommended that at least one
such trained individual should be available on the rig at all times.
From the maintenance standpoint, the occurrences of spillage during wireline operations
and workover, both onshore and offshore, suggest a need for written guidelines and safety
procedures covering these operations. In addition, wireline tickets (job order type forms
showing labor and parts used by a contractor during workover) should identify any abnormal
condition of downhole equipment or components and the reason (even if precautionary or
good practice) for installing any replacement parts.
Inspections and tests should be performed in accordance with written requirements and
procedures (when not obvious or requiring special skills) and substantiated with written
results.
3.4.4 Third Party Actions or Events
Spill events caused by a third party were exhibited primarily from onshore facility data
and attributed most frequently to tampering or vandalism, and damage from road or
construction machinery. (See Appendix K for specific third party events.) Occasionally,
an offshore pipeline was damaged by an anchor. As a result, consideration should be
given to increased security (including fencing) of onshore facilities and the use of locks
to secure valves in both open and closed positions.
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Road machinery damage raises several questions which must be considered on a local
level:
1. What is the condition and visibility of line marking?
2. Is there adequate public record documentation of line location and depth?
3. Are there requirements for construction contractors to examine the public
record prior to start of construction?
For offshore pipelines, consideration should be given to the depth of cover necessary to
ensure protection against a dragging anchor.
3.4.5 Documentation and Reporting of Spills
Existing systems for reporting spills to the Government exhibit a wide variation in format,
technical content, systems and spills covered, maintenance and use of data, and reporting
discipline or enforcement, as indicated in Appendices C and D. As a result, existing spill
data is seriously limited in its ability to provide analytical support to guide the direction
and to evaluate the effectiveness of a spill prevention program. Consideration should be
given to the development of an improved spill reporting system.
3-7
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SECTION 4 - A SPILL PREVENTION PROGRAM FOR ^RUDE OIL SYSTEMS
4.1 PROGRAM OVERVIEW
4.1.1 Summary Description
This section presents a method for reviewing SPCC plans of petroleum facilities to
determine if reasonable and effective spill prevention measures have been applied.
The program, starting with the EPA-developed spill prevention requirements, is defined
by five basic elements as summarized in Table 4-1. The facilities features are com-
pared to a set of spill vulnerability checklists and spill prevention guidelines. The
comparison will identify "spill-prone" points of the facility, and indicate possible spill
prevention actions which, in the reviewer's judgment, may be used as SPCC plan review
criteria. The provisions of the facility spill prevention plan should be reviewed, using
these criteria, to determine if the preventive measures taken effectively cover all
vulnerable points. Apparent shortcomings should be discussed with facility personnel
prior to a decision regarding SPCC plan acceptance.
Recognizing that each facility will have its own unique requirements, the program has
been designed to cover a wide range of facility configurations and operating conditions.
Information describing the systems and presenting the data on previous oil spills is
included to aid the review of facility features and support the use of the checklists and
guidelines. The method is designed for use by a reviewer with technical training but
does not require that he be an engineer or systems analyst.
The following paragraphs discuss the rationale for the spill prevention program and
application of the checklists and guidelines, provide summary descriptions of the
petroleum systems involved and the oil spill data used, and present the checklists and
guidelines for the spill prevention program.
4.1.2 Rationale
The following controlling principles guided the development of the spill prevention
program.
4-1
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Table 4-1. Elements of a Spill Prevention Program
1. Prepare SPCC Plan
A Spill Prevention Control and Countermeasures (SPCC) plan is
prepared by the facility owner/operator and certified by a registered
professional engineer, as required by proposed EPA regulations.
2. Review SPCC Plan
The SPCC plan and related facilities documentation is submitted
for review by EPA regional personnel, in the event the facility has
experienced one spill of 1000 gallons or more, or two spills of any
size in a 12-month interval.
a. Identify Spill Vulnerability Points
The spill vulnerability points of the facility are identified by
comparing the facility description of the SPCC plan to the
systems description and spill vulnerability checklists in this
report.
bi Determine Applicable Spill Prevention Guidelines
Spill prevention guidelines for the facility are established by
considering facility characteristics, spill history and spill
vulnerability points, and using the spill prevention guidelines
in this report.
3. Resolve Differences
Differences between the spill prevention measures of the SPCC plan
and spill prevention guidelines are resolved through discussion with
the facility owner/operator.
4. Certify and Implement SPCC Plan
The facility SPCC plan, including any necessary changes, is certified
by EPA and implemented by the responsible owner/operator.
5. Evaluate Effectivene ss
A spill reporting feedback and analysis system evaluates the effective-
ness and guides the direction of both facility spill prevention measures
and this spill prevention program.
4-2
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1. EPA requires guidelines to implement a spill prevention program for
petroleum systems. Uniform and consistent implementation is important
regardless of a facility's geographical location. EPA's need for guidelines
has resulted from provisions of Chapter 1 of Title 40, Code of Federal
Regulations, and proposed EPA regulations. The proposed regulations
would require owners and operators of facilities to prepare and certify the
SPCC plan, provide a description, and describe the spill prevention
measures to be taken for each facility. A summary description of facility
documentation to be available for SPCC plan review is given in Table 4-2.
The need is to examine the SPCC plan, determine if all spill vulnerable
points have been considered, and evaluate the effectiveness of spill preven-
tion measures given in the plan.
2. Systems engineering principles are applied to develop effective checklists
and guidelines. The systems approach uses fault tree analysis, failure
mode analysis, and provides a carefully defined description of each system
and its elements.
Existing facility characteristics and configurations are considered as
well as current state-of-the-art available for new design. The range
of present systems characteristics and configurations was determined
through a field survey which included observation of a broad range of
facilities, discussions with operations and maintenance personnel,
and review of some documentation used by facility personnel.
Oil spills which have actually occurred are considered rather than
potential spills. Information on 8473 actual spills was developed
from a number of data banks and facilities.
4.1.3 Application
The analysis is performed by comparing the facility elements, subsystem by subsystem,
to the equipments and components identified by the spill vulnerability checklists, indicating
4-3
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Table 4-2. Facility Documentation for SPCC Plan Review
1. Application for SPCC Plan Certification (Partial Summary)
a. Name and location of facility.
b. Name of owner/operator.
c. Date and year of initial operation.
d. Maximum storage or handling capacity and normal daily throughput.
e. Description, including maps, flow diagrams, and topographic maps.
2. Facility SPCC Plan (Partial Summary)
a. Spill history - description of each spill, corrective action, and plans
for preventing recurrence.
b. Prediction of direction, flow rate, and flow quantity that could be
discharged as a result of equipment failures with a reasonable
possibility of occurrence based on experience.
c. Containment or diversionary structures provided as a result of the
predictions in item b.
d. Contingency plan and written resource commitment when structures
in item c are not practicable.
e. Discussion of compliance with SPCC plan development and implementation
guidelines or State requirements when they are more stringent.
3. Special Report for Spills of 1000 Gallons or More (Partial Summary)
a. Cause of spill, including failure analysis of system/subsystem in which
failure occurred.
b. Corrective action and countermeasures taken, including repair or
replacement.
c. Additional preventive measures taken to minimize recurrence.
4-4
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which points of the specific facility being reviewed are spill prone. The facility SPCC
plan is examined to identify spill-preventive measures defined for those spill-prone
points. The reviewers should seek further information from the owner/operator of the
facility for those points identified by the checklist but not covered by spill prevention
measures. A recommended review procedure, covering program elements 2 and 3 in
Table 4-1, is given in Table 4-3.
4.2 SYSTEM DEFINITION
4.2.1 Boundary and Interface Considerations
Using the basic petroleum system configurations and applying fault tree analysis provides
the foundation for developing the spill prevention program checklists and guidelines. The
information for the system configurations and descriptions was obtained from field surveys,
technical literature, and FMEA studies. Inclusion of the system descriptions provides a
key for relating facility descriptions to the checklists and guidelines.
Functional elements required for all crude oil system operations were considered in
establishing not only the interface boundaries of the system, but also the equipment
interactions. The interface boundaries between systems were determined by the phase
of crude oil operation in effect; such as, the drilling, production or gathering/distribution.
The drilling phase boundaries define all activities and related functions between the spud-
ding of a hole and the decision to plug or complete the well. The boundaries for the
production phase encompass the entire producing life from the start of well completion
and include all functions extending through the sale of crude oil to a pipeline company at
the sales valve on a crude oil storage tank. The gathering/distribution phase boundaries
extend throughout the life of the facility and include all functions from initial transfer of
crude oil ownership at the outlet of the sales valve at the final production storage tank,
through the termination of crude oil transmission at the pipeline outlet to a marine dock
or refinery. Figure 4-1 shows these boundary definitions. Within these system definitions
and function boundaries, the various system functions and subfunctions are described in
the following paragraphs.
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Table 4-3. Recommended SPCC Plan Review Procedure
Program Element 2 - Review SPCC Plan
Step 1 - Identify facility systems, subsystems, and equipment elements in terms
of the systems descriptions and block diagrams in Paragraph 4.2. Note
any apparent omissions of any subsystems.
Step 2 - Identify spill vulnerability points defined in the facility documentation in
terms of the systems descriptions and block diagrams in Paragraph 4.2.
Step 3 - Identify facility conditions which, in the reviewer's judgment, would help
determine a reasonable choice of spill prevention measures. Also, con-
sider the effect of the extremes of local climate and any other local condi-
tions which would affect spill prevention measures. Topographic and
other maps, storage capacity, throughput, flow diagrams, and oil spill
history descriptions, should be used in identifying conditions to enhance
the re viewer's Judgment.
Step 4 - Identify and list spill prevention measures defined in the SPCC plan doc-
umentation. Identify the facility elements to which each prevention
measure is applied. Note any omissions or ambiguities.
Program Element 2a - Identify Spill Vulnerability Points
Step 5 - Compare subsystem and equipment elements in step 1 to the spill vulner-
ability checklists in Paragraph 4.4, and identify the specific spill vulner-
able points for that facility. (This step develops review criteria for the
facility spill vulnerable points.)
Step 6 - Compare the spill points in step 5 to the results in step 2.
Step 7 - Note any points identified in step 5 but not identified in step 2.
Program Element 2b - Determine Applicable Spill Prevention Guidelines
Step 8 - Take the spill points in step 2 one at a time, compare them to the spill
prevention guidelines in Paragraph 4. 5, and identify the spill prevention
guidelines entries for each spill point.
Step 9 - Review the guidelines list in step 8 with the information from step 3.
Delete any prevention guidelines which, in the reviewer's opinion,
clearly are not suitable for the particular facility under review. Topo-
graphic and other maps, storage capacity, throughput, flow diagrams,
and oil spill history descriptions, should be used in identifying conditions
to enhance the reviewer's judgment.
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Table 4-3. Recommended SPCC Plan Review Procedure (Cont'd)
Program Element 2b - Determine Applicable Spill Prevention Guidelines (Cont'd)
Step 10 - Establish a revised list of spill prevention guidelines based on results
of step 9. (This step develops review criteria for facility spill pre-
vention measures.)
Step 11 - For each spill point, compare entries in step 10, one at a time, with
the spill prevention measures and applicable facility elements identified
in step 4.
Step 12 - Note those spill points in step 4 that have spill prevention measures which
fall short of those identified in step 11.
Program Element 3 - Resolve Differences
Step 13 - Discuss any apparently missing subsystems or other system/elements
identified in step 1.
Step 14 - Discuss any ambiguities regarding application of spill prevention
measures identified in step 48
Step 15 - Discuss any spill vulnerable points which appear to be missing as
identified in step 7.
Step 16 - Discuss any spill points which appear to have insufficient spill preven-
tion measures as defined in step 12.
Note: Cross-referencing between the Spill Vulnerability Checklist and the
Spill Prevention Guidelines is diagrammed as follows:
VULNERABILITY CHECKLIST
(COLUMN 1 ^\
EVENT TYPE _y
f COLUMN 2 ^\
V INVOLVED J
f COLUMN 3 ^\
\^ INVOLVED ^/
(COLUMN 4 ^
CAUSE ^/
/ rnuiMMfi ) .
^ DETAIL CAUSE J
SPILL PREVENTION GUIDE
(COLU
EVENT
I
(" COLL
APPLI
COMP<
.
( rra i
V CAl
MN 1 \
( SPILL )
TYPEy
IMN2 ~X
CABLE \
ENTOR I
3NENTV
MN3 1
JSE J
4-7
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BEGIN SPUDDING
DRILLING
PHASE
DECIDE TO PLUG
OR COMPLETE
WELL COMPLETION
PRODUCTION
PHASE
PRODUCTION STORAGE TANK
SALES VALVE
FIELD PUMP TO PIPELINE
GATHERING
AND
DISTRIBUTION
PHASE
TANK FARM OUTLET TO
REFINERY OR MARINE DOCK
Figure 4-1. Operational Boundaries for the Various Crude Oil Handling Phases
The crude oil functions addressed in this report are those for the Drilling, Production,
Gathering/Distribution Systems, and Storage. Storage should be identified as either
a local storage subsystem under the Production System or a storage subsystem under
the Gathering/Distribution System. The following rationale for identification may be
used:
1. The operation and maintenance of storage elements is performed by
production personnel if the production phase of the crude oil life cycle
is involved, or by gathering/distribution personnel if the gathering/
distribution phase is involved.
2. Regulations governing storage systems are the responsibility of
production divisions in the one case and of gathering/distribution
4-8
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divisions in the other. The data available on these subsystems are
reported to the responsible governmental division.
3. The crude oil in storage facilities during production operations may vary
in quality, but that contained in gathering/distribution storage is of pipe-
lines sales quality, i. e., less than 1 percent basic sediment and water
(BS&W) content.
The initial step in developing a spill prevention program is to define the total system,
i.e., identify all hardware elements that affect the system function, as shown in
Figure 4-2. Other elements that must also be considered include:
1. Geological and environmental elements, including normal and extreme
natural phenomena.
2. Externally supplied electric, pneumatic, mechanical, or hydraulic power.
3. Externally required control signals.
4. Support elements such as maintenance, personnel, procedures, pro-
tection, and regulations (see Appendix I for a summary of applicable
Federal regulations).
4.2.2 Drilling System
The Drilling System provides the methodology and equipment required to perform explor-
atory, development, and service well drilling operations. Exploratory drilling is to
discover fields, to define the limits of a field, or to find new reservoirs in an already
productive area. Development well drilling is to develop a previously proven area.
Service well drilling is to allow injection into a formation for more efficient petroleum
recovery.
For this study, consideration of site preparation and "rig-up" are not necessary. The
Drilling System and its subsystems are shown as part of Figure 4-2. Brief descriptions
of these subsystems follow:
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Well Subsystem - hole drilled from surface to gain access to object
subsurface zone, to evaluate the zone for potential production of oil
or gas.
Power Subsystem - provides all power to operate drilling rig and
accessory equipment.
Hoisting and Rotating Subsystems - provide for running in and out of
the hole, rotating the drill string, running casing, and other required
functions.
Mud Subsystem - provides for pressure control and hole cleaning and
conditioning.
Drill String Subsystem - provides for rotating the drill bit, circulating
drilling mud, and pressure control of the well.
Blowout Preventer Subsystem - provides for closing-in and controlling
well kicks to prevent losing control of formation pressures (blowouts).
More detailed subsystem descriptions are presented in Appendix B.
4.2.3 Production System
A typical Production System (see Figure 4-2) controls the flow of well fluids to the Earth's
surface and performs surface processing of the fluids as received and disposes of waste
products. The Production System may also provide storage facilities until the processed
product is used or sold. A Production System contains its own gathering and local storage
subsystems. These are different from the comparable subsystems of the Gathering/
Distribution System and are listed separately in this report. The functions of the con-
stituent Production subsystems are:
Well Subsystem - transports fluid from producing formation to the earth's
surface.
Wellhead Subsystem - controls fluid from well to surface flowline.
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PAGE NOT
AVAILABLE
DIGITALLY
-------
Gathering Subsystem - collects and transfers fluid by flowline from
wellhead to required points in the Production System.
Separation Subsystem - separates produced liquids and gas.
Treater Subsystem - treats and conditions crude oil for emulsion and
provides for separation of produced water and oil.
Local Storage Subsystem - stores crude oil until gauging and sale of
oil occur.
Custody Transfer Subsystem - monitors BS&W, meters and transfers
crude oil to sales or pipeline.
Safety Subsystem - monitors and shuts down any or all phases of
production in an emergency, and provides visual and audible alarms
(see Appendix J for information on offshore safety shutdown devices).
Water Disposal Subsystem - disposes of produced water.
A specific Production System may not include all of these subsystems; it depends on the
content of the fluid and the various problems associated with local transportation and
conditioning of the crude oil. Equipment in a particular Production System also vary
from field to field. Specific configurations may depend on special problems or regulatory
requirements. Consequently, the detailed descriptions given in Appendix B for each sub-
system represent broad coverage with uncomplicated configurations.
4.2.4 Gathering/Distribution (G/D) System
The G/D System (see Figure 4-2) gathers crude oil from the field and distributes it to
refineries, marine docks, or other terminal areas. The functions of the constituent
G/D subsystems are:
The G/D System contains its own gathering and storage subsystems which are different
from the comparable subsystems of the Production System and are listed separately in
this report.
4-13
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Pipeline Subsystem - a manifold and pipeline distribution network through
which crude oil is transported to a refinery or other terminal facility.
Pump Station Subsystem - a method of pumping and controlling the flow
of crude oil during transfer through the G/D System.
Gathering Subsystem - a network of pipelines and associated manifolding
which gather oil from the oil fields and bring it to a central gathering
point.
Storage Subsystem - a temporary storage or holding facility for incoming
crude oil pending transshipment.
Safety Subsystem - elements that provide methods of measuring and
monitoring the G/D System to protect it from excessive or insufficient
pressures, to detect leaks and combustible gases, and to provide for
fire control and emergency shutdown.
The subsystems within the G/D System are described in Appendix B for a simple config-
uration. Appendix J provides additional information on safety shutdown devices based on
USGS data from Gulf OCS inspections.
4.3 SUMMARY OF PETROLEUM SYSTEM SPILL EVENT DATA
4.3.1 Purpose and Scope
This discussion summarizes the spill data supporting development of the spill prevention
program. The summary presents the size of the data base, the identity of the important
subdivisions of data, and the quantity of data in each of these subdivisions used in the
development of the spill vulnerability checklists.
The data comprise 8473 total spill events distributed as shown in Table 4-4.
The definitions for the systems were presented in Paragraph 4.2. The definitions for the
shore code, which are given in Appendix K, are repeated for convenience:.
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Table 4-4. Total Spill Events by System and Shore Code
System
Drilling System
Production System
Gathering/ Distribution
System
System Not Identified
Totals
Number of Spill Events
Offshore
18
935
56
10
1019
Onshore
19
3059
4367
9
7454
Totals
37
3994
4423
19
8473
Offshore means the seaward areas outside the low tide mark of the
coasts of the United States.
Onshore means the land territory of the United States inside the low
tide mark and including lakes and rivers.
The data shown in Table 4-4 for Drilling System and System Not Identified are not sum-
marized. Drilling System data, upon preliminary evaluation, were found to add little
value to the study. The 37 Drilling System spill events shown in Table 4-4 were reviewed
to determine if any significant trends were exhibited (see Tables D-19 and D-27 in
Appendix D). No significant trends were exhibited by the limited amount of data. There-
fore, no further analysis of the Drilling System spill event data will be made. The data
from the Production and G/D Systems are summarized in the following paragraphs.
4.3.2 Production System Summary Spill Data
The distribution of Production System spill event data by subsystem and spill category
is given for offshore and onshore applications in Tables 4-5 and 4-6, respectively.
The spill category definitions used for data analyses are:
Minor spill - less than 2.4 barrels (100 gallons)
Moderate spill - 2.4 to 238 barrels (100 to 10,000 gallons)
Major spill - over 238 barrels (10,000 gallons)
4-15
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Table 4-5. Spill Events for Offshore Production Systems
by Subsystem and Spill Category
Subsystem
Well
Wellhead
Gathering
Separation
Treater
Local Storage
Custody Transfer
Safety
Water Disposal
Not Identified
Totals
Number of Spill Events
Minor
4
12
64
100
63
99
7
13
4
53
419
Moderate
8
28
90
100
67
74
8
21
4
30
430
Major
0
0
4
0
0
2
1
1
0
0
8
Not
Identified
2
4
11
11
12
10
1
4
2
21
78
Totals
14
44
169
211
142
185
17
39
10
104
935
Table 4-6. Spill Events for Onshore Production Systems
by Subsystem and Spill Category
Subsystem
Well
Wellhead
Gathering
Separation
Treater
Local Storage
Custody Transfer
Safety
Water Disposal
Not Identified
Totals
Number of Spill Events
Minor
1
16
76
21
22
21
2
0
6
1
166
Moderate
15
136
1004
126
306
486
66
5
34
68
2246
Major
2
4
44
11
38
85
5
1
5
12
207
Not
Identified
36
73
72
8
27
142
0
0
1
81
440
Totals
54
229
1196
166
393
734
73
6
46
162
3059
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Tables 4-5 and 4-6 reveal that the number of reported spill events for Production Sys-
tems is much greater for onshore than for offshore applications. For this reason, as
well as to compare the experience with offshore and onshore technology, separate analyses
are made in Appendix E to support the development of the spill vulnerability checklists.
4.3.3 Gathering/Distribution System Summary Spill Data
The distribution of G/D System spill events by subsystem and spill category is given for
offshore and onshore applications in Tables 4-7 and 4-8, respectively, with terms as
defined in the preceding paragraph.
Table 4-7 reveals that little data are available to establish spill-prone points for offshore
applications. Thus, the checklists for the G/D Systems will reflect to a high degree the
large amount of experience with onshore applications, as summarized in Table 4-8.
Table 4-7. Spill Events for Offshore Gathering/Distribution Systems
by Subsystem and Spill Category
Subsystem
Pipeline
Storage
Pump Station
Safety
Gathering
Not Identified
Totals
Number of Spill Events
Minor
19
0
2
0
1
0
22
Moderate
21
2
3
0
1
0
27
Major
1
0
0
0
0
0
1
Not
Identified
3
0
0
1
0
2
6
Totals
44
2
5
1
2
2
56
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Table 4-8. Spill Events for Onshore Gathering/Distribution Systems
by Subsystem and Spill Category
Subsystem
Pipeline
Storage
Pump Station
Safety
Gathering
Not Identified
Totals
Number of Spill Events
Minor
36
1
1
0
8
2
48
Moderate
2429
96
111
1
775
15
3427
Major
634
38
38
1
83
2
796
Not
Identified
83
1
10
0
2
0
96
Totals
3182
136
160
-2
868
19
4367
4.4 SPILL VULNERABILITY CHECKLISTS
4.4.1 Introductory Summary
Spill vulnerability checklists - an essential part of the spill prevention program - are
presented for the Production and G/D Systems. Checklist development was based on
system descriptions and spill data summarized in Paragraphs 4.2 and 4.3, respectively.
The checklists were developed through the following steps:
1. Identify subsystems with significant major or moderate spill experience.
2. Identify equipment elements with significant spill experience within each
subsystem.
3. Analyze the data for each equipment element, to identify:
Significant causes and components associated with spill events
Prominent cause/component combinations and any trends (e.g.,
geographic location, age of facility, time of year, and increasing
or decreasing rate of occurrence).
4-18
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4. Examine component/cause relationships for significant and prominent
combinations in each subsystem and perform analyses similar to those
in item 3.
5. Examine each system total spill data and identify equipments most
often responsible for reported spills.
6. Examine all system spills (offshore, onshore, and combined) and identify
components most often responsible for reported spills.
These analytical steps identify, at system, subsystem, equipment, and component levels,
the spill-prone points meeting the criteria of Table 4-9.
Table 4-9. Spill Criticality Rating Guide
Spill Criticality Rating
PRIORITY
ROUTINE
POTENTIAL
Criteria for Assignment
Significant frequency of moderate or
major spills based on historical data
from present systems
Significant spill frequency or significant
(even if low frequency) cause/effect
relationship responsible for major or
moderate spills
Significant cause/effect relationship
shown by engineering study of the system
but not shown sufficiently in the spill data
to merit a higher rating
The checklist organization is structured into six columns:
Column 1 - System Spill Event Type - Type of spill defined as either leak or overflow/
overpressure. Leak is defined as spillage through a breach or break in a system com-
ponent. Overflow/overpressure is defined as spillage from a vessel through existing
connections, under conditions other than those intended for the passage of the liquid.
These definitions facilitate the evaluation of preventive measures (see Paragraph 4.5)
suitable to the type of spill event.
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Column 2 - Equipment Type(s) Involved - Equipment elements which contain spill
points for priority or routine review, as shown by the spill data from present systems.
Column 3 - Component Type(s) Involved - Component types recommended for spill
vulnerability review.
Column 4 - General Spill Cause - Cause of spill in terms of one of the following general
fault classifications:
Equipment (hardware)
Operator or maintenance
Design
Natural causes (acts of God)
Third party (actions or events)
Column 5 - Detail Cause - Specific cause from Appendix K.
Column 6 - Remarks - Comments about spill vulnerability points which may help define
the applicability to given facilities, including whether the item is limited to onshore or
offshore applications, geographic areas in which the event has been frequently observed,
and, in the case of externally corroded pipe, whether the pipe was coated or under cath-
odic protection.
4.4.2 Production System Checklists
The Production System Checklists for each subsystem are presented in Tables 4-10
through 4-18; (Tables 4-10 to 4-30 are placed at the end of this section). Spill vulner-
ability points shown as entries in these tables, have a "Priority" or "Routine" criticality
rating and are marked with a (1) or (2) respectively, in accordance with Table 4-9. The
spill vulnerability checklists for the Production System have no entries with a "Potential"
rating. This rating is used with the spill prevention guidelines in Paragraph 4.5.
4.4.3 Gathering/Distribution System Checklists
The G/D System checklists by subsystem are presented in Tables 4-19 through 4-22.
(There is no system checklist for the safety subsystem.) Spill vulnerability points
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points shown as entries in these tables have a criticality rating of "Priority" or "Routine"
and are marked with a (1) or (2), respectively, in accordance with Table 4-9. The spill
vulnerability checklists for the G/D System have no entries with a "Potential" rating.
This rating is used with spill prevention guidelines of Paragraph 4.5.
4.5 SPILL PREVENTION GUIDELINES
4.5«1 Overview
This paragraph presents the candidate spill prevention guidelines, an essential part of
the spill prevention program, for the Drilling, Production, and G/D Systems. These
guidelines, in conjunction with the spill vulnerability checklists presented in Paragraph
4.4, are to be used during review of SPCC plans. The spill prevention guidelines
address corrective or preventive measures to be considered in alleviating or eliminating
the effects of the spill vulnerable points given in the spill vulnerability checklists.
Through engineering analysis made during the derivation of the spill prevention guidelines,
possible spill points were identified which could not be determined through the data upon
which the spill vulnerability checklists were derived. As a result the spill prevention
guidelines address spill points rated "Potential" in addition to the spill points given in
the spill vulnerability checklists.
The review procedure given in Table 4-3 outlines the methodology required to utilize
the spill vulnerability checklists and the spill prevention guidelines. The spill criticality
ratings of "Priority" and "Routine, " applicable to both the checklists and the guidelines,
and "Potential," applicable to guidelines alone, are defined in Table 4-9.
4.5.1.1 Analytical Basis
The guidelines were derived from the fault tree analysis (FTA) diagrams presented in
Appendix F. The blowout prevention guidelines given in Paragraph 4.5.2 are derived
from a review of the FTA logic diagrams, Figures F-2 through F-4, which were scanned
to find any causative elements associated with system-related blowout potential. These
causative elements were then addressed with preventive measure guidelines and asso-
ciated remarks. The remaining guideline items were similarly derived. The guidelines
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for Production Systems, presented In Paragraph 4.5.3, were derived from Figures F-5
through F-9. The guidelines for G/D Systems, derived from Figures F-5 and F-6, are
presented in Paragraph 4.5.4.
4.5.1.2 Organization and Description
The guidelines are presented in checklist format for each system and its subsystems,
except the Drilling System. It is imperative that drilling plans and operations be
thoroughly conceived to control the catastrophic potential of a blowout. The blowout
prevention guidelines in Paragraph 4.5.2 are based primarily upon the various programs,
their controls, and the associated control equipment that may be required. The Produc-
tion and G/D Systems spill prevention guidelines are based upon two broad classifications
of spillage; i.e., leak and overflow/overpressure, as defined in Paragraph 4.4.1.3
The guidelines in the tables are given for these specific causes, and, when appropriate,
remarks are given.
The specific organization of the prevention guidelines addressing blowout prevention is
structured into four columns:
Column 1 - Equipment/Program Considerations - General areas of considerations to be
addressed if formation pressure control is to be attained.
Column 2 - Specific Area of Consideration - Specific elements, activities, or considera-
tions to be addressed to ensure that formation pressure control is maintained.
Column 3 - Cautionary or Preventive Action - Specific procedures, requirements,
policies, and tests to evaluate for each specific area of consideration.
Column 4 - Remarks - Potential undesired consequences resulting from specific areas of
improper activity, the desirable effects resulting from the suggested action, or other
miscellaneous comments.
The specific organization of the prevention guidelines addressing the production and
gathering/distribution functions is structured into five columns:
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Column 1 - System Spill Event Type - Type of spill, either leak or overflow/overpressure,
as observed at the point of spill. (Column 1 of the safety subsystem preventive guide-
lines is entitled "Safety Subsystem Failure Event Type" because the safety subsystem
cannot cause a spill. Failure to function properly is spill-related upon the condition
that a prior or simultaneous abnormal condition that can result in a spill has occurred.)
Column 2 - Applicable Equipment or Component - Equipment or component elements
applicable to the "Cause" given in column 3 and the "System Spill Event Type" given in
column 1.
Column 3 - Cause - Potential cause of the event given in column 1.
Column 4 - Preventive Action Guidelines - Actions which may be considered to prevent
or correct the listed cause.
Column 5 - Remarks - Miscellaneous comments, suggestions, or conditions which can be
considered to evaluate the applicability of the related preventive action guidelines to the
facility being reviewed.
4.5.1.3 Selectivity and Judgment Required
The spill prevention guidelines are to be used selectively in accordance with the criticality
rating given in the associated spill vulnerability checklist. These spill vulnerability
points and their associated spill prevention guidelines are to be used by the reviewer to
evaluate the facility subsystems under review, with the exception of the subsystem(s)
associated with the spill(s) which caused the SPCC submittal. The latter subsystem(s)
will be entirely evaluated by the spill prevention guidelines; however, the element of
judgment cannot be overlooked by the reviewer, since it plays an essential role in the
realistic and practical application of the checklist. His judgment is required to govern
the stringency with which the guidelines and the operator's corrective or preventive
measures are evaluated. In this regard he must consider, relative to onshore facilities,
the proximity of rivers and lakes, the potential of spilled oil getting into the watershed,
the proximity of wildlife sanctuaries, the potential dangers of land or snow slides, and
safety considerations such as the proximity of dwellings, highways, factories, schools,
4-23
-------
airports, and churches. Relative to offshore facilities, he must consider the potential
pollution of fishing waters and beaches and potential collision of shipping vessels.
4.5.2 Drilling Plans and Operations Spill Prevention Guidelines
The guidelines support the spill prevention program through the prevention of blowouts
which are primarily associated with rotary drilling activities during drilling operations.
However, with judicious application, many of the items also are applicable to completion
and workover operations. Although the guidelines given in Table 4-23 are extensive, they
are not all-inclusive. The applicability of each item in Table 4-23 requires selective
judgment dependent upon type of well being drilled, surrounding environment, prior drill-
ing experience in the site area, and anticipated downhole conditions. For example, the
plan for a well being drilled into an already proven formation in Osage country (such as
west Texas) would not necessarily contain the stringent requirements of a plan for a well
to be drilled off the mid-Atlantic coastline near New York. The west Texas example
would have anticipated downhole conditions well defined by extrapolation of geological
conditions and experience from drilling other wells in the vicinity. This would be con-
sidered development well drilling. In addition, few if any problems would exist relative
to polluting water or presenting a hazard to a populated area. In contrast, the mid-
Atlantic operation would be a rank exploratory drilling operation with negligible area
drilling experience upon which to extrapolate anticipated downhole conditions. Further-
more, it would be in water near a concentrated metropolitan area. Therefore, with
these conditions in mind, it may be warranted for Table 4-23 guidelines to be applied in
their entirety. From these two extreme hypothetical examples, it becomes apparent
that the guidelines must be selectively applied to the particular drilling plan under review.
4.5.3 Production System Spill Prevention Guidelines
Spill prevention guidelines for five production subsystems (gathering, treater, local
storage, separation, and safety) are presented in Tables 4-24 through 4-28. These
tables were developed for the subsystems which are the leading oil spill contributors.
The structure of the guideline tables follows that presented in the respective fault trees
4-24
-------
in Appendix F (Figures F-5 through F-9). These guidelines must be used in conjunction
with the spill vulnerability checklists in Tables 4-12 through 4-15 and Table 4-17 so that
preventive measures address points having a criticality rating of "Priority." The guide-
lines addressing that subsystem from which one spill of 1000 gallons or more, or two
spills of any size in a 12-month interval are intended to be used in their entirety, regard-
less of the criticality rating given in Paragraph 4.4, to address all potential spill points
in the subject subsystem.
4.5.4 Gathering/Distribution System Spill Prevention Guidelines
Spill prevention guidelines for the pipeline, storage, and gathering subsystems of the
G/D System are presented in Tables 4-29 and 4-30. The gathering subsystem appears
with the pipeline subsystem since the equipment used is similar. The tables for these
subsystems were developed because they are the G/D System leading oil spill contributors.
The structure of the guideline tables follows that presented in the fault trees in Appendix
F, Figures F-5 and F-7. However, selectivity was used in determining corrective factors
and preventive measures to account for the difference in crude oil handled. These guide-
lines must be used in conjunction with the spill vulnerability checklists of Tables 4-19,
4-20, and 4-22 so that preventive measures address points having a "Priority" criticality
rating. The guidelines addressing that subsystem from which one spill of 1000 gallons or
more, or two spills of any size in a 12-month interval is intended to be used in its
entirety, regardless of the criticality rating given in Paragraph 4.4, to address all
potential spill points in the subject subsystem.
4-25
-------
Table 4-10. Production System Spill Vulnerability Checklist, Well Subsystem
System Spill Event
Type
lOV
Overpressure/Overflow '
Equipment Type(»>
Involved
All<2>
Surface Casing or
Production Tubing' '
Component Type(s)
Involved
All*21
Cement or Plug'2'
General Spill
Cause
0/M Error*2*
Natural Cause*'
Detail
Cause
(2V
Maintenance Improper
Well Flowed'2'
Remarks
Wire line operation and workover Included
Plugged and abandoned wells leaking - Oklahoma
t
to
Oi
NOTES: (1) Spill critloallty rating of priority In accordance with Table 4-9.
(2) Spill critlcatlty rating of routine in accordance with Table 4-9.
Table 4-11. Production System Spill Vulnerability Checklist, Wellhead Subsystem
System Spill Event
Type
Leak*1'
Equipment Type(s)
Involved
Choke'1'
Rod Pump(2)
Component Type(s)
Involved
Body(1)
Stuffing Box'2'
General Spill
Cause
Equip. Malfunction'1'
Equip. Malfunction'2'
O/M Error'2'
Detail
Cause
Sand Cut(1)
Leaking'2'
Valve, position error
Remarks
Gulf OCS, South Pass Area, New Orleans District
Texas, District No. 6
NOTES: (1) Spill crltlcallty rating of priority In accordance with Table 4-9.
(2) Spill crltlcallty rating of routine In accordance with Tnblc 4-9.
-------
Table 4-12. Production System Spill Vulnerability Checklist, Gathering Subsystem
System Spill Event
Type
Overpres mire/Overflow'
Le«k<21
Leak'"
Leak'2'
Equipment Type(a)
Involved
Manifold'21
Flowllne
Manifold* '
Component Type(s)
Involved
_ (2)
Pump
Pipe, Fittings and Valves' *
Plpe(I)
Pump Gaskets, Seals,
Packings'2'
General Split
Cause
Equipment
Malfunction12*
Equipment
(21
Malfunction
Equipment
MalJunctlon'1'
Third Party (2>
Equipment
Malfunction'2'
Detail
Cause
Non-Function or
Lca» of Power
Sanrf or Flow Out'2'
<2)
Overpressure
Broken'1'
Burst'1'
Leak/Hole'1'
Corrosion
Hoad Machinery'2'
Burs.'2'
Remarks
Offshore - Platform to pipeline - West Delta Area
Remits la Surge Tank Overflow
Offshore
Offshore Lousl ana (corrosion not Included)
Onshore
Onshore See Appendix H
Onshore
Offshore
rf»
to
NOTES; (1) Spill criticality rating of priority in accordance with Table 4-9.
(2) Spill criticality rating of routine in accordance with Table 4-9.
-------
Table 4-13. Production System Spill Vulnerability Checklist, Separation Subsystem
System Sptlt Event
Type
Overpressure/Overflow
Overpressure/Overflow '
Leak'2*
Leak'1*
Equipment Type(s)
Involved
Separator Low Pressure
Separator High Pressure'1'
Component Type(s)
Involved
Dump Valves'1*
Pressure Relief Valve'2'
Rupture Disc'2'
Fittings and Valves'2'
Dump Valves'1'
General Spill
Cause
Equip. Malfunction'1'
Equip. Malfunction'2'
0/M Error'2'
Equip. Malfunction'2'
Equip. Malfunction'1'
Detail
Cause
Fall Open'2'
Fall Closed'1'
Failed Open'2'
(2)
Overpressure
Defective Disc'2'
(21
Overpressure1 '
Misapplication'2'
(2>
Improper Maintenance1
Sand or Flow Cut'2'
Sand or Flow Cut'1'
Remarks
Offshore
Offshore Louisiana
to
CO
NOTES: (1) Spill critical!ty rating of priority In accordance with Table 4-9,
(2) Spill crltlcallty rating of routine in accordance with Table 4-9.
-------
Table 4-14. Production System Spill Vulnerability Checklist, Treater Subsystem
System Spill Event
Type
Overpressure/Overflow' '
Overpressure/Overflow' '
Equipment Type(s)
Involved
Heater Treater'1'
(2)
Gun Barrel '
Chem-Electrlc Tteater'2'
Component Type(s)
Involved
Dump Valve'1'
Fire Tubes'2'
Piping'2'
Dump Valves'2'
Piping'2'
Dump Valves'2'
General Spill
Cause
Equip. Malfunction'1'
Equip. Malfunction'2'
Detail
Cause
Fall Open' *'
Fall Closed'2'
Hole'2'
Plugged'2'
Fall Open or Fall Closed'2'
Plugged'2'
Fall Open or Fall Closed'2'
Remarks
Most likely salt water dump valves
See Appendix H
Same as for Heater Treaters
to
NOTES: (1) Spill critioality rating of priority in accordance with Table 4-9.
(2) Spill criticnllty rating of routine in accordance with Table 4-9.
-------
Table 4-15. Production System Spill Vulnerability Checklist, Local Storage Subsystem
Syitem Spill Event
Type
Overpressure/Overflow
(2)
Overpressure/Overflow
Overpressure/Overflow' '
Leak'1'
Leak'2'
Equipment Type(s)
Involved
Tank and Tank Aasociated
Equipment*1'
Sumps
Tank and Tank Asaoclated
Equipment'^
Component Type(i)
Involved
General'1'
Pumps'2'
Valvea'2'
Tank or Pit'2'
Pump«'
General'1'
Piping* Z)
General Spill
Cause
Equip. Malfunction'11
0/M Error'1'
tz\
Natural Causes1 '
Equip. Malfunction^2'
0/M Error'2'
Equip. Malfunction'2'
Equip. Malfunction11'
Equip. Malfunction'1'
Equip. Malfunction'2'
Detail
Cause
Overflow'1'
Operation Incorrect
Lightning'2'
Non-Function
Left Open/Closed'2'
pverflow'2'
Non-Function'1'
Leak/Hole'1'
Leak/Hole'2'
Remarks
Secondary Containment and Recovery Generally Inadequate
for both Onshore and Offshore Facilities.
Onshore
Onshore and Offshore Louisiana West Delta Area
Onshore
Offshore
Gulf OCS
Onshore - Includes foundations
Onshore
t
CO
NOTES: (1) Spill critlcnlity rating of priority In accordance with Table 4-9.
(2) Spill critically rating of routine In accordance with Table 4-9.
-------
Table 4-16. Production System Spill Vulnerability Checklist, Custody Transfer Subsystem
System Spill Event
Type
Overpressure/Overflow
Equipment Type(s)
Involved
Pumps'2'
Meters'2'
Power'2'
Component Type(s)
Involved
/
\
General Spill
Cause
Equip. Malfunction'2'
Detail
Cause
Non-Function'2'
Electrical Malfunction'2'
(2)
Loss of Power* '
Remarks
MOTHS: (1) Spill criticallty rating ot priority in accordance with Table 4-9.
(2) Spill crlticality rating of routine in accordance with Table 4-9.
Table 4-17. Production System Spill Vulnerability Checklist, Safety Subsystem
System Spill Event
Type
Overpressure/Overflow
in\
Overpressure/Overflow
Equipment Type(s)
Involved
Sensing/Detecting
Monitoring and Control'2'
Component Type(s)
Involved
High Level Sensors'4'
Valves'2'
General Spill
Cause
Equip. Malfunction^4'
Equip. Malfunction' '
Detail
Cause
Non-Functioning'
Non-Functioning'2'
Remarks
Spill criticallty rating of (1) for tanks, sumps. L. P.
separators, and heater treaters, and (2) for scrubbers.
See Appendix J
NOTES: (1) Spill criticallty rating of priority In accordance with Table 4-9,
(2) Spill crltlcality rating of routine In accordance with Table 4-9.
(4) See remarks column for spill criticallty ratings of high level sensors
on various equipments.
Table 4-18. Production System Spill Vulnerability Checklist, Water Disposal Subsystem
System Spill Event
Type
(2)
Overpressure/Overflow '
Equipment Type(s)
Involved
Pump'2'
Component Type(s)
Involved
General
General Spill
Cause
Equip. Malfunction'2'
Detail
Cause
Non-Functioning'2'
Remarks
NOTES. (1) Spill criticallty rating of priority In accordance with'Table 4-9,
(2) Spill criticallty rating of routine In accordance with Table 4-9.
-------
Table 4-19. Gathering/Distribution System Spill Vulnerability Checklist, Pipeline Subsystem
00
lystem Spill Event
TJPPe
Overpreasure/Ovarflow
Leak'2'
Leak"'
L.ak<2>
Equipment Type(.)
Involved
Pipeline'1'
Road Crossing'21
Component Type
Corroalon
Corrosion (External)'1'
See Appendix H
Corrosion (Internal)'1'
See Appendix H
Defective Material'2'
Defective Wolds'2'
Road Machinery'2'
Corroalon'2'
Road Machinery'2'
Remark*
Texas, Ml.atiatppl and Colorado
1. Texas (Dlst. 4 Apr-Sept); DIM. 7 (hole/leak)
2, Miss. (Oot-MarxUrge dla. pipe), low recovery
3. Requlrea clarification between external or Internal
corrosion for remedial action.
1. Illinois, Inatalled 1930-39, cath. prat,, coated
2. Indiana. Installed before 1920. no protection
In Lake, porter and Fulton Counties.
3, Indiana. Installed 1930-1949 In Wayne, Putnam, Shelby,
Vlgo and Johnaoa Counties! cath. protection but not
coated.
4. Louisiana. Installed 1940-49, Lafayette Dial. , cathodlc
protection, not coated.
5. MlsBlsstppt. Installed 19(0-99, Perry and Lamar
Counties, no protection.
0, New Mexico. Installed 1930-39. Lea County, oathodlc
protection, mostly uncoated.
7. Ohio. Installed before 1920. Tmmbull County, no
protection.
8. Ohio, Installed 1930-49, Wood County, little protection.
9. Oklahoma. Installed 1920-19, Dlst. 1 and 4; moat with
cathodtc protection! mostly unooatod.
10, Pennsylvania. Installed before 1920, no protection,
Clarion, Butler and McKean Counties,
11. Texas. 82 major spill events, mixed pipe age protection
statua and location.
1. Montana. Inatalled 1950-59, Wlbaux County, all coated
and with oathodlc protection.
2. Texaa. Dla. 7, 8, and 10. Large dla. pipe, most
spills reported month* of Oct. and Nov.
3. Texaa. Inatalled 1960-69, Dlst. 10, cath. prot. and
coated.
4. Texas. Installed 1940-49, Mat. 8, cath, prot, and
coated.
5. Texas. Installed 1920-29, Dist. l and 7C, cathodlc
protection and coated.
KaniaB. Montana. Oklahoma, Texaa.
Oklahoma. Installed 1930-39, Dlst. I, Pawnee and Payne
Countlea. pipe coated but cath. prot. atntua not known.
Oklahoma. Dirt. 2 Oklahoma and Kingfisher Counties.
Texas 44 major spill event*, mixed locatlona.
Colorado. Rio Blanco County.
Toxa*
NOTESi (1) Spill crltlcaUty rating of priority In uccorduncv with Tublu -1-9.
(2) Spill crULcnllty rating of routine In accordance with TiibUr I-U.
-------
Table 4-20. Gathering/Distribution System Spill Vulnerability Checklist, Storage Subsystem
System Spill Event
Type
Overpressure/Overflow
Equipment Type(s)
Involved
Tank and Tank Associated
Equipment'1)
Component Type(s)
Involved
Body or Shell'1'
Check Valves'1'
General Spill
Cause
Equip. Malfunction11'
0/M Error'2'
Equip. Malfunction'1'
Detail
Cause
Overflow'1'
(21
Operation Incorrect1 '
Fall Open or Non-Function' '
Remarks
See Appendix J
NOTES: (1> Spill crlticality rating of priority in accordance with Table 4-9.
(2) Spill crlticality rating of routine in accordance with Table 4-9.
Table 4-21. Gathering/Distribution System Spill Vulnerability Checklist, Pump Station Subsystem
System Spill Event
Type
Leak*2'
Equipment Type(s)
Involved
Pump'2'
Component Type(s)
Involved
Hose'2'
Nipple'2'
Packing Gland'2'
General. Spill
Cause
Third Party'2'
Equip. Malfunction'2'
Detail
Cause
Vandalism'2'
Broken'2'
/2v
Overpressure or Leak '
Remarks
00
KOTKS: (1) Spill criticality rating of priority in accordance with Table 4-9.
(2) Spill crlticality rating of routine in accordance with Table -4-9.
Table 4-22. Gathering/Distribution System Spill Vulnerability Checklist, Gathering Subsystem
System Spill Event
Type
Leak'1'
Equipment Type(s)
Involved
All Gravity, Suction,
and Pressure Systems
Component Type(s)
Involved
Pipe'1'
General Spill
Cause
Equip. Malfunction' '
See Appendix H
ThlnJ Party'2'
Detail
Cause
BurSt<2'
Corrosion'2'
Corrosion (External)
Corrosion (Internal)
Road Machinery1 2)
Remarks
Texas, large diameter pipe
Texas: requires clarification to define as either external
or Internal corrosion for remedial action.
Texas, Districts 8 and 9, winter months
Texas, large diameter pipe
Texas, District 9, winter
NOTES: (1) Spill criticality rating of priority in accordance with Table 4-9,
(2) Spill criticality rating of routine in accordance with Table 4-9.
-------
Table 4-23. Blowout Prevention Guidelines for Evaluation of Drilling Plans and Operations
Equipment/
Program
Considerations
Casing*
Cement
Drilling mud
Specific Area
of
Consideration
Program
Casing string
design
Casing pres-
. sure test
Running casing
Alleviation of
casing wear
during drilling
and tripping
Cement pres-
sure testing
Program
(General)
Program
execution
Cautionary or Preventive Action
Analysis of prior area drilling experience relative to anticipated pressures and formation
strengths.
Design of the -casing string should correlate with pore pressure and formation fracture
gradient considerations.
All casing strings should be tested for leaks prior to drill out of plug after cementing.
Control speed at which casing is run into hole to reduce surge pressures.
Provide for avoidance of critical rotary speeds.
Provide for control of dog leg severity.
Keep Kelly and crown block lined up over hole.
Keep drill string and Kelly straight.
Maintain and check wear bushing.
Maintain smooth surface on drill string members, such as drill pipe rubbers and
hard bands at tool Joints.
Maintain sand content of drilling mud at lowest possible level.
All primary cement Jobs should be tested (upon Initial drill out after the casing
pressure test) to a pressure In excess of the equivalent hydrostatic head of the
heaviest drilling mud subsequently required prior to setting additional casing.
If cement Job falls, It should be repaired by squeeze cementing.
Consider surge and swab pressure variations during tripping.
Continuous surveillance by competent technical personnel at the rig to Interpret
current conditions to assure positive ECD during execution of trips and standing
out of the hole Is desirable.
Control speed of withdrawal of drill string.
Standardized procedure for keeping hole filled during trips Is desirable. Trip
tank and pump stroke counter are desirable during tripping or standing out of hole.
Procedure for controlling speed at which drill pipe Is run Into hole during trips to
minimize surge pressures.
Remarks
Insufficient depth of casing for the pressure and depth of the objective
can result In lost circulation and potential well control toes.
Improper casing design can result In casing failure during well killing
operations.
This wUl assure the pressure Integrity of the casing string.
Rapid lowering of casing can result In lost circulation from plunger,
or surge, effect.
Incidents of high lateral thrust loads are alleviated.
Poor vertical alignment promotes casing wear.
(Wear bushing not necessary In completion or workover activity. )
Reduces wear on casing from rotation of drill string.
Reduces abrasive effect of drilling mud.
This assures the pressure Integrity of the system.
Inadequate ECD concepts permit kicks or lost circulation to occur
unnecessarily.
Not maintaining positive ECD permits kicks to occur unnecessarily.
Too rapid withdrawal of drill string results in a negative ECD
(swabbing) and allows kicks to occur unnecessarily.
Not keeping hole filled can result In unnecessary kicks.
Lost circulation can occur when running drill pipe Into hole
too fast (surge), i
to
tffc
-------
Table 4-23. Blowout Prevention Guidelines for Evaluation of Drilling Plans and Operations (Continued)
Program
Considerations
Drilling mud
( continued)
Detection equip-
ment require-
ment* and
procedures
Specific Area
of
Consideration
Sand content
control
Separation of
water and mud
s ya terns
Quantity of
mud on
Ite
Weak forma-
tion break-
down
General Instru-
mentation and
alarm require-
ments
General
Kick detection
training and
policy
Detecting
circulating
pressure
decrease or
pump speed
Increase
Detecting pit
gain
Detecting drill-
Ing rate change
or drilling
break
Detecting
flowllne mud
weight
decrease
Detecting flow
rate Increase
Cautionary or Preventive Action
Dasander and/or centrifuge desirable to keep sand content of drilling rr ud low.
Desirable to maintain complete separation of water system from mud system to prevent
accidental dilution of mud with water.
Require quantity of mud on site to meet contingency needs.
All rig personnel should be familiar with procedure In the event of lost circulation due
to formation breakdown.
Consider requiring Instrumentation for proper action mud inventory and competent
technical personnel to Interpret the relevant Indications.
Manufacturers' procedures for the installation, maintenance, and calibration of the
various detection equipment should be adhered to.
Consider requirement for formalized training program and policy for kick detection.
Consider requiring pump stroke counter and/or flowltne alarm.
Consider requiring pit levels and alarm.
Requires proper training, attention, and competent Interpretation of potential
danger present.
Remarks
Abrasive sand can cause casing wear.
Resulting lighter mud can result in unnecessary kicks.
Requires pit level recorder to detect gain or Ices of mud, either
being an indication of a kick or lost circulation.
en
-------
Table 4-23. Blowout Prevention Guidelines for Evaluation of Drilling Plans and Operations (Continued)
Equipment/
Program
Considerations
BOP equipment
requirements
Specific Area
°f
Consideration
General
Preventer
equipments
General pre-
venter
Installation
procedures
H S con-
&
slderation
Periodic test
and mainte-
nance of BOP
equipment
Operation
of Ram
preventers
Choke, mani-
folds, kill
lines, flow
lines
Cautionary or Preventive Action
Provide flexibility to address all conditions and redundancies.
Align on Installation and maintain alignment.
Give consideration to API/IADC suggested preventer stack configuration (API Bulletin
D13) relating to anticipated bottom hole pressures and existing environment.
Consider formalized procedures to define (relative to various casings) the BOP
stack configuration to be used.
Consider use of BOP equipment designed for H S service if H S may be encountered.
Require weekly (or more often If conditions warrant) pressure tests on BOP
stack and flushing with water at same time.
Require pressure test on BOP stack upon installation.
Require pressure test on BOP stack following repairs which required disconnection
of a pressure seat In the assembly.
Scheduled weekly (or more often if conditions warrant) tightening of BOP stack
should be required.
Ram preventers should be exercised every trip.
Only one set of ram preventers should be closed at the same Instant.
Give consideration to APt/IADC suggested choke manifolding and '-'.'l line
configuration (API Bulletin O13) related to the maximum anticipated bottom
hole pressure.
Have manual switching available as backup to hydraulic switching.
Provide operating handle for each value.
Remarks
These minimum configurations for various anticipated service
conditions (I.e., light, low, medium, high, or extreme pressures)
should be altered in view of existing environment and type of well
being drilled. For example, a rank exploratory well drilling
operation has negligible geological data to extrapolate anticipated
conditions; it may be desirable to exceed the minimum configuration.
Also, if drilling Is being performed In populated, sea, and water-
shed environments. It may be desirable to exceed the minimum
configuration. This API/IADC bulletin is in process of being updated.
See Appendix H
If severe shaking and vibration la being Imposed upon the BOP
stack, more frequent testing may be required.
If severe shaking and vibration is being Imposed upon BOP
stack, more frequent tightening may be required.
f
CO
-------
Table 4-23. Blowout Prevention Guidelines for Evaluation of Drilling Plans and Operations (Continued)
Equipment/
Program
BOP Equipment
Requirements
(Continued)
Wellhead
equipment
Miscellaneous
Well killing
procedures
Specific Area
of
Periodic
test and
maintenance
of choke, and
kill manifold-
ing and lines,
kelly, and drill
string
Hydraulic
closing and
control equip-
ment for BOPs
and choke
matnfoldlng
Periodic test
of closing and
control equip-
ment
General
Dropped drill
string
Pressure
leak
Positive kick
control contin-
gency plan
Kick control
training
Well killing
worksheet
Pit drills
Cautionary or Preventive Action
Require weekly pressure test and related water flushing. (This test Is an integral portion
of previously noted test on the BDPs).
Keep main outlet valve closed and maintain manifold full of clear water.
Require accumulator capacity sufficient to close all BOPs and hydraulic valves with
adequate reserve fluid without operating hydraulic pumps.
Require hydraulic line sizing adequate to allow rapid closing of BOPs.
Require properly sized reservoir.
Require sufficiently sized and sufficiently pressured accumulator bottles for backup.
Consider the temperature, foam, and other characteristics of the hydraulic fluid In
relation to environment and application usage.
Inspect hydraulic fluid for cleanliness and sufficient filtering.
Require remote control at safe distance from rig floor and ctenr marking of controls.
Require complete test of closing and control equipment weekly.
Require partial test every trip. (Related to exercising Ram preventers).
Consider the necessity of using wellhead equipment which Is not prone to hydrogen
embrlttlement failure In H S, CO and other corrosive applications In high surface
pressure applications.
Consider future operating loads, such as sand and other production elements,
which may be imposed on wellhead.
Requires good maintenance on drill pipe handling equipment.
Require new and clean spare gaskets, seal, or O-rings on hand for reassembly of BPO
or BOP stack.
Be familar with location and use of secondary seals.
Should have documented evidence of BOP configuration, well killing equipment design for
conditions expected, based on anticipated fracture gradient and pore pressure profile.
Desirable to have driller, tool pusher, and drilling engineer periodically trained on a kick
simulator device, or well, In properly controlling kicks under various conditions, such as
BIT -ON-BOTTOM situations and BIT -OFF-BOTTOM situations.
A written plan and updated well killing worksheet should be required on the rig and
personnel should be familiar with It..
Should be required weekly (or more often Iff conditions warrant) for each crew.
Documented procedure for pit drills should be available.
Remarks
To prevent settling of sand, cuttings, etc., that can
foul valve.
See Appendix H
Can result In lost circulation.
Can result in blowout during well killing operations.
Formalized classroom work of this nature is available
as Industry-sponsored adult education courses at various
universities and within some companies.
CO
-------
Table 4-24. Production System Spill Prevention Guidelines, Gathering Subsystem
System
Spill Event
Type
Applicable Equipment
or
Component
Cause
Preventive Action Guidelines
Remarks
Manifold
Overpressure/
Overflow
Pump
Power Lossv
or Failure
Consider Allowing Adequate Storage Capacity for Worst Case
Pump or Power Repair.
Consider Backup Power Source.
Upstream Vessel can Overflow.
Flowline Leak
CO
00
Pipe*
External (1)
Corrosion
Check Desirability of and Apply External Coating or Wrapping
See Appendix H
Pipe, Fittings
Couplings, etcetera
Require Routine Inspection and Patrol
Pipe
Consider a Recommended Manufactured Pipe Process
Consider Sacrificial Cathodlo Protection
Consider Scheduled Replacement of Pipe Possibly by;
1. Setting Threshold of Pipe Repair After Which
Replacement Is Required.
2. Ultrasonic Survey Techniques
3. X-Ray Survey Techniques
Desirable In Offshore, Estuary, and Inland Water
Operation.
See Appendix H
Consider Use of Plastic, Glass Reinforced, or Similar. Pipe
In Low Pressure Applications and Limited Areas of the
Gathering Subsystem.
See Appendix H
Consider Heavier Pipe.
Pipe, Fittings,
Couplings, et cetera
(1)
Internal
Corrosion
(1)
Consider Injection of Inhibitor at the Well Subsystem
Pipe
Consider Use of Plastic, Glass Reinforced, or Similar. Pipe
In Low Pressure Applications and In Limited Areas of the
Gathering Subsystem.
Pipe, Fittings,
Couplings, et cetera
Tempera-
ture (Burst
or Freeze)
(1)
Avoid Configurations Which Allow Static Accumulations of
Water.
Take Thermal Expansion/Contraction Considerations into
Account.
Pipe
,(2)
(2)
Collision
(Third Party)
Mark Pipe Location at Points Vulnerable to Collisions.
Patrollng and Monitoring Surveillance.
Exchange information and Educate.
Document Routing and Depth.
-------
Table 4-24. Production System Spill Prevention Guidelines, Gathering Subsystem (Continued)
System
Spill Event
Type
Flowline Leak
(Continued)
Manifold Leaks
Applicable Equipment
or
Component
Pipe, Elbows, et(2)
cetera
Couplings, Unions,
Et cetera
Pipe
Pipe, Fittings,
Couplings, Et Cetera
General
Valves
Cause
Sand or (2)
Flow Cut
Coupling, (3)
Union, and
Similar
Failures
Weld <3>
Failure
Shock and (3)
Vibration
Fatigue
Operator/ * '
Maintenance
Incurred
Damage
Incorrect
Operator
Action (Over
Pressure)
(31
Procedural v '
Errors
Vandalism *3'
Operator <3)
Negligence,
Training, and
Incorrect
Operator
Action
Preventive Action Guidelines
Review Velocity and Capacity Considerations For:
1. Allowance of Long Radius Bends, Instead of Sharp Bends.
2. Velocity Reduction, Such as Larger Diameter Pipe, or
Choke.
3. Use Abrasive Resistant Materials in Critical Areas.
4. Eliminate Sand at Earliest Point in Configuration.
Educate Personnel on Proper Application.
Educate Maintenance Personnel on Proper Make-up Procedures.
Avoid Imposition of a Bending Moment on Component.
Give Velocity and Pressure Considerations to Component
Selection.
Consider Use of Welded Joints In Lieu of Couplings.
Educate Personnel on Best Welding Procedure For the Appli-
cation.
Consider Use of Pulsation Dampeners.
Avoid Turbulence Through Smooth Changes in Cross Section or
Direction.
Use Heavier Material When Outside Forces are Known to be
Hostile.
Provide Proper Tools.
Provide Proper Training.
Use Proper Methods.
Perform Inspection of Repair.
Separate High Pressure and Low Pressure Operation to Decrease
Possibility of the Application of One on the Other.
Color Code Piping and Valving.
Indicate on Valving the Direction of Flow.
Lock Unattended Valves in Desired Position.
Job Descriptions With Minimum Required Experience Specified.
On the Job Training Under Competent Supervision and Monitoring.
Remarks
OS
to
-------
Table 4-24. Production System Spill Prevention Guidelines, Gathering Subsystem (Continued)
System
Spill Event
Type
Manifold Leaks
(Continued)
Applicable Equipment
or
Component
Valves
(Continued)
Pump Gaskets,
Seals, Packing
Cause
Worn <3>
Valvlng
Valve Pack-<3)
Ing Degraded
Valve Cut- ^
out
Valve <3>
Vibration
Livestock <2>
Rubbing
Valves
Corrosion
of Valves,
Header, et
cetera
Freeze or * '
Burst
Worn <2>
Preventive Action Guidelines
Consider Periodic Inspection and Overhaul.
Consider Periodic Inspection and Packing Replacement.
Reduce Abrasives Where Possible.
Reduce Velocities.
Use Hard Valve Trim.
Remove Constrictions or Conditions Which Can Cause Chatter.
Consider Fencing In Area.
Consider Installing Protective Cover Over Sensitive Items.
Consider Locking Valves In the Desired Position.
Periodic Inspection and Maintenance.
Use Special Valve Trim.
Use Heavier Materials.
Avoid Static Accumulations of Water.
Consider Burying Flowlines Below Frost Depth.
Consider High Pressure Shutdown, or Relief Valve, on Rod
Pumps.
Increase Maintenance and Inspection.
Consider Redundant Pumps.
Remarks
Usually Indication That Valve May Need Maintenance
See Appendix H
NOTES: (1) Spill Critteallty Rating of Priority In Accordance With Table 4-9.
(2) 9pOl Crittcality Rating of Routine In Accordance With Table 4-9.
(3) Spill Criticality Rating of Potential In Accordance With Table 4-9.
-------
Table 4-25. Production System Spill Prevention Guidelines, Treater Subsystem
System
Spill Event
T\pe
Overpressure/
Overflow
Applicable Equipment
or Component
Saltwater Dump Valve
on treaters, gun barrels,
skimmers, freewater
knockouts
Oil Dump Valve
Cause
(1)
Fails Open
(General)
Fails Open (1)
(Sanded up)
Fails Open ( '
^Instrument
Gag lost )
Falls Open ( '
(Ruptured
Diaphragm)
(2)
Falls Closed
(General)
Falls Closed <2)
(Sanded up or
plugged)
Falls Closed (2)
(Treater
Pressure lost)
Faila Closed (2)
(Hole In float)
Falls Closed (2)
(Level control
linkage failure)
Falls Closed
(Valve spring)
Falls Open (1)
(General)
Preventive Action Guidelines
Consider alternate downstream capacity for containment.
Consider low oil level shut-in or high level shut-in
downstream.
Increase Inspection and sand clean-out.
Desirable to have stand-by Instrument gas source. Most
desirable to have primary source to be Independent of the
gas In the treater.
Routine inspection and overhaul.
Consider alternate downstream capacity for containment.
Consider scrubber on gas flare or gas sales line.
Consider high level shut-in.
Consider Increased Inspection and sand clean-out.
Consider sand jets on treaters.
Desirable to have primary source to be Independent of
treater gas pressure and treater pressure used as
standby source.
Check float periodically.
Consider stainless steel or plastic float.
Increase inspection and maintenance.
Consider routine overhaul.
Consider alternate downstream capacity for containment,
Consider high level shut-in and/or alarm for water/oil
Interface.
Remarks
Oil flows out the water leg, resulting In possible spill downstream.
Applicable to gas actuated dump valves.
Causes saltwater carry-over Into oil outlet, resulting In possible spill
Downstream. Also, possible carry-over out gas tine.
Applicable If dump valve is reverse acting and actuated by pressure
In treater. Oil dump valve would fail closed also.
Applicable to horizontal treaters.
Water and oil overflows out oil outlet. (Not a likely event. )
Applicable to horizontal treaters.
-------
Table 4-25. Production System Spill Prevention Guidelines Treater Subsystem (Continued)
System
SplU Event
Type
Overpressure/
Overflow
(Continued)
Applicable Equipment
or Component
Oil Dump Valve
(Continued)
Energy Source
Relief Valve
Cause
(1)
Falls Open
(Ruptured
Diaphragm)
Falls Open (1)
(Instrument
Gas Lost)
Falls Closed (1)
(General)
Falls Closed (2)
(Hole in Float)
Falls Closed (2)
(Level Control
Linkage Failure)
Falls Closed (2)
(Treater
Pressure Lost)
(3'
Energy Source
Lost
(2)
Fire Tube Hole
Falls Open (2)
(General)
Falls Open (3>
(Mlsadjustment)
Preventive Action Guidelines
Routine overhaul.
Desirable to have primary source of Instrument gas to be
Independent of treater gas pressure and treater pressure
used as a standby source.
Consider alternate downstream capacity for containment.
Consider low level shut-in and/or high level shut-In and/or
alarm downstream.
Check float periodically.
Consider stainless steel or plastic float.
Increase Inspection and maintenance.
Desirable to have primary source of Instrument gas to be
Independent of treater gas pressure and treater pressure
used as standby source.
Consider alternate capacity for containment downstream.
Consider flame arrester on fire box or burner.
Consider corrosion Inhibitor In emulsion.
Consider Increased Inspection and maintenance on fire tube.
Pipe overflow to sump or secondary containment.
Consider high level or high pressure shut-In and/or alarm.
Increase test and inspection.
Remarks
Applicable to gas actuated dump valves.
Oil escapes through saltwater outlet. Potential of spill downstream
Applicable to horizontal treaters.
Applicable If dump valve Is reverse acting and actuated by pressure In
treater. Saltwater dump valve would Call closed also. Oil flow would
occur out gas line.
Emulsion out both oil and saltwater outlets. Possibly cause problem
of saltwater dump valve falling closed with result of potential carry-
over out gas line also.
Potential of fire and resultant overflow.
See Appendix H
Liquid will overflow through relief valve.
Configuration dependent
rf*
to
-------
Table 4-25. Production System Spill Prevention Guidelines^ Treater Subsystem (Continued)
System
Spill Event
Type
Overflow
Overpressure
(Continued)
Leaks
Applicable Equipment
or
Component
Rupture Disc
Pipe
Vessel shell, plerce-
ments, fire tubes,
water and oil legs,
fittings, et cetera
Rupture Disc
Connections, Valves,
et cetera
Valves, piping, etc.
Connections, Fitting
Sight glasses, gauges,
et cetera
Connections, unions,
et cetera
Gaskets, seals, et
cetera
.Cause
Falls Open
(General)
Falls Open
(Wrong Disc)
Falls Open
(Corrosion)
Bursts Open
(Disc Function)
(was normal)
Plugged (2)
Corrosion
Sand or Flow
Cut
Froze and
Burst (Tem-
perature)
Broken Due
to Movement
Breakage
Operator/Main-
tenance In-
curred damage
Worn
Preventive Action Guidelines
Pipe overflow to sump or secondary containment.
Consider high level and high and low pressure shut-in
and/or alarm.
Check application and replace with proper disc.
Coat disc with cosmollne.
Consider changing configuration to protect disc from
moisture entrapment.
Inspect and replace more frequently.
Check for dump valves falling closed.
Check for plugged outlets.
Check for relief valve falling closed.
Increase maintenance.
Consider use of inhibitors for Internal corrosion.
Consider Increased maintenance and inspection.
Increase Inspection and replace.
Coat with cosmollne.
Change configuration to eliminate moisture entrapment.
Consider choke at Inlet to treater.
Consider use of abrasive resistant materials in critical areas.
Insulate outlet lines or valves.
Design for thermal shock (expansion and contraction).
Design foundation for freeze/thaw heaving.
Put protective guards on Items.
Educate personnel on proper application.
Educate personnel in proper make-up procedures.
Perform Inspection of repair.
Provide proper tools.
Routine Inspection and overhaul.
Remarks
Liquid will overflow through rupture disc.
See Appendix H
See Appendix H
Potential mostly when treater is Initial processor after
well head.
Applicable on saltwater outlet primarily.
I
CO
NOTES: (1) Spill Crlticallty Rating of Priority In Accordance With Table 4-9.
(2) Spill Crlticallty Rating of Routine In Accordance With Table 4-9.
(3) Spill Crlticallty Rating of Potential In Accordance With Table 4-9.
-------
Table 4-26. Production System Spill Prevention Guidelines, Local Storage Subsystem
System Spill
Event Type
Overflow
Applicable Equipment
or Component
Tank, Sumps
Firewall
Tank
Tank or Sump
Associated Equipment
Cause
il;
Negligence
O/M Error
Fire. Over-( '
Flow, Rain
Foundation (3)
Failure
Lightening (Z)
Float Level (1)
Control
Failure
Pump or '
Pump Motor
Failure
Check <8>
Valve Open
In Drain
Line
Valve Frozen(3)
Closed
(Temperature)
Operator/ *2)
Maintenance
Left Up-
stream Valve
Open or Down-
Stream Valve
Shut
Preventive Action Guidelines
Provide Adequate Capacity.
Consider Equalization Lines.
Consider Formalized Job Description With Personnel
Requirements.
Educate and Train.
Design Firewall for Greater Capacity Than the Containment
Vessel It Surrounds.
Design Foundation Giving Consideration to Frosting and Thaw-
Ing Heaving and Provide for Proper Drainage from Foundation.
Require Flame Arrester.
Increase Maintenance and Inspection.
Consider Timor Switch with High/Low Override.
Increase Maintenance and Inspection.
Consider Redundant Pumps.
Consider Allowing Adequate Storage Capacity to Allow
For Worst Case Pump Repair or Replacement Times.
Increase Inspection, Maintenance, and Monitoring.
Consider Serially Redundant Check Valves.
Prohibit Use of Check Valves for Block Valve Function.
Consider Insulating Valve.
Consider Detailed Operation or Maintenance Procedures.
Educate and Train.
Remarks
Relative to Lease Stock Tanks.
Boiling Fluid Results In Requirement For Greater
Capacity.
Mostly Saltwater Skimmer Pumps.
-------
Table 4-26. Production System Spill Prevention Guidelines,
Local Storage Subsystem (Continued)
System Spill
Event Type
Overflow
(Continued)
Leak
Applicable Equipment
or Component
Tank or Sump
Associated Equipment
(Continued)
Power
Tanks
Tank Associated
Equipment
Cause
(3)
Third Party
Operated
Valve
(HI
Electricity
Loss
(1)
Externally
Corroded
Bottom
Other (1>
External
Corrosion
Internal (1)
Corrosion
Break fa (1)
Tank Shell
Corrosion ot
Fittings. Con-
nectors, et
cetera
Broken <2)
Gauges
Gaskets. <2)
Packing.
and Seal*
Preventive Action Guidelines
Lock Unattended Valves in Desired Position.
Consider Safety Shutdown and Alarm.
Consider Redundant (or Standby) Power Source.
Consider Sacrificial Cathodlc Protection.
Consider Crushed Rock Grading on Foundation for Drainage.
Paint and Galvanize.
Consider Conical Tank Bottom to Assure Complete Drainage.
Consider Liners or Paint on Inside of Tank If Sulphur Oil is
A Factor.
Design for Allowance of Thermal Movement.
Consider Scheduled Maintenance and
Inspection of Thief Hatches.
Increase Preventive Maintenance.
Provide Guard,
Increase Inspection and Preventive Maintenance.
Remarks
Especially Applicable to Offshore or Other Overwater Facilities.
See Appendix H
Designed to Alleviate Overpressure.
See Appendix H
NOTES: (1) Spill Crltlcality Rating of Priority in Accordance with Table 4-9
(2) Spill Critlcallty Rating of Routine In Accordance with Table 4-9
(3) Spill Critlcallty Rating of Potential In Accordance with Table 4-9
-------
Table 4-27. Production System Spill Prevention Guidelines, Separation Subsystem
System Spill
Event Type
Overflow/
Overpressure
Applicable Equipment
or Component
Dump Valve
on Separator* and
Scrubber*
Backpressure
Regulator Valve
Cause
(2)
Falls Open
(General)
(2)
Falls Open
(Sand or Flow
Cut)
Falls Open *>
(Sanded Up)
Falls Open <*'
(Instrument
Gas Loss)
Fall* Open
(Ruptured
Diaphragm)
Falls ClosecP
(General)
Falls Closed
(Sanded Up)
Falls Closed
(Hole In Float)
Falls Closed
(Valve Spring)
Falls Closed
(Level Control
Linkage)
Falls Open <3>
(General)
(3)
Falls Open
(Mlsadjust-
ment)
(3)
Falls Open
(Vibration)
Preventive Action Guidelines
Low Level Shut-in and Alarm Desirable.
Consider Hard Valve Trim.
Consider Scrubber on Flare or Secondary Containment
Downstream.
Consider Increased Routine Maintenance on Sand Cleanout,
Desirable to Have Stand-By Instrument Gas Source. Most
Desirable to Have Primary Source to be Independent of
the Gas In the Pressure Vessel.
Routine Overhaul.
Desirable to Rave High Level Shut-In and Alarm. '
Pipe Overflow to Sump or Secondary Containment.
Consider Increased Routine Maintenance on Sand Cleanout.
Consider Sand Jets on Separator.
Check Float Material.
Consider Stainless Steel or Plastic Float.
Consider Routine Overhaul.
Increase Inspection and Maintenance,
Desirable to Have High Level Shut-in and Alarm.
Consider Installing Scrubber on Flare or Gas Sales Line.
Increased Test and Maintenance.
Consider Tlelng Backpressure Regulator to Dump Valve Control
Linkage by a "Floating" Lever.
Increase Teat and Maintenance
Consider Tlelng Backpressure Regulator to Dump Valve Control
Linkage By A "Floating" Lever.
Remarks
May Cause Spill Downstream.
Most Probably Occurring In High Pressure Operations.
Most Probably Occurring In Low Pressure Operations.
Applicable to Gas Operator Dump Valves.
Can Result in Overflow to Gas Line, Out Relief Valve, or Out
Rupture Disc.
Most Probably Occurring In Low Pressure Operations.
See Appendix H
Liquid Will Flare Into Gas Line.
Applicable to Mechanical Control Linkages Only.
t
OS
-------
Table. 4-27. Production System Spill Prevention Guidelines, Separation Subsystem (Continued)
System Spill
Event Type
Overflow/
Overpressure
(Continued)
Leak
Applicable Equipment
or Component
Back Pressure
Regulator Valve
(Continued)
Belief Valve
Rupture Disc
Miscellaneous
Vessel Shell
Connection*, Valve
Trim, et cetera
Cause
<3>
Falls Open
Falls Open
(General)
(2)
Falls Open
(Wrong Disc)
Falls Open(2)
(Corrosion)
(2)
Bursts Open
(Disc Func-
tion was
Normal)
Surge <3>
(3)
Corrosion
(3)
Metal
Fatigue
Sand or (2>
Flow Cut
Preventive Action Guidelines
Consider Insulation If Icing Is Caused From External Tempera-
ture. Consider Inhibitors If Icing Is Due to Gas Expansion
and/or Cooling Effect of Reducing Pressure Across Valves.
Consider High Level and Pressure Shut -fa and Alarm,
Pipe Overflow to Sump or Secondary Containment.
Consider Low Pressure Sensor on H. P. Separator.
Pipe Overflow to Sump or Secondary Containment.
Consider High Level and Low Pressure Shut-in.
Increase Test and Inspection,
Pipe Overflow to Sump or Secondary Containment.
Consider High Level and High and Low Pressure Shut-in
and Alarm.
Check Application and Replace With Proper Disc.
Coat Disc With CosmoUne.
Consider Changing Configuration to Protect Disc From
Corrosion.
Inspect and Replace More Frequently.
Check For Dump Valve Falling Closed.
Check For Plugged Oil Outlet or Dump Valve.
Check for Failed Relief Valve.
Check for Backpressure Regulator Valve Falling Closed.
Consider Throttling and Surge Dump Valve Configuration.
Consider Capability of Switching to Another Separator.
Check For Upstream Condition Causing Surge.
Consider Use of Inhibitors For Internal Corrosion.
Consider Increase Maintenance.
Consider Checking Procedures For Pressure Testing
and Inspection.
Consider Choke At Inlet to Separator.
Consider Ute of Abrasive Resistant Materials In Critical Areas.
Remarks
Liquid Will Overflow Through Relief Valve or Rupture Disc.
Liquid Will Overflow Through Relief Valve.
Liquid Will Overflow Through Rupture Disc.
See Appendix H
See Appendix H
r
-------
Table 4-27. Production System Spill Prevention Guidelines, Separation Subsystem (Continued)
System Spill
Event Type
Leak
(Continued)
'Applicable Equipment
or Component
Connections, Unions,
Et Cetera
Sight Glasses,
Gauges, et
cetera
Cause
(3)
Operator/
Maintenance
Incurred
Damage
Internal
Corrosion
External (3)
Corrosion
Breakage ( '
Preventive Action Guidelines
Educate Personnel on Proper Application,
Educate Personnel on Proper Make-Up Procedures.
Perform Inspection of Repair.
Provide Proper Tools.
Consider Injection of an Inhibitor.
Consider Increased Inspection.
Consider Heavier Parts.
Consider Corrosion - Resistant Coating and Material.
Put Protection Guards on Items.
Hemnrks
See Appendix H
00
NOTES: (1) Spill Crltlcallty Rating of Priority In Accordance with Table 4-9
(2) Spill Criticallty Rating of Routine In Accordance with Table 4-9
<3| Spill Crltlcallty Rating of Potential In Accordance with Table 4-9
-------
Table 4-28, Production System Spill Prevention Guidelines, Safety Subsystem
Safety System
Failure Event
Type
Fails to Shut-In
on High or Low
Level
Falls to Shut-In
on High or Low
Level or Pressure
Falls to Shut-in
Applicable Equipment
or Component
High or Low Level
Sensor
High and Low .Level
and Pressure
Relay Valve
Surface Safety
Valves
Cause
(4)
Hole in Float
(4)
Level Linkage
Fouled
(3>
Control Line,
Blockage Be-
tween Sensor
and Relay
Valve
Pilot Exhaust (3>
Plugged
Mlsadjusted <3>
Pilot Sensor <3>
Plunger Stuck
Diaphragm '
Leak
Valve Stem <2>
Seal Leak
Valve Stem or(Z>
Spring Hung-Up
Blockage In (2)
, Control Line
From Relay
Valve to
Actuator
Valve Cut Out <2)
Stem or Piston* '
Hung-up or Stuck
Preventive Action Guidelines
Cheek Float Frequently,
Use Stainless Steel or Plastic Float.
Increase Inspection and Maintenance.
Check and Clean During Reassembly Activities.
Filter and Dehydrate Gas or Hydraulic Fluids.
Check Routing of Control Line for Areas of Potential
Line Kinks and Protect.
Avoid Use of Neoprene Seals in Hydrayllc System.
Check and Clean During Reassembly Activities.
Filter Gas or Hydraulic Fluids.
Inspect for Frozen Moisture In Exhaust Port.
Frequent Inspection, Test, and Readjust as Required.
Check for Defective Spring.
Routine Inspect, Test, and Maintenance.
Routine Inspect, Test, and Maintenance.
Use Caution and Care During Maintenance,
Routine Overhaul.
Use Care During Maintenance to Preclude Gouging,
Et cetera.
Check and Clean During Reassembly Activities.
'Filter and Dehydrate Gas or Hydraulic Fluids.
Check Routing of Control Line for Areas of Potential
Kinks and Protect.
Consider Abrasive Resistant Valve Trim.
Consider Installing on Downstream Side of Choke.
Consider Routine Inspection, Test, nnd Overhaul.
Routine Inspection. Test and Overhaul.
Remarks
Spill Critlcallty Rating' ' for Sensor on Tanks, Sumps, L. P.
Separators, and Heater Treaters;*2* for those In Scrubbers
See Appendix J
See Appendix H
See Appendix J
Can Occur Under High or Low Pressure or tow
Temperature Conditions.
I
«0
-------
Table 4-28. Production System Spill Prevention Guidelines, Safety Subsystem (Continued)
Safety System
Failure Event
Falls to Shut-In
(Continued)
Subsurface Safety
Valve Failure
Applicable Equipment
or Component
Surface Safety Valves
(Continued)
Velocity-Control-
led Subsurface
Safety Valve and
Surface Controlled
Subsurface Safety
Valve
Velocity-Control-
led Subsurface
Safety Valve
Surface Controlled
Subsurface Safe-
ty Valve
(3)
Manually Locked
Out
Sanded Up or ' '
Cutout
Initial Misinter-
pretation of Well
Data
Failure to Reset'
Safety Valve for
Changing Flow
Characteristics
Misapplication*3'
for Certain
Condition*
(3)
Fouled Up With
Sand or Paraffin
(3)
Same Problem*
Which Occur on
Surface Safety
Control Line*
Preventive Action Guideline*
Procedure to Assure that Valve Will be Put Back Into Fall -Safe
Operation After Every Activity Which Requires Manual Lock Out
1* Completed,
Routine Testing and Inspection.
Procedure for Inspection After Short Operational Duration After
Initial Installation.
Well Should be Brought In, Cleaned and Potentiated Prior to
Selection and Installation of Subsurface Safety Valve.
Regular Monitoring of Current Flow Conditions and Test and
Inspection on a Regular Basis.
Consider Surface Controlled Subsurface Safety Valve as It
I* Impervious to Changing Well Flow Condition*.
Check to Determine if Blowout Condition* on Exist Outside
the Predetermined Condition* to Which the Valve 1* Designed
or Set to Close.
Consider Surface Controlled Subsurface Safety Valve.
Install Deep Enough to Preclude Paraffin from Accumulation*.
Routine test and Inspection.
See Above for Hydraulic Problems.
Remarks
See Appendix J
c!n
o
NOTES; (1) Spill Critlcallty Rating of Priority In Accordance with Table 4-9
(2) Spill Critlcallty Rating of Routine In Accordance with Table 4-9
(3) Spill Critlcallty Rating of Potential In Accordance with Table 4-9
(4) See Remark* Column for Spill Critlcallty Rating of High Level
Sensor* on Various Equipment
-------
Table 4-29. Gathering/Distribution System Spill Prevention Guidelines,
Pipeline and Gathering Subsystems
System Spill
Event Tjrpe
Overpressure/
Overflow
Leak
Applicable Equlpmeot .
OT CompoDent
Pipe. Check Valves.
Relief Valves, Etc.
Pipe
Cause
(2)
General
(2)
Burst/Rupture
or Split
External ?!
Corrosion (See
Appendix H)
Internal (1)
Corrosion (See
Appendix H)
Preventive Action Guidelines
Check and Install High and Low Pressure Sensors to Alarm or
Shutdown the Pump.
Check or Install Downstream Valve Status Sensor to Alarm
or Shutdown Pump.
Check or Install Pressure Relief Valve and/or Rupture Disc.
Inspect Inline Check Valves - Consider Serially Redundant
Check Valves.
Periodic (Air and/or Ground) Line Patrol for Evidence of Leak.
Periodic Inspection (At Least at Suspected Vulnerable Points) of
Pipe Wall Thickness by Ultrasonic or Other Suitable Methods.
Survey and Scanning Pig Program for Wall Thickness and
Evaluation.
Check if Corrosion Involved and See Below.
Check for Safety Shutdown Devices and Relief Devices of Short
Reaction Time and Pressure Sensitivity Consistent With the
Pipe Discharge Capacity,
Check Compliance With Line Pressure Operational Limits.
Pig the Line to Remove Water Trapped at Low Elevation Points.
Check or Install Provision to Avoid Shock Loads (Water
Hammer Effect).
Accelerated Inspection and Replacement Schedule for Weakened
Pipe.
Reduce Line Pressure in Lines With Weakened Pipe.
Check (Or Apply When Feasible)
Sacrificial Cathodlc Protection System.
Check (Or Apply) External Wrapping or Coating
Consider Possible Effect of Local Conditions Creating
Unusual Subsurface Electrical Potential Including
Ground and Overhead Power Transmission Lines and
Industrial Facilities With Large Electrical Power
Requirements Grounded Into the Earth's Surface. A
Program of Electrical Surveys (When Appropriate) To
Determine Areas of Active Corrosion for Remedial
Attention.
Check or Add Inhibitors to the Fluid.
Pig the Line to Sweep Water from the Line.
Consider Application of Internal Coating to Pipe.
"Slug" the Line to Treat the Pipe Wall With a Corrosion
Inhibitor.
Consider Possible Internal Long Line Galvanic Coll
Action in Coated and Cathodlcally Protected Pipe.
Remarks
See Appendix J
To Relieve Into Containment Tank and to Alarm or Shutdown Pump.
To Detect Leaks.
To Eliminate Leaks.
Primarily to Limit Size of Spill.
If Pipe Above Frost Line.
Particularly After Repeated Patching or Clamping of Leaks.
New Installation (Replacement)
en
-------
Table 4-29. Gathering/Distribution System Spill Prevention Guidelines ,
Pipeline and Gathering Subsystems (Continued)
System Spill
Event Type
Leak
(Continued)
Applicable Equip neat
or Component
Pipe (Continued)
Cause
<*)
Defective
Material
Defective **'
Welds
Third Party <*'
Incurred
Breaks In
Line
Preventive Action Guidelines Remarks
Draw Specifications to Match Application.
Require Certification of Specification in Purchase Contract.
Require Evidence of Quality Assurance Program In
Selection of Pipe Manufacturer.
Perform Close Inspection and (As a Minimum) Perform
Sample Tests to Pipe Specifications.
Pressure Test with Water Before Approval for Use For
Petroleum Transmission.
Require Welding Only by Certified Welder.
Require Beit Available Welding Rod Equipment, Practice
and Technology for Each Particular Application.
Inspect Welding Results and Monitor Procedure.
Mark Pipe Location at Points Vulnerable to Collision!.
Patrolling and Monitoring Surveillance.
Exchange Information and Educate.
Document Routing and Depth.
For New Design and Equipment Pipe Purchase.
01
to
NOTES: (1) Spill CritlcaUty Rating of Priority In Accordance with Table 4-9
(2) Spill CritlcaUty Rating of Routine In Accordance with Table 4-9
-------
Table 4-30. Gathering/Distribution System Spill Prevention Guidelines, Storage Subsystem
System Spill
Event Type
Overflow
Applicable Equipment
or Component
Tank
Firewall
Tank Associated
Equipment
Power
Cause
<2)
O/M Error
Lightening <8)
Foundation <3)
Failure
Fire, Overflow'.3*
Rain
General <"
Pump or Pump
Motor Failure
Operator/ <2>
Maintenance
Left Upstream
Valve Open or
Downstream .
Valve Shut
Third Party <8>
Operated
Valve
Check Valve W
Falls Open
Valve Frozen <3>
Closed Tempera-
ture
Float Level <3>
Control
Failure
Electricity (')
Lews
Preventive Action Guidelines
Consider Equalization Lines.
Consider Formalized Job Descriptions and Written Operational
Procedures.
Educate and Train.
Require Flame Arresters,
Design Foundation Giving Consideration to Frost/Thaw-Induced
Heaving and Drainage to Prevent Standing Water
Design Firewall for Greater Capacity Than the Tank It Surrounds.
Require Sufficient Separation Between Tanks and Require An
Individual Firewall for Each Tank.
High Level Sensors to Shut Down Upstream Pump and/or
Alarm to Manned Control Station.
Increase Maintenance and Inspection.
Consider Redundant Pumps.
Consider Allowing Adequate Storage Capacity to Allow
For Worst Case Pump Repair or Replacement Times.
Consider Detailed Operation or Maintenance Procedures,
Educate and Train.
Lock Unattended Valves in Desired Position.
Increase Inspection, Maintenance, and Monitoring.
Consider Serially Redundant Check Valves.
Consider Insulating Valve.
Increase Maintenance and Inspection.
Consider Safety Shutdown and Alarm,
Consider Redundant (or Standby) Power Source.
Remarks
See Appendix H
Boiling Fluid Results In Requirements for Greater Capacity.
Necessary to Preclude Potential of Fire Being Spread to
Other Tanks.
See Appendix J
See Appendix H
See Appendix J
CI
-------
Table 4-30. Gathering/Distribution System Spill Prevention Guidelines, Storage Subsystem
(Continued)
System Spill
Event Type
Lrak
Applicable Equipment
or Component
Tank*
Tank Associated
Equipment
Cause
(«)
Externally
Corroded
Bottom
External (3)
Corroalon
Internal
Corroilon
Break In (8)
Tank Shell
Corroiloo of
Fittings, Con-
nectors, et
cetera
Broken <»>
Oauges
Gaskets, (3)
Packing.
and Seals
Preventive Action Guidelines
Consider Sacrificial Cathodlc Protection.
Consider Crushed Rock Grading on Foundation.
Paint and Galvanize.
Consider Conical Tank Bottom to Assure Complete Drainage.
Consider Liners or Paint on Inside of Tank if Sulphur Oil Is
A Factor.
Design for Allowance of Thermal Movement.
Increase Preventive Maintenance.
Provide Guard.
Increase Inspection and Preventive Maintenance.
Remarks
Bee Appendix H
See Appendix H
NOTES: (1) Spill Crltlcaltty Rating of Priority In Accordance with Table 4-9
(2) Spill Crltlcallty Rating of Routine In Accordance with Table 4-9
(3) Spill Crltlcallty Rating of Potential In Accordance with Table 4-9
-------
BIBLIOGRAPHY
-------
BIBLIOGRAPHY
1. Report of the Ad Hoc Committee, State Regulations and Practices, Oil and
Gas Operations and Oil Pollution, State of California Resources Agency,
June 1969.
2. Issue Paper, Program for Management of Leased and Leasable Minerals.
U.S. Geological Survey, May 1969.
3. Code of Federal Regulations, Title 30: Mineral Resources. U.S. Department
of the Interior, Geological Survey, December 1968.
4. Code of Federal Regulations, Title 43, and the Outer Continental Shelf Lands
Act, 67 Stat. 462, U.S. Department of the Interior, undated.
5. Notice to Lessees and Operators of Federal Oil, Gas, and Sulphur Leases In
the Outer Continental Shelf Gulf Coast Region; OCS Order Nos. 1 through
11Gulf of Mexico, United States Department of the Interior, Geological
Survey Conservation Division Branch of Oil, and Gas Operations Gulf Coast
Region, 28 August 1969.
6. Environmental Impact Statement (Draft), U.S. Geological Survey, 23 February
1971.
7. Environmental Impact Statement (Draft), U.S. Geological Survey, 10 May 1971.
8. The Offshore Petroleum Resource, The Resources Agency of California, 1970.
9. Pollution Control Report, Parts I, II and III, Ocean Industry, June-August 1970.
10. Outer Continental Shelf, Oil Gasr Sulfur and Salt, Leasing, Drilling. Production,
Income and Related Statistics. 1953 through 1970, U.S. Department of the
Interior, Geological Survey, Conservation Division, April 1971.
11. Mineral Production. Royalty Income, and Related Statistics on Oil. Gas, and
other leasable Minerals, Federal and Indian Lands. U.S. Department of the
Interior, Geological Survey, Conservation Division, 1969.
12. Texas Oil and Gas Conservation Laws, Title 102 Revised Civil Statutes of
Texas, Railroad Commission of Texas, January 1971.
13. QUARTERLY REVIEW OF DRILLING STATISTICS FOR THE U/S., API, Division
of Statistics and Economics.
14. General Conservation Rules and Regulations of Stateside Application, State of
Texas, The Railroad Commission of Texas, January 1971.
15. The Public and the Pipeline Industry - Report on the 21st Annual Pipeline
Conference, API, April 1970
BL-1
-------
BIBLIOGRAPHY (Continued)
16. Progress With Responsibility in the Seventies - Report on the 22nd Annual
Pipeline Conference, API, April 1971.
17. Report on Air and Water Conservation Expenditures of the Petroleum Industry
in the U. S.. 1966-1970. AH, February 1971.
18. JOURNAL OF ENVIRONMENTAL SYSTEMS, Baywood Publishing Company,
Inc.
19. Primer of Oil and Gas Production, API, 1962.
20. Introduction to the Oil Pipeline Industry. Petroleum Extension Service, The
University of Texas, May 1966.
21. Drilling/Production. Rules-of-Thumb Handbook. 4th Edition, Reprinted from
WORLD OIL, Gulf Publishing Co., 1971.
22. Oil Pipeline Pumping Station Operation - Volume IV, Petroleum Extension
Service, The University of Texas.
23. Oil Pipeline Construction and Maintenance - Volume II, Petroleum Extension
Service, The University of Texas, February 1953.
24. Environmental Conservation. The Oil and Gas Industry. Vol. I/A, Summary -
Report of the National Petroleum Council's Committee on Environmental
Conservation, National Petroleum Council, June 1971.
25. Engineering Design Handbook. Reprinted from PIPELINE INDUSTRY, Gulf
Publishing Company, 1969.
26. Annual Statistical Review - U. S. Petroleum Industry Statistics. 1956-1970.
API - Division of Statistics and Economics, April 1971.
27. Texas Oil and Gas Handbook. RW Byram & Company, 1970.
28. Report to the President: Environmental Science - Challenge for the Seventies.
National Science Board, 1972.
29. Pipeline. Rule of Thumb Notebook. Reprinted from: PIPELINE INDUSTRY, Gulf
Publishing Company, 1967.
30. Crude Oil Tanks; Construction. Strapping. Gauging and Maintenance. Petroleum
Extension Service, University of Texas, 1968.
31. Gas/Oil Production Practices Handbook - Reprinted from WORLD OIL, Gulf
Publishing Company, 1971.
32. JOURNAL OF PETROLEUM TECHNOLOGY, Society of Petroleum Engineers
of AIME, July 1971.
BL-2
-------
BIBLIOGRAPHY {Continued)
33. PETROLEUM TODAY, API, Published Quarterly.
34. PIPELINE INDUSTRY, Gulf Publishing Company.
35. MARINE TECHNOLOGY SOCIETY JOURNAL, Marine Technology Society.
36. PIPELINE AND GAS JOURNAL, Petroleum Engineering Publishing Company.
37. WORLD OIL, Gulf Publishing Company.
38. Don R. Boling, Some Aspects of the Use of Electrostatic Coalescience in the
Dehydration of Gulf Coast Crudes. Doc. No. 926-11-D, API reprint from
National Tank Company, March 1966.
39. How an Old Giant is Faring. OIL & GAS JOURNAL (reprint), July 1968.
40. F. J. Allen, Jr., Are We Really Drilling as Well as We Could? A paper
presented before AIME Study Group, March 1969.
41. Forms and Regulations for Reporting Oil Spills in Texas. Railroad Commission
of Texas, Oil and Gas Division, February 1970.
42. A Bill to Amend the Federal Water Pollution Act as Amended, No. S. 1014 and
S. 523, 92nd Congress, 1st Session, February 1971.
43. An Act to Amend the Clean Air Act to Provide for a More Effective Program
to Improve the Quality of the Nation's Air - An Act to Extend and Strengthen
the Water Pollution Control Act.
44. Notice to Lessees and Operations of Federal Oil and Gas Leases in the Outer
Continental Shelf, Gulf Coast Region, OCS Lease Management Program,
Gulf of Mexico. USGS, 27 May 1971.
45. Federal Water Pollution Control Act, June 1970, U. S. Department of the
Interior.
46. SAFETY SYSTEMS AND AUTOMATIC CONTROL EQUIPMENT FROM OTIS,
OEC-5052, A-198, Otis Engineering Corp.
47. OCEAN INDUSTRY, Gulf Publishing Company.
48. OIL AND GAS JOURNAL, The Petroleum Publishing Company.
49. Clean Water for the 1970's - A Status Report. U. S. Department of the
Interior, June 1970.
50. Study on Spill Prevention Techniques for Hazardous Polluting Substances.
OHM 7102001, EPA, February 1971.
51. Proceedings of Joint Conferences on Prevention and Control of Oil Spills,
15-17 June 1971. API, June 1971.
52. Newsletter from International Association for Pollution Control. IAPC,
June 1971.
BL-3
-------
BIBLIOGRAPHY (Continued)
53. A Report to the President on Pollution of the Nation's Waters by Oil and
Other Hazardous Substances. Secretary of Interior & Secretary of Trans-
portation, February 1968.
54. The Porter-Cologne Water Quality Control Act and Related Water Code
Sections, California State Water Resources Control Board, November
1970.
55. Notice to Lessees and Operators of Leases in the Outer Continental Shelf.
Pacific Region, OCS Order No. 10, U. S. Department of Interior,
28 March 1969.
56. Pamphlet: Conservation in Alberta. Energy Resources Conservation Board,
1970.
57. Report of the Operations of the Oil and Gas Conservation Board. SRCB 71-12,
ERCB, 1970.
58. Monthly Statistics - Alberta Oil and Gas Industry. J^RCB 71-03, June
1971.
59. Catalog of Publications - Services. Maps. ERCB.
60. Guide to Minimum Surface Casing Requirements. IL 69-11, Oil and Gas
Conservation Board, October 1969.
61. The Oil and Gas Conservation Act - Oil and Gas Conservation Regulations -
Office Consolidation, ERCB.
BL-4
-------
GLOSSARY
-------
GLOSSARY
Accumulator - A device which stores liquid under air pressure to hydraulically
operate blowout preventers.
ACT - "Automatic Custody Transfer, " a system for automatically measuring and
sampling oil or products at points of receipt or delivery other than leases.
Allowable - Amount of oil or gas that a well is permitted by State authorities to
produce during a given period.
Annular Blowout Preventer (BOP) - A device which can seal around irregularly
shaped objects of an open hole. Compression of a reinforced rubber packing
element by hydraulic pressure actuates the device.
API - American Petroleum Institute
API Gravity - Gravity (weight per unit of volume) of crude oil as measured by a
system recommended by the API.
Atmospheric Degasser - A vessel operating at atmospheric pressure which provides
for natural separation of gas from gas-cut mud encountered in drilling.
(Also see Vacuum Degasser).
Back Pressure - Pressure resulting from restriction of full natural flow of oil or
gas.
Back Pressure Regulator or Back Pressure Valve - A valve which controls pressure
upstream of the valve.
Barite - An additive to drilling mud. Used to weight the mud.
Barite Recovery Unit (Mud Centrifuge) - A means of removing less dense drilled
solids from weighted drilling mud to conserve Barite and maintain proper
mud weight.
Barrel - 42 United States gallons at 60° Fahrenheit.
Batch - A definite amount of oil, mud, acid, or other liquid in a tank or pipeline.
Battery - One or more tanks for storage.
Beam Pump - Similar to Rod Pump.
Beam Well - A well using a pumping jack or unit and rods to lift fluid.
Bell Nipple - Also called "mud riser" or "flowstack." Consists of a casing nipple
installed in the top of the preventer with "belled" or expanded top to guide drill
tools into the hole. Has side connections for fill line and mud-return line
(flowline).
Bentonite - An additive to drilling mud. Used to increase mud viscosity.
GL-1
-------
Flange (also a blind flange) - A solid disk used to dead end a companion flange.
Blank Liner - A liner without perforations.
Bleeder - A valve or pipe through which internal pressure is released.
Bjeeji Off or Bleed Down - Reduce pressure by letting oil or gas escape at a low rate.
Blind Ram Blowout-Preventer - Also called TrBlank ram" and "master gate." They
seal against each other and completely shut off the hole below.
jflowcase - A pressure vessel used to propel fluids intermittently by pneumatic
pressure.
Blowout - A wild and uncontrolled flow of subsurface formation fluids at the earth's
surface.
Blowout Underground - An uncontrolled flow of fluids from one subsurface formation
into another by way of the well bore without reaching the earth's surface.
Blowout-Preventer (BOP) - A device to control formation pressures in a well by
closing the annulus when pipe is suspended in the well or by closing the top of
the casing at other times.
Blowout-Preventer Drill - A practice procedure in which men follow the same
procedure they would for an actual blowout (see Pit Drill).
Blowout-Preventer Operating and Control System - Assembly of pumps, valves,
lines, and other items necessary to open and close the blowout-preventer
hookup. Includes Accumulator.
Blowout-Preventer Rams - Closing and sealing components of a preventer.
Correspond to the gate in a gate valve.
Blowout-Preventer Stack (BQJPs) - Assembly of well and pressure control equipment
connected to the top of the casinghead during drilling or workover.
Bonnet - A removable portion of an equipment housing which provides access to
inner workings.
Bottom-Hole Pressure - Pressure at the bottom of a well (see Formation Pressure).
Bottom Sampling - Obtaining a sample by collecting a portion of material on the
bottom of a container or pipeline.
Box. Stuffing - (Also called a Packing Gland) - A device containing sealing material
to prevent fluid leakage between moveable metal parts of equipment, including
rod pumps, centrifugal pumps, and valves.
BS&W - Basic sediment and water measured with oil. Generally pipeline regulation
limits the contents of BS&W to 1 percent of the volume of oil.
Bull Plug - A short plug with male threads at one end.
Burp Pit - An earthen pit in which waste oil and other materials are burned.
GL-2
-------
Casing - Large steel pipe used to "seal off or "shut out" water and prevent caving
of loose gravel formations when drilling a well. When set, drilling continues
through and below the casing with a smaller bit. The overall length of this
casing is called the string of casing. More than one string inside the other
may be used in drilling the same well.
Casinghead - A flanged connection between the top of the casing and the BOPs or
next casing spool.
Casingfaead Gas - Gas that is produced along with oil from an oil well.
Casing Pressure - Gas pressure built up between the casing and tubing.
Centrifuge - A shake-out or grind-out machine. Samples of oil are placed in the
machine and whirled at high speed to settle out sediment for measurement of
BS&W.
Check Valve - A valve which permits flow in only one direction.
Chemical-Electrical Treater - A vessel which utilizes surfactant chemicals and an
electrical field to break oil-water emulsion (BS&W).
Choke - A device with either a fixed or variable aperture used to release the flow of
well fluids under controlled pressure.
Choke Bean - Removable or replaceable fixed choke, the purpose of which is to
throttle or control fluid flow.
Choke Body - Body or housing containing fixed or adjustable choke and necessary
operation controls.
Choke Flowline - An extension from the blowout-preventer assembly used to direct
and control the flow of well fluids from the annulus to the choke.
Choke Manifold - A manifold connecting chokes to the choke flowline.
Choke Target - A sacrificial wear surface designed to absorb the energy of high
velocity fluid discharge downstream of choke.
Christmas Tree - Assembly of fittings and valves at the top of the casing of an oil well
that controls the flow of oil from the well.
Closed-In - A well capable of producing oil or gas, but temporarily shut in.
Collar - A pipe coupling threaded on the inside.
Common Carrier - Any transportation system available for use by the public for
transporting cargo. Almost all pipelines are common carriers.
Condensate - Hydrocarbons which are in the gaseous state under reservoir conditions
but which become liquid either in passage up the hole or at the surface.
Control Panel - Master or Primary - A manifold system of valves, usually situated
at the power source, which may be operated manually (or by remote control)
to direct pressurized fluid to closing devices at wellhead (see Accumulator and
BOP Control System).
GL-3
-------
Control Panel - Remote or Secondary - A system of controls, convenient to the
driller, which can be used selectively to actuate valves at the master control
panel.
Coupling - Ordinary pipe collar.
Crown Block - Sheaves and supporting beams on top of derrick.
Cut Oil - Oil that contains water, also called wet oil.
Dead Well - A well that will not flow.
Degasser - A device for removing gas from drilling fluid, usually by vaduum.
Derrick and Substructure - Combined foundation and overhead structure to provide
for hoisting and lowering necessary to drilling.
Desander - Equipment, usually cyclone type, for removing drilled sand from the
drilling mud stream and from produced fluids.
Desilter - Equipment, normally cyclone type, for removing extremely fine drilled
solids from the drilling mud stream.
Development Well - A well drilled for production from an established field or
reservoir.
Dispatcher - An employee responsible for scheduling movement of oil through
pipelines.
Disposal Well - A well through which water (usually salt water) is returned to sub-
surface formations.
Dog-Leg - An abrupt change in the course of the bore hole.
Dog-Leg Severity - The relative severity of the change in course of a bore hole,
expressed in degrees of change per 100 feet of hole drilled.
DOT - Department of Transportation
Down Hole BOP - An open hole packer, controllable from the surface, which is run
in the drill string down hole while drilling for closing in wells when kicks occur.
Drill Collar - A heavy section of pipe run above drill b|it to provide bit weight for
drilling.
prilled Show - A showing of gas or oil from drilling a formation.
Driller - The individual shift supervisor responsible for on-location operation of a
drilling rig. He reports to the tool-pusher for that rig.
Drill Pipe - Special pipe designed to withstand the torsion and tension loads encountered
in drilling.
Drilling Line - Wire line, or steel cable, used in pulley system for hoisting and lower-
ing drillstem, casing, and other tools while drilling.
GL-4
-------
Drilling Mud -A susr jnsion, generally aqueous, used in rotary drilling to clean and
condition the hole and to counterbalance formation pressure; consists of various
substances in a finely divided state among which bentonite and barite are most
common.
Drilling Spool - A BOP stack connection having both ends equipped with flanges. It
usually has the same bore diameter as the blowout preventer. It may or may
not have side outlets for connecting auxiliary lines.
Dump Valve - A mechanically or pneumatically operated valve used on separator?,
treaters, and other vessels for the purpose of draining, or "dumping" a batch
of oil or water.
BCD - Equivalent Circulating Density. The effective drilling mud density during
circulation.
EPA - Environmental Protection Agency.
Failure Mode - Manner or way an item can fail.
Field - The area around a group of producing wells.
Fire Wall - A wall of earth built around an oil tank to contain the oil if the tank breaks
or burns.
FMEA - Failure modes and effects analysis. A reliability engineering technique used
to assess system element failure effects on overall system performance.
FRRC - Federal Railroad Commission.
Fittings - The pipe, elbows, tees, crosses, swages, reducers, and valves that are
used to make up a system of piping or manifold.
Flange - A bolted joint that provides a seal.
Flaring - The burning of volatile hydrocarbons in specially designed flares for safety
purposes.
Floating Roof - A special type of storage tank roof which floats upon the surface of
the product in the tank, thereby eliminating tank breathing and reducing evapora-
tion losses.
Flow Chart - A chart made by a recording meter which shows rate of flow of fluid.
Flowing .Veil - A well which produces oil or gas without any means of artificial lift.
Flowline (Drilling System) - Mud return line from bell nipple to shale shaker.
Flowlines (Production System) - Pipe through which oil travels from the well to storage.
Flow Tank - A lease storage tank into which produced oil flows after separation and
treatment.
Fluid Injection - Injection of gases or liquids into a reservoir to force oil toward and
into producing wells. (See also Water Flooding.)
GL-5
-------
Formation - Various subsurface geological strata penetrated by well bore.
Formation Pressure - See "Pore Pressure."
Fracturing - Application of excessive hydrostatic pressure which fractures the well
bore, causing lost circulation of drilling fluids.
Freewater Knockout - An oil/water separation tank (atmospheric pressure).
G_aging_ Nipple - A small section of pipe in the top of a tank through which a tank may
be gaged.
Gas-Cut Mud - Drilling fluid with entrained formation gas.
Gas Lift - A means of stimulating flow by aerating fluid column with compressed gas.
Gas-Oil Ratio - Number of cubic feet of gas produced with a barrel of oil.
Gate Valve - A valve which employs a sliding gate to open or close the passage in it.
Gathering Line - A pipeline, usually of small diameter, used in gathering crude oil
from the oil field to a point on a main pipeline.
Gauging - Determining the volumetric contents of a tank.
Girth or Girt - One of the horizontal braces between the legs of a derrick.
Gun Barrel - An oil-water separation vessel.
Hatch - An opening into a tank, usually through the top deck.
Hydrocarbon - A compound consisting only of molecules of hydrogen and carbon.
Hydrostatic Head - Pressure which exists in the well bore due to the weight of the
column of drilling fluid; expressed in pounds per square inch (psi).
Hydraulic Lift - A method of pumping which uses hydraulic energy as the power
medium. Crude oil is used as power oil and mixes with the well effluent after
power stroke.
Heater Treater - A vessel used to break oil-water emulsion with heat.
Header - A section of pipe into which several sources, such as well streams, are
combined.
I. C.C. - Interstate Commerce Commission. A Federal board which has jurisdiction
over pipelines engaged in interstate commerce.
Inhibitor - An additive which, when present in a petroleum product, prevents or
retards undesirable changes taking place in the product, particularly oxidation
and corrosion, and sometimes paraffin formation.
GL-6
-------
Insulating Flange - A flange which incorporates plastic pieces to separate the metal
parts, useful in cathodic protection.
Internal Preventer - Also called "inside blowout preventer. " A check valve placed in
the drill string which permits circulation down the hole but prevents any back
flow.
Joint - A length of pipe - usually from 20 to 45 feet long.
Kelly - A special joint of drill stem, usually square or hexagonal in cross-section.
that is used at the top of a drill stem to provide rotation for drilling.
Kelly^Cock - A valve installed in the drill string between the swivel and the kelly to
keep pressure off the swivel and rotary hose when necessary.
Kick - Flow of fluid caused by pressure from below in excess of that exerted by the
drilling fluid in the well. If efforts to control a kick are unsuccessful and the
subsurface pressure increases to the point where the expulsion of drilling fluid
is violent and uncontrolled, a blowout can develop.
Kill a Well - To overcome pressure in a well by use of mud or water so that surface
pressures are neutralized.
Kill Line - A line attached to some point in the blowout preventer assembly through
which drilling fluid can be pumped into the hole to subdue well pressure.
LACT Station - "Lease Automatic Custody Transfer" station; an automated system for
measuring and transferring oil from a lease gathering system into a pipeline.
Lease Tank - See Flow Tank.
Liner - A short length of smaller casing extending below and sealing with the last full
string of larger casing set in a well.
Location - Place at which a well is to be or has been drilled.
Log Book - Book used by station engineers and gaugers to keep notes of current opera-
ting conditions and other useful information.
Log Sheet - Daily report sheet on which operating data is entered by gaugers, dis-
patchers, and station engineers.
Main Line - A trunk pipeline.
Manifold - An arrangement of piping and valves to provide interconnecting links
between a number of pumps, tanks and lines at a pump station.
Manhole - A hole in the side of a tank through which a man can enter the tank; also the
cleanout plate.
Marginal Well - An oil or gas well the production of which is so limited in relation to
production costs that profit approaches the vanishing point (see Stripper Well).
GL-7
-------
Master Choke Line Valve - The valve on the choke and flowline which is nearest to the
preventer assembly. Its purpose is to stop the flow through the choke and flow-
line.
Master Gate - A large valve used to shut in a well.
Mud Density - Weight per unit volume of drilling fluid, usually expressed in pounds per
gallon or pounds per cubic foot.
Mud Line - Pipe through which mud is pumped.
Mud Pit - A steel or earthen tank which is part of the surface drilling mud system.
Mud Pump - A reciprocating, high pressure pump used for circulating drilling mud.
Mud-Weight Recorder - An instrument installed in the mud system which mechanically
weighs the mud and records its weight.
Multiple Completion - A well completion which provides for simultaneous production
from separate zones.
Nipple - A short length of pipe with male threads at each end.
PCS - Outer Continental Shelf
Offshore - In this context, the submerged lands between shoreline and the edge of the
continental shelf.
OHM - Oil and Hazardous Material
Oil/Leg - An arrangement for drawing off treated oil from a treater, including dump
valve arrangement.
Onshore - Dry land, inland bodies and bays, and tidal zone.
OSC - On-Scene Coordinator
Packer - A device run downhole in the tubing string to pack off and provide a seal
between the tubing-casing annulars.
Packing Gland - A stuffing box.
Pack-Off or Stripper Preventer - Preventers having a unit of packing material whose
closure depends upon well pressure coming from below. They are used pri-
marily to strip pipe through the hole or allow pipe to be moved with pressure on
the annul us; also annular preventer.
Paraffin - A heavy hydrocarbon sludge from crude oil.
Pig - A scraping tool forced through a flowline or pipeline to clean out paraffin or
other deposits.
Pig Trap - See Scraper Trap.
Pipeline Oil - Crude oil whose BS&W and water content is low enough to make the oil
acceptable for pipeline shipment.
GL-8
-------
Pipe Ram BOP - Rams designed to close around pipe to effect an annular seal.
Pit Drill - Blowout prevention close-in procedure carried out by crew on a surprise
basis initiated by deliberate tripping of pit level alarm.
Pit-Level Indicator - A device installed at the mud pits to register the level of mud in
the pits continuously. May have remote recorder on the rig floor.
Plug Valve - A valve whose operating mechanism consists of a plug with a hole through
it on the same axis as the fluid line. Turning the plug 90° opens or closes the
valve.
Polished Rod - A pump rod with polished wear surface for operating through a packing
gland.
Pop Safety Valve - See relief valve.
Pore Pressure (or Formation Pressure) - Natural pressure of a formation, usually
expressed in terms of mud weight.
Pressure Regulator - A valve which controls pressure in a line downstream from the
valve.
Precipitator - A water treating tank designed to promote precipitation of suspended
solids and filter removal of finely divided oil particles.
Proration - A system of regulation which limits the amount of oil which can be pro-
duced from a particular well or field within a given period.
Proving Tank - A device used to calibrate meters used in metering oil.
Pump, Centrifugal - A pump whose propulsive effort is effectuated by a rapidly turning
impeller.
Pump, Positive Displacement - Rotary pumps that move fluids by positive displacement
using a system of rotating vanes, gears, or lobes.
Pump, Reciprocating - A pump whose propulsive effort is achieved by reciprocating
motion of pistons or plungers operating in cylinders.
Rank Wildcat - An exploratory well drilled in an area far enough removed from pre-
viously drilled wells to preclude extrapolation of expected hole conditions.
Relief Valve - A valve that will vent automatically when the preset pressure is exceeded.
Used to prevent damage to vessels by excessive pressures.
Relief Well - A well drilled to combat a blowout; used to channel mud to the blowing well.
Reservoir - Each separate, unconnected body of producing formation.
Riser - A pipe through which liquid travels upward.
Rod Pump - Method of artificial lift by which a pump is reciprocated in a well by
means of a string of rods.
Rotary Hose - A flexible pressure hose for circulation while drilling, providing for
vertical movement of drill string.
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Rotary Hook - Device for handling load connecting traveling block to swivel or elevator
links.
Rotary Table - A device centered over the bore hole to provide for rotation of drill stem
while drilling and to support weight of drill pipe or casing when going in or out of
hole.
Rupture Disc - An expendable disk calibrated to rupture at a specific pressure for the
protection of a pressure vessel. Usually used to "back up" a Pop Safety Valve
or Relief Valve.
Sanded Up - Clogged by sand.
Scraper - A device used to clean deposits of paraffin from tubing or flow lines (see Pig).
Scraper Trap - Special piping arranged to launch or receive a pipeline scraper.
Scrubber - Equipment used to extract entrained liquids from natural gas.
Sensor. Level - A device sensitive to the level of fluids in a vessel.
Sensor. Pressure - A device that is sensitive to the internal pressure of a vessel.
Separator - A vessel used to separate oil and gas by gravity segregation.
Shake Out - Centrifuge to spin a sample of oil at high speed to determine its BS&W
content.
Shale Shaker - Mechanical vibrating screen to separate drilled formation cuttings carried
to surface with drilling mud.
i
Shut In - To close valves on a well so that it stops producing; said of a well on which the
valves are closed.
Shut-In Pressure - Pressure at the top of a well when it is shut in.
Skimmer - A settling tank in which oil is permitted to rise to the top of the water and
is then taken off.
Sour Crude Oil - Oil containing hydrogen sulfide or other sulfur compounds.
Sour Gas - Gas containing hydrogen sulfide.
Spacing - Distance between wells producing from the same pool (usually expressed in
terms of acres, e. g., 10-acre spacing).
Stand Pipe - Vertical portion of mudline connected to rotary hose, permitting sufficient
vertical travel of the kelly.
Stock Tank - See Flow Tank.
Strainer - A screen for stopping trash.
Stripper Well - A well which produces such small volume of oil that the gross income
therefrom provides only a small margin of profit or, in many cases, does not
even cover actual cost of production {see Marginal Well).
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Stripping - Adding or removing pipe when well is pressured without allowing vertical
flow at top of well.
Stuffing Box - A packing gland.
Subsurface Safety Valve - A differential pressure operated valve that shuts in a producing
well on a signal denoting downstream damage or breaks.
Sump System - A system of drains and catch tanks for capturing and gathering fluids
that fall in a given area.
Surface Controlled Subsurface Safety Valve - A subsurface safety valve controlled from
the surface for the purpose of shutting in a well in event of damage or break
downstream.
Surge Pressure - Pressure generated below the bit or casing shoe by the "plunger
effect" of the drill string or casing string being lowered into the well. This
increase in pressure can cause the BCD to exceed the fracture gradient of the
formation and result in lost circulation.
Swabbing - Lowering the hydrostatic head momentarily, caused by pulling pipe too fast.
Swab Pressure - Pressure generated by the "swabbing effect" of too rapid withdrawal
of the drill string from the well. This can induce "feed-in" from the formation,
thus reducing the equivalent mud density and resulting in an ECD that is lower
than the formation pore pressure.
Swage - A male pipe reducer.
Sweet Crude Oil - Oil containing little or no sulfur, especially in the form of hydrogen
sulfide.
Swivel - A device at the top of the drill string that supports weight, permits rotation,
and provides a rotary seal to permit mud circulation down through drill stem.
Tank - A bolted or welded atmospheric pressure container designed for receipt,
storage and discharge of oil or other liquid.
Tank Battery - A group of tanks to which crude oil flows from producing oil wells.
Tank Farm - One or more tanks connected to a pipeline and a pump station by means
of which oil is unloaded in tanks or withdrawn from them.
Terminal - A point to which oil is transported through pipelines. It usually includes
a tank farm and may include tanker loading facilities.
Tool Pusher - Individual responsible for the drilling rig, all on-location drilling
operations, and associated logistics required in accordance with the well design
and drilling plan provided to him. He normally reports to the drilling superintendent
and supervises a driller for each shift of daily operation.
Traveling Block - Free "pulley" used in conjunction with crown block for hoisting and
lowering drill string and casing and other heavy loads.
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Treater - An equipment used to break an oil/water emulsion.
Trip - To pull or run a string of drill pipe, rods, or tubing from or into a well.
Trip Gas - An accumulation of gas which enters the hole while a trip is being made,
and shows up as gas-cut mud after circulation is restored.
Tubing Hanger - A hanger and seal element supporting tubing string from tubing head.
Tubing Head Equipment - A flanged spool, sealing above casing head, which supports
weight of tubing string.
USCG - United States Coast Guard.
USGS - United States Geological Survey.
Vacuum Degasser - A vessel designed to remove entrained gas from gas cut drilling
mud with the assistance of a vacuum.
Water Flooding - Injection of produced water into a reservoir to prevent lowering of
ground elevation as a result of oil production. (See also Fluid Injection.)
Water/Leg - A vertical siphon controlled by a dump valve and attached to a treater to
siphon off clear water from the base of the treater.
Well Completion - In a potentially productive formation, the well must be completed in
a manner to permit production of oil; the walls of the hole above the producing
layer (and within it if necessary) must be supported against collapse and the entry
into the well of fluids from formations other than the producing layer must be
prevented. A string of casing is always run and cemented, at least to the top of
the producing layer, for this purpose. Some geological formations require the
use of additional techniques to "complete" a well such as casing the producing
formation and using a "gun perforator" to make entry holes, the use of slotted
pipes, consolidating sand layers with chemical treatment, and the use of surface-
actuated underwater robots for offshore wells.
Well Head - Equipment used at the top of a well, including casing head, tubing head,
hangers and Christmas Tree.
Wildcat Well - A well drilled to test formations nonproductive within a 1-mile radius
of previously drilled wells. It is expected that probable hole conditions to be en-
countered can be extrapolated from previous drilling experience data from that
general area.
Wirelines - Wire rope used to raise or lower items from or into well.
Wireline Preventers - Manually-operated ram-type preventers especially adapted for
closure around wirelines.
Work Over - To clean out or otherwise work on a well in order to increase or restore
production.
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