EPA-R2-73-280h
August 1973 Environmental Protection Technology Series
Petroleum Systems
Reliability Analysis
Volume II - Appendices
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, have
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-R2-73-280b
August 1973
PETROLEUM SYSTB1S 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 II - APPENDICES
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 has 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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FORBVORD
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 inters 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 invaluable 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
111
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spill prevention program for crude oil systems, based on a review of
petroleum facility SPCC plans and using techniques developed during the
study. The Engineering Report also includes a bibliography and glossary.
Volume II contains eleven appendices that provide the detailed infor-
mation upon which the report is based. Relationships between appendices
are shown by the following diagram.
APPENDIX A
FIELD SURVEY TRIPS
APPENDIX B
SUBSYSTEM DESCRIPTIONS
SOURCE DATA BANK
DESCRIPTIONS
TABULATION OF OIL SPILL
RECORD DATA
APPENDIX K
DATA CODE BOOK
APPENOIXE
PRESENTATION OF SPILL DATA
FAILURE MODES AND
EFFECTS ANALYSIS
uveame
OKHfxxnas OF HUWDOS
KHVRM. ENYIRCXEJT ON
CORROSION OF PfTROLEUM
SYSTEMS EQUIPMENT
APPENDIX I
REGULATION REVIEWS
SUMMARY REPORT
SAFETY SHUTDOWN
DEVICES
Thomas J. Charlton, 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
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APPENDIX A
FIELD SURVEY TRIPS
A-i
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TABLE OF CONTENTS
Appendix A - Field Survey Trips A-l
A. 1 Introductory Summary A-l
A. 2 Overview of Field Survey Approach and Activity A-2
A. 2.1 Three Inland Oil Fields and a Pipeline Pumping Station
in Texas A-2
A. 2.2 Three Offshore Fields and Related Shore Crude Oil Handling
Facilities and a Land Oil Field in Alaska A-2
A. 2.3 Three Offshore Operations and Related Shore Facilities and
Three Other Shore Installations in California A-2
A. 2.4 Six Offshore Fields and Related Shore Crude Oil Handling
Facilities and Two Tidal Zone Fields in Louisiana (State
and OCS Leases were included) A-3
A. 3 An Overview of Significant Observations A-3
A. 4 Trip and Visit Report Summaries A-7
A. 4.1 Trip Number 1 - Houston, Texas Area Survey (4 through
13 August 1971) A-7
A. 4.2 Trip Number 2 - Alaska Survey (30 August through
14 September 1971) A-ll
A. 4.3 Trip Number 3 - Collection of Texas Spill Data and Attendance
of LAGCOE (17 through 22 October 1971) A-16
A. 4.4 Trip Number 4 - Southern California Area Survey
(25 October through 5 November 1971) A-18
A. 4.5 Trip Number 5 - Louisiana Gulf Coast Survey
(2 through 10 December 1971) , . A-32
A. 4.6 Trip Number 6 - Continuation of Louisiana Data and Field
Survey (7 through 18 January 1972) A-45
A. 4.7 Trip Number 7 - Company D's New Orleans Division Office
(15 through 18 August 1972) A-54
A-ii
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LIST OF ILLUSTRATIONS
Figure
A-l Company A's Typical Operations, Simplified Flow Diagram. . A-8
A-2 Schematic Diagram of Environmental Control-Waste
Utilization (Liquids) Facilities , A-21/A-22
A-3 Company B Test Schedule A-25
A-4 Safety Instruction Sheet A-29
A-5 Company G's Onshore State Lease Treatment Facility A-34
A-6 OCS Production Onshore Terminal A-35
A-7 Company G Main Pass Oil Production Platform A-38
A-8 Typical Main Pass Oil Production Platform A-39
A-9 Company G Bay Marchand Oil Production Platform A-41
A-10 Company G's Treatment Facility A-42
A-ll Company H South Timbalier Oil Production Facility A-44
A-12 Simplified Schematic of Company J Grand Isle Platform .... A-49
A-13 Company L's South Pass Production Operation A-55
LIST OF TABLES
Table
A-l Reports and Documents, New Orleans District Office A-46
A-2 Summary of Facilities, Gulf Region OCS Operation A-50
A-3 Tabulation of Spill Reports - Districts 1 and 2 A-50
A-iii
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APPENDIX A
FIELD SURVEY TRIPS
A. 1 INTRODUCTORY SUMMARY
The spill prevention program described in this report relies heavily on the operations and
findings of field survey trips. Through the cooperation of a number of oil companies and
governmental agencies, the field survey provided the study team with current, first hand
exposure to existing petroleum systems, operation and maintenance practices, local
conditions and environments, and also provided the opportunity for discussion with petroleum
industry personnel. This appendix is included to provide an understanding of the benefits
resulting from the study team's observations. The basic purpose of the field surveys was
to develop an information baseline through observations, discussion, and study of the more
significant continental United States' oil producing areas. Survey emphasis was guided by
the following criteria:
1. Visit a sufficiently large number of selected facilities to provide a
representative sample of present petroleum systems and system
state -of-the -art.
2. Observe systems over a wide range of ages and configurations.
3. Observe both onshore and offshore operations.
4. Observe operations in various geophysical areas and climatic conditions.
The information gained from these surveys, supplemented through study of the technical
literature, was instrumental in the development of the system description of Volume I,.
the failure modes and effects analysis documented in Appendix F, and in the interpretation
spill data tabulated in Appendix D.
The remainder of this appendix presents an overview of field survey activity; a summary
of significant findings; and summarized reports of survey trips and visitations.
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A. 2 OVERVIEW OF FIELD SURVEY APPROACH AND ACTIVITY
The field survey trips and visits generating reportable facility information are identified
in the following paragraphs with general comments concerning the prevailing factors of
area choice. State and Federal agencies in these areas and two Government agencies
in Canada were contacted for background information and pertinent data. Several manu-
facturers of oil field equipment and controls were also visited. All visits were accom-
plished during the period June 1971 through August 1972.
A. 2.1 Three Inland Oil Fields and a Pipeline Pumping Station in Texas
Texas produces approximately one-third of all domestic crude oil. Houston, in the
coastal area, is the hub of the petroleum industry. The city afforded an opportunity to
visit equipment manufacturers, service companies, and nearby crude oil production and
pipeline facilities. A cross-section of operations and technology exists which ranges
from very old to modern. The producing wells range from high capacity to nearly depleted
stripper operations. The field locations chosen for visitation were on dry land, but near
coastal waters and in the watershed of a high rainfall belt.
A. 2.2 Three Offshore Fields and Related Shore Crude Oil Handling Facilities and a
Land Oil Field in Alaska
Alaska was selected to provide information on the effects of a cold environment on both
land and offshore operations. There is currently no significant activity on the North
Slope where arctic climate exists; therefore, that area was not visited. Cook Inlet,
however, provides a unique cold weather, offshore environment. A land operation in
southern Alaska was also selected.
A. 2.3 Three Offshore Operations and Related Shore Facilities and Three Other Shore
Installations in California
California produces approximately one-ninth of all domestic crude oil and virtually all
oil production of the nation's west coast. Both onshore and offshore production exist.
Offshore operations are in both protected and exposed coastal waters, while some onshore
facilities are in densely populated urban areas. Facilities range in age from very old to
modern.
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A.2.4 Six Offshore Fields jind Related Shore Crude Oil Handling Facilities and Two
Tidal Zone Fields in Louisiana (State and PCS Leases were Included)
Louisiana produces approximately one-fourth of all domestic crude oil, the majority of
which comes from the coastal area. This region is characterized by high-productivity
wells in the offshore and adjacent tidal areas. Offshore oil production comes from plat-
forms situated in water depths to well over 200 feet. Nearshore operations are in tidal
marshes, lakes, bays, and sounds.
A.3 AN OVERVIEW OF SIGNIFICANT OBSERVATIONS
Some of the more significant observations and findings derived from the field surveys
are highlighted below:
1. Although the petroleum systems studied generally comprise a definable set of
processes "typical" configurations could not be identified. As a result of wide
differences in naturally occurring conditions, standardization among systems,
subsystems, or equipment was not exhibited at any level. This complicated
the development of the failure modes and effects analysis presented in
Appendix F.
2. Evidence among several companies indicates that formal spill contingency
plans have been developed and oil companies have ascribed to these on a
cooperative basis. These plans list well-defined emergency procedures,
pertinent notifications, names, emergency telephone numbers, and other
information, and receive mutual, cooperative implementation regardless
of spill source.
3. The application of automated oil field production methods is increasing. As
a result, it has been necessary to develop highly refined procedures for
routine and preventive maintenance. The value of these programs has been
recognized and adapted to some nonautomated production systems. However,
in many cases, documentation is relatively informal or lacking in some detail
with respect to operation, inspection, and preventive maintenance.
A-3
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4. Competition among oil field hardware manufacturers has made available to the
industry several lines of rugged and dependable components, as well as less
dependable components at a lower price. The more expensive components
exhibit reliability and failsafe considerations in their design.
5. A major company conducted a failure modes and effects analysis (FMEA) on a
principal offshore platform facility and a reliability study on a major land-based
computerized field, and is performing an FMEA on a portion of a producing
facility which will be submerged in the deep seas.
6. The U. S. Geological Survey (USGS) has collected large quantities of refined
information on equipment and procedures required on the outer continental
shelf (OCS) which could be used in reliability analysis; had a study made by
NASA personnel to determine the feasibility of applying reliability analysis
methods to oil field systems in the OCS area; and is conducting three other
related studies, one of which will include FMEAs of six offshore platforms
of various complexities.
7. Sand production is a major problem in petroleum systems. It causes blockage
(sanding up) of tubing and equipment and erosion (sand cutting) of tubing, pipe,
valves, fittings, and vessels. The use of sand control techniques in well com-
pletion and workover procedures limits sand production but does not eliminate
it. Some advanced preventive maintenance procedures such as ultrasonic
inspection to determine wear and tear rates in critical areas, have been
developed to detect the problem.
8. Various schemes are used to remove accumulated sand from vessels by wash-
ing with an oil stream. One such scheme uses a timer to provide intermittent
washing cycles. Desanding equipment is used to remove sand from oil and
water "in-stream." Various means are used to reduce velocities of sand-laden
fluids to control erosion. An example would be a choke downstream of a dump
valve or elbow.
A-4
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9. One company has studied internal pipe wear as a function of fluid velocity and
determined that velocities of 75 feet per second or greater cause severe
acceleration of pipe wall loss. As a result, flow demands on all flowlines
are reviewed every 6 months and, where necessary, flowlines are replaced
and flow rates are adjusted to less than 75 feet per second. Produced sand
is laundered before its disposal in overwater operations.
10. External corrosion of pipelines, offshore platforms, and other metallic equip-
ment can be controlled largely by cathodic protection and protective coatings.
There is a special problem in the splash or wave wash zone in overwater
operations, which in some cases is corrective by application of a vulcanized
rubber coating, which has been found to be especially effective.
11. Internal corrosion is not controllable cathodically. Effective means include
the use of corrosion inhibitors by continuous injection of small quantities
into the fluid being pumped, and by "slug" treatment using water plugs.
Occasionally, corrosion attributable to anerobic bacteria was identified.
This apparently can occur where the culture is introduced into the
pipeline system via drain sump fluids that are pumped ashore with
the produced oil and saltwater. In these cases, biocides can be intro-
duced into the drain sumps to control the problem. In some instances,
protective coatings can be applied to the interior of pipe, fittings, tanks,
and other vessels.
12. Sump systems have become required equipment in overwater operations
and are routinely found in many land operations. These sumps centralize
the collection of all drips and accidental spills, and are also used for
blocks and drain procedures in repair operations. Spills have resulted
from sump overflows due to failure of automatic, fluid-level controlled
disposal pumping methods. Overflow can result from failure of the
A-5
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disposal pump by overload due to hard rain. Some of these problems
can be overcome by use of redundant pumps and controls, automatic
timer switches with liquid-level override, and the addition of a water
leg to siphon excess water.
13. Personnel training has come into strong focus in recent years. In-
creased complexity and refinement of equipment and procedures have
required extensive operational training in the petroleum systems
studied. Oil spill prevention and cleanup have become subjects for
intensive training for all personnel levels in the crude oil Production
and Gathering/Distribution systems. Blowout prevention has become
more of a science than an art. It is now recognized that this
technology must be learned both in the classroom and by experience
on the drilling rig floor. Accordingly, there has been a proliferation
of training programs offered to personnel, ranging from short
lectures using electronic simulation to formal courses that include
"hands-on" well-killing procedures on a full-scale blowout training
well, such as one recently installed at Louisiana State University
and financed by industry. Hardware and procedures have been
developed to the point that blowouts can be virtually eliminated if
rig floor personnel have the proper training. Some elements of
industry have begun to spend considerable funds for training in this
area. Until recently, there was reluctance to provide such training
because of the transient nature of rig floor employees.
14. There are at least eight manufacturers actively engaged in the develop-
ment of a second generation subsurface safety valve for flowing wells,
commonly known as a storm choke. The new configuration will stress
surface control. A number of these devices have been in use in other
A-6
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areas of the world. Improvements are being sought in those currently
available designs, and entirely new concepts are also being developed.
Several prototypes of these new designs are undergoing testing by
several major producers using actual well conditions. The USGS is
revising regulations dealing with subsurface safety valves to encourage
a phased changeover to the use of surf ace-controlled configurations
in the OCS area.
A. 4 TRIP AND VISIT REPORT SUMMARIES
This paragraph provides summaries of the trips and visits made during the field survey.
In preparing these summary reports, some visits, and some discussion and observa-
tions during other visits, have been omitted when, in our judgement, these actions
seemed appropriate. The remainder of this appendix presents the summary reports,
organized by trip.
A.4.1 Trip Number 1 - Houston. Texas Area Survey (4 through 13 August 1971)
Visit Number 1 - A Major Company Producing Tanks, Pressure Vessels, Etc.
Purpose - To observe maintenance and repair activities in support of the
company's products provided to the oil industry.
Personnel Contacted - Vice President of Sales, District Manager, and Sales
Engineer.
Observations - The equipment provided to the oil industry by this manufacturer
indicate that a skilled man with proper parts can repair the valving associated
with the vessels with ordinary tools in relatively short times. For example,
it was demonstrated that valve seat replacement could be performed in 10
minutes.
A-7
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Visit Number 2 - Company A's Production Operations in a Large Field Near Houston
Purpose - To observe production operations and procedures.
Personnel Contacted - Regional Superintendent, Area Engineer, and Computer
Specialist.
Observations - The operation is located on a large field discovered in the 1930s
with gas-lift aided sweet crude flowing wells. The field and well head areas
showed little evidence of oil spillage. Personnel observed the gathering,
separation/treatment, metering, and gathering to local storage for pipeline
sale. Company A has a computer system for monitoring flow parameters
and plans to extend this system, including remote control, to other fields.
The company provides, to a large extent, its own maintenance and does not
rely on manufacturers' service organizations. Figure A-l depicts the general
production operation on a typical lease and the field ACT station.
GAS TO PLANT AT 8 TO 15 PSIG
LEASE-GAS
METER
TEST-GAS METER [
STORAGE TANK
PIPELINE OIL
b f
OVERFLOW LINEp-[ Q,L
j IMETER
f-looo
DUMP
VALVE
/ \ SAMPLER
TOWER
SEPARATOR
Q LEASE PUMP
TREATER
FLUID METER
TEST SEPARATOR
TEST WELL
PIPELINE-OIL WELLS
SALT WATER TO
ACCUMULATION
STATION
FLOW LINES
FROM WELLS
SALT-WATER
TO SALT-WATER
DISPOSAL
METER I
: 0-AI
Figure A-l. Company A's Typical Operations, Simplified Flow Diagram
Visit Number 3 - Company B's Production Operations in a Large Field Near Houston
Purpose - To observe production operations and procedures.
Personnel Contacted - Environmental Coordinator, District Superintendent, and
Acting Field Superintendent.
Observations - Company B has a large field of gas-lift aided sweet crude flowing
wells. The entire area was well kept with several environmental protection features.
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Wells near highways were equipped with storm chokes. A demonstration of the salt
water treatment closed system was given by allowing a heavy flow of crude oil from
one salt water inlet line to this system. After passing through a multistage skim-
ming pond, the outlet salt water showed no evidence of sheen. Company B also has
a computer system for monitoring, but not controlling, oil flow parameters.
Visit Number 4 - Company B's Production Operations in an Old Field Near Houston
Purpose - To provide a contrasting view of early oil field practices compared with
those observed in Visits 2 and 3.
Personnel Contacted - Same as during Visit 3.
Observations - A short visit was made to an early 1900s oil field. This nearly
depleted field, primarily pumping-aided production wells, appeared to have
experienced considerable prior oil spillage.
Visit Number 5 - Texas Railroad Commission, Austin
Purpose - To determine the types and quantities of spill data available at the
Commission that would be applicable to the present study.
Personnel Contacted - Messrs. Rex King and Guy Mathews.
Observations - The Commission maintains a large file of oil spills reported in Texas
and made this file available. With over 4000 spill reports in 12 districts since
January 1970, the team concentrated on Districts 1 and 3 to develop data for sub-
sequent and more detailed analysis. Two reported major causes for spillage were
pipeline corrosion and separation/treatment equipment valve malfunction.
Visit Number 6 - Company B's Pipeline Station Near Houston
Purpose - To observe pumping station and pipeline operations and procedures.
Personnel Contacted - Assistant Operations Manager, Station Manager, and two
Station Engineers.
Observations - The station's pumping and manifolding facilities appeared to be
extremely well kept. According to station personnel, spillages occurred more
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frequently in the pipelines than in station facilities despite that station facilities
are more complex and involve mechanical operation. This was attributed to the
greater opportunity for personnel observation and preventive maintenance.
Visit Number 7 - A Drilling Control and Monitoring Device Manufacturer
Purpose - To examine and discuss various drilling control devices.
Personnel Contacted - Vice President and two engineers.
Observations - Examined and discussed the operation of a number of drilling control
devices. These included downhole blowout preventers, drilling mud weight, and
flow rate measurement devices and recording equipment. Of particular interest
was an opportunity to see an experimental computer-operated drilling well control
system.
Visit Number 8 - A Major Company Producing Well Accessory Equipment
Purpose - To increase familiarization with available well accessory equipment.
Personnel Contacted - Manager of the Houston Office.
Observations - Examined and discussed operation of automatic surface control valves
and several types of subsurface storm chokes. Many of those devices are designed
in accordance with fail-safe principles. Certain types are made of a steel particu-
larly resistant to corrosion from the sulphur compounds present in sour crude.
Visit Number 9 - A Drilling Equipment Rental Company
Purpose - To increase familiarization with various drilling tools and blowout
preventers.
Personnel Contacted - Company owner.
Observations - Inspected a variety of drilling tools including ram-type surface blow-
out preventers. The massiveness and ruggedness of equipment was impressive.
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Visit Number 10 - Revisit to Company Visited in Visit 1
Purpose - To discuss questions raised by review of Texas Railroad Commission
data.
Personnel Contacted - Sales Engineer.
Observations - As a result of reviewing the data maintained by the Texas Railroad
Commission, the team returned to obtain further information on oil separator/
treater equipment, valves, and controls.
Visit Number 11 - A Drilling Tool Rental Company
Purpose - To increase familiarization with additional drilling equipment other than
that observed during Visit 9.
Personnel Contacted - Company owner.
Observations - Obtained a broader view of drilling tools available to the petroleum
industry.
A. 4.2 Trip Number 2 - Alaska Survey (30 August through 14 September 1971)
Visit Number 1 - U. S. Coast Guard, Juneau, Alaska
Purpose - To introduce the program to the Coast Guard and to extract any and all
crude oil spill data for analysis and evaluation.
Personnel Contacted - Lt. Westling.
Observations - As a result of an earlier phone call from CSC and a program Lt.
Westling had just completed, a data summary of Cook Inlet spills dating from 14
June 1968 through 26 July 1971 was ready upon the team's arrival. In addition to
these data Lt. Westling agreed to forward additional data as reports are received.
One additional reference suggested by Lt. Westling is a document generated by the
University of Alaska entitled "Quantitative Assessment of Oil Pollution Problems
in Cook Inlet," Report No. R-69-16, dated January 1970.
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Visit Number 2 - Oil and Gas Conservation Board, Calgary, Alberta, Canada
Purpose - To obtain crude oil spill data for analysis and evaluation from environ-
ments similar to that in Alaska.
Personnel Contacted - Assistant Manager, Drilling and Production; and Engineer,
Drilling and Production Office.
Observations - A summary of crude oil spills in the Alberta area for 1970 and 1971
was provided. Copies of Oil and Gas Acts, Regulations, maps of Alberta oil fields
and pipelines, and copies of monthly and weekly statistics were obtained. Mr.
Edgecombe indicated that his field offices may have more detailed information on
the crude oil spills he had summarized. He also said that pipeline spills did not
fall under his jurisdiction; pipelines were under the jurisdiction of the Alberta
Division of Mines and Minerals.
Visit Number 3 - Edmonton Field Office of Drilling and Production and the Division of
Mines and Minerals, Edmonton, Alberta, Canada
Purpose - To obtain detailed information on crude oil spillage from the Edmonton
Field Office of Drilling and Production and to obtain pipeline spill data from the
Division of Mines and Minerals.
Personnel Contacted - Duncan LaBallister, Edmonton Field Office for Drilling and
Production, and Mr. A. L. (Larry) Berry, Superintendent of Pipelines, Division
of Mines and Minerals.
Observations - Mr. LaBallister said that he did not have additional detail to the
summaries that Mr. Edgecombe had previously provided us. Mr. Berry indicated
that his records on pipeline oil spillage were of some detail. However, he was not
at liberty to provide the records unless required by court order. He did provide
general statistics on the category of oil spillage cause and the percent of the total
events caused by each category. Mr. Berry appeared to be knowledgeable on the
weaknesses of standards relating to pipelines, which the oil industry uses in both
the United States and Canada. He indicated several of the weaknesses which he felt
should be corrected. A copy of Alberta's Pipeline Act was obtained.
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Visit Number 4 - Environmental Protection Agency, Anchorage, Alaska
Purpose - To obtain spill data for analysis and evaluation.
Personnel Contacted - Ray Morris of the EPA office
Observations - Mr. Morris indicated that his file on oil spillage was the most
complete in the Alaskan Area, including State and Coast Guard files. The records
of the events relating to spillage of crude oil were examined.
Visit Number 5 - Alaska Department of Natural Resources, Division of Oil and Gas
Purpose - To obtain oil spill data for analysis and evaluation.
Personnel Contacted - Homer L. Burrell, Director of the Division of Oil and Gas,
and John Miller and Lonnie Smith, Engineers.
Observations - Mr. Burrell said that any crude oil spillage event would be in
EPA's files. He said he may be able to provide more detail to specific spills
and blowouts, so we left a summary of EPA-recorded spills with him. He said
he would mail the additional information to CSC along with State regulations and
pool rules for wells. Warren McFall of EPA's Anchorage office said that Mr.
Burrell's division also makes periodic checks and exercises of safety valves on
wells. Mr. Burrell was recontacted to obtain records of failures detected during
these checks.
Visit Number 6 - Company C's Onshore Oil Field
Purpose - To observe Company C's production operations and procedures as well
as those of an independent drilling contractor.
Personnel Contacted - Company C's Alaskan Division Production Superintendent,
Field Production Foreman, Gas Plan Foreman, and a Tool Pusher for the Drilling
Contractor.
Observations - The Field Production Foreman had a collection of failed items and
discussed the problems that Company C has experienced in this field. The principal
problems have been cutting from sand and plugging of equipment with asphaltene.
A-13
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The wells at this facility are on artificial gas lift. As a result of this, storm
chokes are installed in some wells (and in time will be installed in all wells), a
highAow valve is at each well head to shut in the well if a break occurs in the
flow line, flow lines are extended out from well head with long radius bends in the
lines to alleviate cutting by sand, and a motor gate valve is located at the gathering
point. The gathering points and separators are located in Butler building enclos-
ures which have monitored "sniffer" leak detection systems which are forwarded
via two-way radio to patrol cars. An 8-inch gathering line from the LACT to a
pipeline company storage tank is scraped every 3 or 4 days in summer and daily
in winter. The field has approximately 58 wells of which 36 are in production on
6000-psi gas lift. About six to ten wells are on workover activity each summer.
The sand problem has migrated to pump station, causing seal problems there.
Visit Number 7 - Visit to Company A's Cook Inlet Field Operations
Purpose - To observe offshore production facilities and procedures in two
different fields and onshore treatment and storage facility.
Personnel Contacted - Production Superintendent and Production Foreman
Observations - Minimum oil is stored on the platforms. Instead, pipelines to the
shore storage facility are used to eliminate potential hazards. One platform's
production is interfaced to the shore storage via two 10-inch pipelines and the other
platform via two 8-inch pipelines. In both instances, one pipeline carries gas, the
other crude oil. However, should a problem occur in the oil pipeline, crude oil
production can be transported through the gas pipeline. The first platform consists
of two flowing wells and eight wells on hydraulic lift, as well as several inactive
wells which are to eventually be used for water flooding. The latter platform con-
sists of hydraulic lift wells only. The configurations of the two platforms are
essentially the same. The crude oil flows from the well head to two 250-psi separa-
tors (one three-phase, the other two-phase) and through a 40-psi separator used
as a free water knockout. Equalization occurs between the two high pressure
separators, alleviating spillage due to failure of the isolation valve between the
A-14
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high pressure separator and FWKO. The surface-controlled subsurface safety
valves are about 250 to 300 feet below the mud line in the well tubing string, and
include a high/low pressure valve at the well head, and high and low level valves
on each separator which are alarm-detectable at levels which allow adequate warn-
ing before overflow or draining will occur. In the event of a failure, the safety
valves will react in sequence back to the well, resulting in shut-in. Monitoring
and fault isolation panels are located in the Production Maintenance quarters
The platform equipment also includes a skim tank and two test separators. The
FWKO and skim tank were used earlier to condition the salt water prior to disposal
into the Inlet. Subsequent regulations prohibited salt water disposal into the Inlet.
Consequently, the conditioned salt water is now injected with crude oil into the
pipeline for separation and treatment at the onshore storage facility. Due to
paraffin formation, scrapers are periodically run through the platform to shore
pipelines. During the winter, scraper trips are performed daily; during the
summer, about once every 3 or 4 days. The onshore storage and treatment
facilities consist of a heat exchanger, four heater treaters, two serial free water
knockout tanks, two 10,000-barrel good oil storage tanks with equalization, and a
bad oil storage tank which will accept overflow from either or both of the good oil
tanks. The bad oil tank is fed back to heater treaters for further treatment.
Monitoring and remote valve controlling is centralized in a control building. Each
heater treater has an interface level control and an oil flare which will ignite any
overflowing oil. This flare is separate from the gas flare. The produced salt water
is disposed into a salt water evaporation pit.
Visit Number 8 - Visit to Company D's Platform
Purpose - To observe offshore production facilities and procedures.
Personnel Contacted - Production Superintendent and Production Foreman.
Observations - The platform consists of 16 wells, of which six are used for water
injection. The highest producing well averages approximately 1100 barrels per day.
The wells use gas lift. Several of the wells are of a dual completion type,
A-15
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the rest single completion. The separation area consists of a production separator,
a test separator, as well as a skim tank and small slop oil tank. The pressure disc
outlet configuration on the separator allows for overflow to enter the skim tank in
the event of a highlevel valve failure. Downhole well configurations were obtained.
The safety valves consisted of high/low valves for shutting in the well, tubing ball
valves, high level separator shutdown alarm valves, high pressure separator valve,
and relief valves, intermediate high level crude oil tank alarm, final high level
crude oil tank alarm, and a low pressure shutdown system for pipeline. A central
monitor and fault isolation room contained indicators to monitor conditions of the
various high/low safety valves and the well tubing valve as well as various pressures
for the gas lift and the automatic valves. There are two 8-5/8-inch pipelines to shore,
one for gas, one for crude oil. The gasline could be switched to transport crude
oil if the other experienced a problem. The pipelines are scraped according to the
same schedule as Company A. Company D disposed of the produced salt water
through shipment of the crude oil to its onshore treatment facility. After separation
of the salt water and the crude oil in the heater treaters, the salt water was disposed
into a water evaporation pit.
A. 4.3 Trip Number 3 - Collection of Texas Spill Data and Attendance of LAGCOE
(17 through 22 October 1971)
Visit Number 1 - Texas Railroad Commission
Purpose - To complete the collection of oil spill data from the files of the Texas
Railroad Commission.
Personnel Contacted - Rex King; Arthur H. Barbeck, Jr. (Chief Engineer);
Roy D. Rayne (Chief of Field Operations); Robert Harris (Assistant Chief Engineer).
Observations - Mr. King was most cooperative in making available the entire file
of oil spill reports. The team participated in reviewing the two file drawers of
reports, made principally during 1970 and 1971. The team received a summary
report of offshore Texas oil and gas production, which indicated that the offshore
leases have generally been a disappointment, and lacked the promise that seemed
A-16
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so positive a few years before. Only a few offshore producing wells existed.
The personnel interviewed stated with emphasis that no oil spill incidents were
known to have occurred offshore Texas.
Visit Number 2 - LAGCOE Attendance
Purpose - To attend the Louisiana Gulf Coast Oil Exposition (LAGCOE) at Lafayette,
Louisiana.
Personnel Contacted - Not applicable.
Observations - LAGCOE is held every other year at Lafayette. It is characterized
as the "Working Man's Oil Show," displaying the latest related products and
services in the oil industry. About 325 exhibitors, restricted to oil industry firms,
showed their products at the Blackham Coliseum, nearby buildings, and surrounding
grounds. The exhibit area is normally a facility of the University of Southwestern
Louisiana and is located on that campus.
The tour of the exhibits proved to be particularly valuable since it provided an
opportunity to see equipment, demonstration models, and displays of the services
common to the oil industry, and for discussion with knowledgeable personnel
manning the booths, many of whom were national and international authorities in
the industry. In general, the exhibitors were forthright and informative, answering
the many questions the team put to them. The team collected brochures and handout
material which provided description of equipments and their operation. The main
thrust of the exhibits was to present products meeting oil field requirements (partic-
ularly offshore), and to generate interest in sales of their product lines. The team
would have had to cover an immense territory and search out many people to gather
the information completely and freely displayed at LAGCOE. The visit to LAGCOE
also provided information concerning equipment specifications and petroleum system
configurations. In addition, much was learned about "failsafe" devices, failure
modes of equipment, and a miscellany of oil industry problems and proposed
solutions.
A-17
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A. 4.4 Trip Number 4 - Southern California Area Survey (25 October through
5 November 1971)
Visit Number 1 - Company M's Drilling, Production, Storage, and Pipeline Shipping
Facilities in the Long Beach, California area.
Purpose - To observe operating equipment and procedures.
Personnel Contacted - Production, Drilling, and Construction and Maintenance
Superintendents.
Observations - Discussed facilities and operations briefly prior to being given a
conducted tour of several facilities.
The first facility visited was a man-made island consisting of a perimeter of earth-
filled armor rock paved with a concrete surface. A retaining wall exists around
the island perimeter except at the boat dock wnere a boom is maintained to contain
fluid runoff in case of emergency. All island surface areas are constructed to
drain toward the center of the island such that all rain, spilled fluids, or liquids
used for cleanup are contained on the island. All wells are located in cellars.
Several hardware systems were examined:
Drilling - Only one rig was in operation. There are several unique features
of drilling and completions of the wells:
(1) Hole drift can vary up to 70 degrees from vertical
(2) Wells are completed on about every 5 acres of the producing horizons
(3) The close spacing of the surface locations and subsurface completions
require precise drilling techniques
(4) Drilling fluids and cuttings are carefully contained in vessels.
Production - The following production equipment was inspected:
(1) Cellars - wellheads, flowlines, valves, and safety equipment
(2) Well testers
A-18
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(3) Free Water Knockout (serving as horizontal separator for gas-water)
(4) Transfer pumps and motors
(5) Safety systems - included visual and audio, fire control, and spill
containment. To control spills, each island has a 5-foot retaining wall
around it. However, the driveway leading to the boat ramp is much
lower (i. e., an elevation increase of about 1 to 2 feet above the island
floor).
Onshore facilities include some producing wells, treatment facilities, storage facilities,
pipeline facilities, and water treatment facilities. The following onshore equipment was
inspected and discussed.
Flowsplitters - Crude oil from the manmade island flows into a large flow-
splitter, then into heater treaters. Crude oil from onshore wells flows into
other flowsplitters and thence into other heater treaters.
Heater Treaters - The treaters operate at about 75 pounds pressure and are
used to separate residual gas and water. The gas flows into a tank to de-
hydration prior to being compressed for transmission to gas treatment (H S
£
removal) plant. The water is sent to treatment facilities prior to being re-
injected. The crude oil is transferred to storage tanks.
Storage Tanks - The crude oil is contained in five tanks, two having a capacity
of 87,000 barrels each. The other three tanks have a capacity of 28,000
barrels. Three pumps, driven by electric motors, move the crude through
a 24-inch line to the ACT unit at the pipeline shipping terminal.
Pipeline - Although pigs are run every week on the lines moving wet oil from
the onshore and offshore wells to the treatment facilities, there is no pig
capability in the 24-inch line. Corrosion inhibitors are added to the oil as a
protective measure. Company personnel walk the line for above-ground visual
inspections of leaks.
A-19
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Pipeline Shipping Terminal - The crude oil is manifolded into the purchasers'
lines and sent through provers to determine the amount of crude sold. The
crude is purchased by several oil companies and transferred to their refineries
through several pipelines. High-low pressure sensors are monitored at the
pipeline shipping terminal and at the control house near the storage facilities.
Safety - A control house near the storage facilities has instruments to moni-
tor the treatment and transfer of oil and gas at and between the various facilities.
In addition, control panels, colored lights, and audio alarms are provided at
treatment and transfer facilities.
Water Treatment - Figure A-2 shows a schematic diagram of water treatment
and injection facilities. This is typical of low volume systems where heater
treaters are not used. In other installations, the wash tank is replaced by
heater treaters, or the oil output of the wash tank is recycled to heater-
treaters for processing. The flotation tank, when overflowed, dumps into a
boomed area in the harbor.
A preventive maintenance program is recorded on sets of three cards (white, green, and
yellow). The white cards are used for schedule maintenance; the green describe the
equipment, and the yellow record maintenance and completed repair work.
Visit Number 2 - Company B's Crude Oil Production Facilities in Southern California.
Purpose - To observe operating equipment and procedures.
Personnel Contacted - Western Region Production Manager, Environmental
Conservation Manager, Area Supervisor, and Area Foreman.
Observations - The production manager described how planned unitization will
affect the local producing properties. Production from two units will go into three
or four tank batteries instead of the present 50 or more. The number of tank
batteries for another unit will be reduced from 34 to one. About 60 to 70 miles
of coated, concrete-lined pipe will be laid for the new system. Since the pipe will
be laid under streets, the construction will be a time-consuming and expensive.
A-20
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However, Company B feels it will be an economically feasible operation in spite of
the rather low daily production rates2000 barrels of oil per day (12 to 20° API)
and 3000 barrels of water (60 percent water cut). Company B, as operator of the
unit, feels that the exposure risk to nearby houses (i. e., wells and tank batteries
are in back yards) demands unitization. Upon completion of the unitization a pre-
ventive maintenance program similar to the one used in another area will be required.
After the meeting a tour was made of the offshore facilities.
Facility - The facility, located about 1 mile offshore, is a platform of the
same general design as those in the Gulf of Mexico. The main platform is on
reinforced concrete pilings. A later addition, built to accommodate a store-
room/fire safety equipment and personnel safety area, is on treated steel
pilings. The surface area of the main floor is about 1 acre and is designed to
permit production from about 75 wells.
Production - As of this date, 51 wells have been drilled and 37 are actively
producing (1500 barrels of oil and 680 barrels of salt water per day). Well
spacing on the platform is in rows, with 10 feet between wells. The holes are
directionally drilled and maximum deviation from vertical is about 45°. Pro-
duction is from formations at depths from about 3500 to 7000 feet. Additional
wells have not been drilled because of the drilling ban (since lifted) and the
need to obtain permits from State agencies. Water is produced from shallow
onshore wells and piped to the platform for water flooding. The crude oil
varies from about 22 to 28° API.
Pipeline - Four pipelines (an 8-inch gas line, a 3-inch fresh water line and
two 3-inch lines for produced fluids) connect the platform to the onshore
treatment plant. The lines are laid on water bottom. When questioned about
these lines being caught by dragging anchors, it was stated that boat traffic
runs parallel to the lines and anchors inside the marinas. Chemical additives
are used for corrosion prevention.
A-23
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The output of the onshore separation center is:
1. Crude - sold to another oil company
2. Gas - sold to the gas company for local consumption
3. Treated Water - discharged into the river
4. Solid Wastes - trucked to garbage dump.
The equipment design, configuration, and operation in the separation center is standard
for this area. One serious potential trouble spot is the discharge of treated water into
the river. A serious crude oil overflow from the treaters into the water treatment, into
the river, and then into the marina (filled with docked pleasure crafts and large yachts)
would have serious repercussions. Company B plans to incorporate the treated water
into a closed system, i.e., no discharge.
Figure A-3 is Company B's Test Schedule. The "Xs" indicate which tests are completed
each month.
Visit Number 3 - Company N's Crude Oil Production Facilities in the Long Beach,
California Area.
Purpose - To observe operating equipment and procedures.
PersonneHItontacted - General Manager, Superintendent and Assistant Superinten-
dent of Construction and Maintenance, and Petroleum Engineer
Observations - The production, treatment, storage, and transportation facilities
are collected in units and are positioned so that the land area used is minimized.
Production - Produced well fluids contain about 27,000 barrels of oil and
211,000 barrels of water (i. e., 87 percent determined by cut monitor panel)
on a daily basis. There are several producing zones which range in vertical
depths from 2,200 to 6, 000 feet. The crude varies from 15 to 19 degrees
API, measured at the tank farm. The early producing zones were gravel
packed, but are now float packed. The casing program is as follows:
A-24
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This monthly report should be submitted to the District office no later than the 5th day of the following
month.
Month:
Date Submitted:
Submitted By:
Test
Master Panel and Flame Detector Panel
Flow in Fire System Shutdown
Gas Detector Shutdown
Flame Detector Shutdown
Power Failure Shutdown
Remote Shutdown
High Pressure Shutdown for Shipping Tank
High Pressure Shutdown for 8-inch Gas Line
Low Pressure Shutdown for 8-inch Gas Line
Low Pressure Instrument Air Alarm
Shipping Pump Controls and Shipping Tank Bypass System
High Pressure Shutdown for Shipping Pumps
Low Pressure Shutdown, Two Shipping Pumps
Low Pressure Shutdown, One Shipping Pump
Pump Suction Valves Closure
Shipping Tank Bypass System Operation
Surface Safety Valves
Bleed Test to Check Valve Closure
Bleed Test to Cheek Valve Leaking
Subsurface Safety Valves
Low Pressure Set Point Test
High Pressure Set Point Test
Oil Pipelines
Pressure Test line 1
Pressure Test Line 2
Weekly Visual Check by Crew Boat
Gas Pipeline
Pressure Test
Fire Protection
Start and Run Fire Pumps 15 Minutes Daily
Drain and Flush Main Lines
Drain and Flush Foam Lines
Flush Cellar Deluge Lines
Service Fire Extinguishers
Pressure Test Fire Hoses
Lubricate Hose Nozzles
Test Deluge System Over Compressors
Fire Protection - Separation Center
Service and Test Foam System
Service Fire Extinguishers
Cathodic Protection
Read Rectifier Output
Measure Cathodic Protection Potentials
Cathodic Protection - Separation Center
Read Rectifier Output
Measure Cathodic Protection Potentials
J F M
X
X
X
X
X
X
X
X
X
X
X
X
X
X
,X X X
X
XXX
XXX
XXX
X
XXX
X
Test Schedule
A M J J A
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X X X X
X
X
X
X X X X X
X X X X X
X
X
X
X X X X X
X
X X X X X
X
s o
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
X X
X
X X
X
X
X
X
X
X
X X
X
X X
X
N D
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X X
X
X
X
X X
X X
X
X
X
X X
X
X X
X
Figure A-3. Company B Test Schedule
A-25
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Depth (feet) Ranges Casing (inches) Diameter
0 to 60 - 80 24
60 - 80 to 800 13-5/8
800 to T. D. 9-5/8
The liner diameter is 6-5/8 inches. Oil is produced by submersible pumps,
hydraulic lift, and mechanical lift. The casing hangers are below ground
in cellars approximately 5 feet deep. From the wells, the oil is pumped
to a house where it is manifolded and sent to treaters (the manifolds have
been housed because power oil, in the past, has leaked out and sprayed on
private property, causing considerable damage).
Treaters - From the manifold house, the oil is moved to the free water
knockout, which serves as a three-stage flow splitter. A gravity weight
float controls water dump; the gas is released at pressures above 20 psi.
A water trap alarm has been installed to alert personnel that oil is being
dumped into the water system. The oil moves from the free water knock-
out to the heater treaters. The steel lines from the heater dump valves
are being replaced with glass and glass flanges. Bronze valves are used
in the treaters for valves smaller than 2 inches and stainless steel for
those larger than 2-inches. Glass is used throughout the treaters where
temperature and pressure permit. The gas shipped from Company N's
property has 150 grains of hydrogen sulfide per 100 cubic feet.
Pipelines and Storage Tanks - The oil moves from the treaters to the tank
farm. Records are kept on the preventive maintenance to the pumps and
pump motors (inspections and lubrications) and on tank cleaning and anode
installation. The LACT meters are tested every 2 weeks. The LACT
shipping pumps force oil into surge tanks with high level visual alarms.
A-26
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Water Treatment - Water from the free water knockout and treaters goes
to skim tanks, to flotation cells, and then to a reinjection system. The
tanks in the water treatment system have fiberglas bottoms which extend
2 inches up the sides to prevent oxidation. Sodium sulphite is added for
oxygen. The skim tank has a pump which operates at 40 psi and high-low
level arms. The flotation cells have valves which operate at 40 psi. The
cells operate on intake at less than 30 psi to allow floculation. Gas from
the flotation cells goes to gasline and water goes to a surge tank or, for
untreated water, to a waste tank. All solid waste materials are hauled
to a dump. The surge tanks are equipped with high-low level alarms.
Pumps transport treated water to a filtration plant through epoxy-coated
lines. The filtration plant is connected to the water injection plant and
wells by concrete lined pipes.
Visit Number 4 - Company C's Crude Oil Production Facilities in Southern California.
Purpose - To observe operating equipment and procedures.
Personnel Contacted - Southern Division General Manager, Staff Engineer,
Area Supervisors, and Area Foremen.
Observations - Both offshore and onshore production facilities were visited.
The offshore facility is a man-made island of 1.1 acres in water about
40 feet deep. The island has the capability for 128 wells (two cellars, A
and B, with two lines of wells in each cellar and 34 well locations in
each line).
Production - Seventy-four wells are on stream. The field has not been
drilled completely because of the drilling ban, since removed, and the
need to obtain permits from State agencies. An average of 5500 barrels
of oil and 4000 barrels of water per day are produced from eight zones
A-27
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ranging in slant depths from 3500 to 7000 feet. Artificial lift by gas
and hydraulic pumping methods is used. Water from shallow onshore
wells (capable of producing 20,000 barrels per day) is piped through
4-inch lines to the island. Some wet gas is produced and is recycled.
Well tree valves are air open/spring close type. High-low pressure
sensors are on the flow lines. The wells are shut down monthly to test
meters and valves. Every 6 montihs, the subsurface control valves
(two on each well, installed at depths of about 9 feet) are tested. Electric
motors are used on the island but diesel engines are ready on standby basis.
Pipelines - The pipelines to shore are on the ocean floor, coated, and
cathodically protected. Gas is transferred by a 10-inch line and wet oil
by a 12-inch line. Sensors can close and shut off lines at pressures
outside the thresholds as follows:
Hydrocarbons Pressure (psi)
Low High
Gas 50 250
Oil 30 250
Pigs are run in the oil lines every week.
Safety - Figure A-4 is a safety instruction sheet supplied to all island
visitors.
The onshore facility has the capability of 76 wells (two cellars, A and B, of
two rows per cellar and 16 sites per row (at 6-foot spacing), plus 12 sites
in the middle of the cellars).
Production - A total of 68 wells have been drilled; 55 are on stream, 10
are used for water injection, and three are inactive. Production per day
A-28
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ALL VISITING PERSONNEL
ALARM SIGNALS
FIRE
MAN OVERBOARD
THREE (3) LONG BLASTS OF APPROXIMATELY 4-5
SECONDS EACH.
THREE (3) SHORT BLASTS FOLLOWED BY TWO (2)
LONG BLASTS.
ABANDON ISLAND ONE (1) CONTINUOUS BLAST.
WHILE ON ISLAND - IF ANY OF THE ABOVE SIGNALS ARE HEARD, REPORT TO
THE ISLAND OFFICE (LOCATED UPSTAIRS) FOR FURTHER
DIRECTIONS.
THANK YOU,
ISLAND FOREMAN
Figure A-4. Safety Instruction Sheet
A-29
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is 11,200 barrels of oil; 17,000 MCF of gas; and 5000 barrels (40 percent
cut) of water. The production per day from another site (4200 barrels of
oil, 2000-3000 barrels of salt water (30 to 40 percent water cut), and
3500 MCF of gas), is combined with production from the first site, then
shipped to nearby treatment facilities. Of the 55 producing wells, five
are water lift and 50 are gas lift or flowing. Production is from depths
(vertical) of 2000 to 8000 feet, The crude is 25 to 30 degrees API. The
surface casing extends down 1000 to 1500 feet. Below the surface casing
7-inch strings are run through the producing horizon or to the top of
gravel pack.
Downhole, the gas lift and flowing wells have ball type safety valves which
are dependable in operation and repeatable under test. These are installed
90 feet below the tubing head, are hydraulically operated (at 50 psi under
the tubing pressure), and are removed by wire line. They can be operated
manually or triggered by "Fire Eyes." Tests are conducted monthly and
results of the tests, including removal of the valve, are documented. The
gas lift wells have a check valve at the well head to prevent backflow from
the annulus. The Christmas trees have pneumatic pressure-operated
safety valves which, in the past, required considerable maintenance because
the operator was pressure testing through the valves and weakening them.
Test procedures have since been modified to bypass these valves during
tests and this has improved the operational efficiency and life span of the
valves. The flow lines are equipped with automatic valves. Injection wells
have check valves to prevent backflow. They are locked into the tubing at
a depth of 90 feet. Injection water (21,000 barrels per day) is obtained
from.outside sources. Headers have high-low shutdown equipment and
alarms.
A-30
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Pipelines - Pipelines from another site transfer wet oil to this site's
lines in 6-inch lines and gas in two lines of 6 and 8 inches. From this
site to the treatment facilities, the pipelines are two low pressure gas
lines of 8 and 10 inches at 180 psi each, one high pressure gas line of
8 inches at 300 psi, and a 12-inch wet oil line at 150 psi. These lines
are about 4 years old. Pigs are run in the oil lines every 2 weeks. In
the gas line, two ball pigs, with corrosion inhibitors between the two
pigs, are run every 4 weeks. Power operated block valves are set into
the lines leaving this site and at the entrance to the treatment plant to
prevent backflow.
Treatment Facilities - Although this site was not visited, it was stated
that all separators and gas scrubbers have high-low pressure shutdown
equipment and alarms.
Visit Number 5 - Company P's Texas Offices.
Purpose - To discuss operations in Southern California.
Personnel Contacted - Senior Vice President, Technical Manager of Environ-
mental Control, Administrative Manager of Environmental Control, General
Manager, and District Engineer.
Observations - Unable to arrange a mutually agreeable time to visit Company P's
facilities, an interview was arranged in their Texas offices to discuss their
operations. The information obtained is summarized as follows:
Production - Company P produces about 20,000 barrels of
oil and 180,000 barrels of water per day (90 percent water
cut). The wells are on mechanical lift. The producing wells
are old and the majority are in the Long Beach area. Since
many are inside dikes and below sea level, pumps are available to
A-31
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remove rain water (it is pumped into the channel). Although the
company representative did not discuss the details, Company P
apparently had pumped oil into the channel because a shut-off valve,
controlling the oil-water contact, failed to function. A preventive
maintenance program is currently in operation on these and all pumps.
Flow lines have been relocated away from dikes to avoid spills into
water bodies.
Pipelines - All lines over and under water are pressure tested. They
are low stress, extra wall thickness steel. Cathodic protection
devices are installed on underwater lines. The pipelines, as well as
flow lines, are equipped with high-low pressure shut-in devices and
quantity control meters (compares input and output of lines, then shuts
down line if there is a sufficient mismatch). In addition, all lines are
visually monitored from the dike banks.
Treatment - API gravity separators have been enlarged to accommodate
increased volume of produced water.
A.4. 5 Trip Number 5 - Louisiana Gulf Coast Survey (2 through 10 December 1971)
Visit Number 1 - Company G's Louisiana Onshore Treatment Facility
Purpose - To observe onshore and offshore facilities and procedures.
Personnel Contacted - Assistant Division Manager; Area Manager; Field Pro-
duction Superintendent, Main Pass Area; Field Foreman and Assistant Field
Foreman, Onshore Treatment Facility.
Observations - A visit was made to several of Company G's onshore crude oil
collocated treatment facilities. One facility treated and conditioned crude oil
produced from State leases in the delta region. The other facility was for treat-
ing and conditioning OCS production from platforms in the Main Pass. area. State
A-32
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lease production was produced from 49 wells; 25 are dual completion and 24
utilize gas-lift. The field contains 127 miles of flow lines, producing approxi-
mately 10,000 barrels of crude oil daily. The general configuration of the
facility is depicted in Figure A-5. All relief valves and rupture discs are
inspected semi-annually, the relief valves for operation and the rupture discs
for corrosion conditions. Rupture discs are coated with cosmoline to deter
corrosion from water. The valves are actuated by instrument gas derived from
the low pressure vessels backed up by gas from high pressure vessels. The
principal problems encountered at this facility, according to operating personnel,
have been sand plugging and sand cutting.
The Main Pass Onshore Terminal conditions the fluid from the Main Pass OCS
production pipeline prior to delivery to the pipeline. This facility is required to
conform to USGS regulation. Figure A-6 depicts the configuration of the Main
Pass Onshore Terminal. Approximately 50,000 barrels of crude oil and over
40,000 barrels of salt water are conditioned at this plant.
The salt water produced from State and OCS leases was emptied into a series of
three salt water pits with oil skimmers prior to disposal into the Bay. The
disposal point was enclosed by a floating boom encircling a large area as an
additional precaution to contain any oil that might, under flooding of the pits, or
other accidental circumstances, enter the Bay. The accumulated oil in the pits
or Bay would be vacuumed as events required.
Several miscellaneous items of interest were revealed during discussions with
company personnel. First, a formal spill contingency plan, ascribed to by the
major oil production companies in the area, contains locations of various spill
control equipment owned by the companies, names and phone numbers of each
company's spill control and cleanup assistance personnel, and assignments of
responsibilities to personnel during spill events. Second, the company has a
fire-fighting school which consists of classroom and hands-on exercises using
A-33
-------
(All
H. P.
Separator
To Gas Compressor
Facility
(All H. P. Separators)
1*
Automatic
Custody
Transfer
Figure A-5. Company G's Onshore State Lease Treatment Facility
-------
Brine Disposal
I
w
en
From
Main Pass
Block
To
Pipeline
Figure A-6. OCS Production Onshore Terminal
-------
fire-fighting equipment. Every employee who will be in an oil field, either
intermittently or full time, is required to go through the school as a refresher
course. Third, since January 1971, this company has had in effect a "Hydro-
carbon Noncontalnment Failure Report" system which gives details as to cause,
failed component or part, and corrective action taken for every noncontainment
event.
Visit Number 2 - Company G's Main Pass Offshore Production
Purpose - To observe Main Pass offshore production facilities and procedures.
Personnel Contacted - Main Pass Production Superintendent and Field Foreman
of two fields.
Observations - Several Main Pass Blocks were visited. Separation of gas and
liquid is performed on the offshore platforms in both areas whereas the oil-salt
water separation is performed at onshore facilities. The offshore production is
transported by a 14-inch production gathering pipeline to the Main Pass Onshore
Terminal. The production from another block is transported by the same pipeline
to the onshore treatment facilities for oil-salt water separation.
One of the offshore platforms in the block visited consists of three structures
connected by catwalks. These structures are crew living quarters platform,
oil production equipment and wells platform, and gas and compressor equipment
platform. This complex of platforms serves as the gas-liquid separation facility
for the wells as well as the pipeline gathering point for all block satellite source
well structures in addition to those wells on platform. In the event of a catas-
trophe, the complex is capable of being shut-in within 16 seconds, and the complete
field is capable of being shut-in within 3 minutes. Approximately 90,000 barrels
of liquid are produced daily through this complex from 107 producing wells.
Twenty-seven injection wells are utilized in waterflooding the associated
A-36
-------
reservoirs. The configuration of this complex is shown in Figure A-7. Compli-
ance and inspection reports in regard to USGS Orders 8 and 9 are summarily
reviewed.
The other field is 22 years old and produces about 10,000 barrels of crude oil
daily. The reservoirs have almost ideal water drive such that little water is
produced with the oil until the well suddenly starts producing mostly water, at
which time it is shut in. This field's production is from 75 strings which are
primarily dual completion wells. Since the water depth in the field is about 12
feet and the Gulf floor in that area is soft silt, the flowlines are buried about
12 feet below the floor level. In contrast to the central pipeline gathering complex
in the other field, the gas-liquid separation is performed on each individual plat-
form and each platform produces into a production gathering line system. In
turn, the gathering line system flows into headers to the pipeline for transportation
to the onshore treatment facility. This pipeline also transports the Company's
production from another Main Pass field. Problems experienced in the block
are caused by sand plugging and sand cutting. Figure A-8 is a diagram of a
typical configuration in this field.
Visit Number 3 - Company G's Bay Marchand Offshore Production and Onshore Treat-
ment Facilities
Purpose - To observe facilities and procedures in the Bay Marchand area and
older facility equipment.
Personnel Contacted - Area Manager, Field Product Supervisor, Structure Field
and Structure Assistant Field Foremen, Structure Foreman, and Onshore Treat-
ment Facility Foreman.
Observations - Two of the offshore facilities and an onshore treatment facility
were visited in the Bay Marchand area. The two offshore facilities were
similar. Each consists of three platform structures butted together instead of
A-37
-------
AA
(Typical for all
Wellheads)
Instrument
Gas System
Backup Supply
Wells <
H. P.
Separator
O9
CO
Notes:
Pressure Sensor, High/Low
Level Sensor, High
Fusible Plug
Parallel or Multiple Dump Valves
Robot Arm Shut-in
Manualmatlc Shut-in
To
Instrument
Gas System
. Test I 'jj J | Test I |J
. Separator] ; ~ (SeparatorI ,
x J. I v \ i i /
A-^
(Typical for
Separators)
all
(Typical at all
Flowlines)
To Flare
Figure A-7. Company G Main Pass Oil Production Platform
-------
CO
CO
Wells
o-
Notes; £J\ Pressure Sensors, High/Low
/
ator
V
\l
)
\
[Gas Lift
ISales
* r
i
V
Trans-
fer
Pump
To Pipeline Header
Via
Production Gathering
Line
Figure A-8. Typical Main Pass Oil Production Platform
-------
being interconnected by catwalks. The configuration of both structures consists
of a wellhead platform sandwiched between a separator platform and a com-
pressor/surge tank platform. One structure, however, has living quarters for
the crew, whereas the other structure only has several office quarters. The
daily output of the one structure is about 700 barrels. The wells have surface-
controlled (pneumatic) subsurface ball safety valves. Those wells having less
than 100 psi tubing pressure have storm chokes tied by wire to the wellheads,
instead of being installed in the production tubing. Such action has been approved
by waiver of USGS OCS Order No. 5. Instrument gas for the various shut-in
valves is obtained from the low pressure separation equipment with a backup gas
source from the high pressure system.
All enclosed buildings have gas detection and alarm systems which activate and
cause shut-in if the combustible gas level reaches 60 percent of the USGS
required maximum limit of 4.9 percent. Figure A-9 depicts the general con-
figuration of the structures. The onshore treatment facility receives liquid from
two state lease offshore areas as well as from the Bay Marchand and South
Timbalier Areas. All four sources of crude oil are required to be segregated
up to entry into the pipeline. Consequently, the liquid treatment facilities are
duplicated in several equipment areas. Figure A-10 presents the configurations
of this facility.
Visit Number 4 - Company ITs South Timbalier's Offshore OCS Operations
Purpose - To observe facility and procedures.
Personnel Contacted - Area Staff Engineer, Field Foreman, and Field Mainte-
nance Foreman.
Observations - The facility consists of five platforms interconnected by catwalks.
The five platforms of the complex consist of two separation platforms, a gas
compressor platform, a wellhead platform, and crew quarters platform. The
A-40
-------
Instrument Gas
(Typical on H. P. & L. P. Separators)
Wells \
System Backup Supply
(J
O-*
s^~^
-^
Manifold
>
r
/
! TV.
/
H. P.
Separatoi
/
\
J
I
\ ''
' T£p.T\ ! ' /TL. P"^ !
\--*J I Test I |J 1^| | Test I j I
\ iSeparatorj / \ |Separator| /
VJ [/ XL. _ _ _>*
To
L. P.
Separatoi
/
1 *"
i
Instrun
System
Surge
Tank
lent U
as
Transfer
Pump
To
Production
Gathering Line
Notes: /T\ Surface-Controlled Subsurface Safety Valve (or Storm Choke Tied to Wellhead)
/2\ Manualmatlcs
/3\ Fusible Plug
Pressure Sensor, High/Low
Level Sensor, High
Figure A-9. Company G Bay Marchand Oil Production Platform
-------
From Bay Marchand
Line
From South
Pipe Line
n i ii i r i
1
i
1
1
Heater
Treater
1 1
Depurator 1 Pump
Free Water
Automatic
Custody
Transfer
~|
<- *
Gun
Barrel
Storage
Tank
Automatic
Transfer
h -
...,fc,
^ To
Pipeline
\
<= =»
Storage
Tank
_J^\_
To
Pipeline
From State
Leases
Heater
Treater
i
Automatic
Custody
Transfer
Storage
Tank
. To
Pipeline
To
Bay
From Off-shore
Structures
(State Lease)
Figure A-10. Company G's Treatment Facility
-------
field produces about 40,000 barrels of crude oil daily from most of 190 source
wells. After gas-fluid separation at the facility, the crude oil is transported
by pipeline to the onshore treatment facility. Instrument gas is supplied from
the separation equipment. The instrument gas distribution system is composed
of nylon plastic tubing rated for 2500 psi and 168° melting point. This tubing
is used instead of fusible plugs, except at the wellheads and manifolds. The
pressure vessel equipment was configured to vent to a flare system which con-
tained a scrubber. The separation equipment consists of high pressure sepa-
rators with two dump valves (normal and high level), low pressure separators
with three dump valves (normal, high level, and high-high level), and a free
water knockout. Figure A-11 depicts the general configuration of the facility.
During the visit, a valve company maintenance man stationed at the complex
was contacted. He provided some insight to the failure modes of several
valve types that he maintained. It was also learned that Company H has a
failure and operating/maintenance error data system.
Visit Number 5 - Company B's New Orleans Office Visit
Purpose - To discuss their data program.
Personnel Contacted - District Production Superintendent and Special Staff
Engineer.
Observations - Company B was contacted to discuss their data program. The
Special Staff Engineer had recently transferred to the Gulf Coast area from
West Texas. In West Texas he was instrumental in the development and
implementation of Company B's initial formal preventive maintenance and data
collection program. This pilot program has been very successful, and he is
now working on a similar program for Company B's Gulf Coast operations. During
the meeting, the opportunity was afforded to see samples of the preventive mainte-
nance schedules and copies of the associated checklists and failure reports
currently in use in West Texas.
A-43
-------
Satellite
Wells
Plat-
form <
Wells
O
O
-^
IA
1
-. . /r"L~P.'
Test | L ^ | Test | r
"*"~ ' ' Separator^ /
I J. COt I I*
\ (Separator! /
M. i'
H. P.
Separatoi
^ ^ bepara
r\ T i/
~^
c
v
Flare
Scrubber
V \
L. P.
Separator
^Tlr
i L
/
V
^ /
H, P.
Separatoi / , V
rr
L. P.
Separator
Free
Water
K. O.
[\
/
/
< I Test | \* *-( I Test I P
\ 'Separator. / \ [Separator /
-I Ix ,| lx
Free
Water
K. O.
\
)
L
j *
£
^s
m
To Flare and
Compressor
Surge
Tank
To Pipe
Line
To
Water Disposal System
From Various
Platform
Areas
Figure A-ll. Company H South Timbalier Oil Production Facility
-------
A.4.6 Trip Number 6 - Continuation of Louisiana Data and Field Survey (7 through 18
January 1972)
Visit Number 1 - USGS New Orleans District
Purpose - To scope the data available in the District flies.
Personnel Contacted - Bert Mullins, New Orleans District Supervisor and Gene
Marsh of the USGS Eegional Office.
Observations - Items of interest obtained during the visit were:
The Items of Non-Compliance (INCS), Potential Items of Non-Compliance
(PINCS), and the USGS inspection forms were designed by a management
information section in the USGS Water Resources Division.
A copy of a speech given by Bob Evans to the oil industry at a meeting in
Houston, Texas, last fall was obtained. It contained statistics that
resulted from the USGS initial analysis of their inspection results. These
statistics gave numbers of check valves, subsurface valves, pressure
sensor pilots tested, and the numbers failing during the inspections. In
addition, statistics were given in relation to blowouts during drilling and
production operations.
Mr. Mullins suggested a report, "Environmental Quality, Second Annual
Report, " which he believes is worth reviewing.
A tabulation of the various reports and documents at the New Orleans
District Office, which would be of interest in relation to the project, is
given in Table A-l.
A-45
-------
Table A-l. Reports and Documents, New Orleans District Office
R epor t/Document
Quantity
Pollution (Spill) Reports
Production Inspection Reports (OCS-3)
Drilling Inspection Reports (OCS-2)
Accident Reports
Semi-annual Industry Inspection Records
(1 January - 1 July 1971)
Configuration Schematics
3,500
550
300+
480
15,000 pages
50
A review of spill reports indicate that they are sources of equipment failure
information which is of value to this study. Many of these failures are not
detailed in the monthly summary since they are spills of one barrel or less.
Visit Number 2 - Company J's Platform on the OCS in the Grand Isle Area
Purpose - To observe offshore operations and procedures.
Personnel Contacted - Petroleum Engineer, Platform Foreman, and Operator.
Observations - This platform serves as the gas-liquid separation point for
various well structures in the West Delta as well as other Grand Isle struc-
tures. Altogether 11 crude oil gathering lines and a number of gas gathering
lines from the various blocks enter this platform, varying in size from 6 to
16 inches. The daily production through this platform consists of approximately
85,000 barrels of liquid (65, 000 of crude oil and 20,000 of salt water). The
platform also serves as the metering point for sales gas. The complex consists
of the following five platform structures:
A-46
-------
1. Quarters, Control, and Electrical Generator Platform
2. Riser, Pig Trap, and Major Manifold Platform
3. Gas/Liquid Separators, Scrubbers, and Surge Tank Platform
4. Pumping Platform
5. Compressor Platform
The liquid is transported by a 20-inch pipeline to Grand Isle onshore treatment
facilities for further treatment prior to sales. This complex is being converted
to full automation.
There are 285 wells which produce into this complex, most being dual comple-
tion wells. The gas-lift wells have surface-controlled subsurface safety valves,
whereas the pressure wells have velocity-actuated storm chokes. Spring return
valves are used on all wellheads.
A dual supply of instrument gas is in use on this platform; an actuator supply
system supplies all the operators, and a gas instrument supply system supplies
the rest of the shutdown system. Each supply system is capable of backing up
the other. The gas is derived from a 16-inch gas line from another Grand Isle
block. It is scrubbed and filtered prior to use in the dual system. Natural gas,
instead of inert gas, is used in the dual system for economic reasons. The
daily quantity of gas used for these supplies is about 84,000 cubic feet. Conse-
quently, it would be costly to install special compressors for the dual system
supply and supply the quantity of inert gas that would be required if inert gas,
rather than the readily available natural gas, was used.
The operation is monitored and controlled through a panel on the crew structure
by electrical signals at the various sensors. The enclosed structures have both
ultraviolet monitoring and gas sniffer detection. The ultraviolet system will set
off an alarm but will not activate fire equipment since it is sensitive to water
reflections from the deck. The complex is operated by a foreman and two
operators, and hourly rounds are made on the platforms.
A-47
-------
The separation platform consists of a high pressure gas scrubber whose liquid
is dumped into the primary separators. The incoming oil line feeds into two
primary separator-scrubber combinations. The primary scrubbers and separ-
ators have two dump valves, one for throttling control and the other for surge
dumping. If a high level occurs in one primary separator, the oil is automati-
cally switched to the other, the same being true in relation to the scrubbers.
The oil then goes through three intermediate separators into three surge tanks.
The levels on the surge tanks, in turn, control the number and speed of the
transfer pump motors required to maintain the pumping capacity for the surge
tanks. These pumps can handle 300 percent of the normal flow capacity of the
complex.
The sump system consists of a drainage sump tank with a high level indicator
and dual pumps which pump the drainage into the surge tanks. Oil drainage
from the transfer pump bearings is pumped into the pipeline. In the event of
problems in the primary separators downstream, all production can be
bypassed back to the pipeline to Grand Isle. Oil gathered in the pig traps is
channeled back into the gathering line instead of the sump system. The main
problem experienced at the complex is sand-cutting of valve trim, primarily
on the dump valves. Consequently, an annual inspection/replacement of
valve trim is done as a preventive maintenance program. The schematic
diagram of this complex is presented in Figure A-12.
Visit Number 3 - USGS Districts 1 and 2 - Lafayette, Louisiana
Purpose - To determine the quantities of data of various types.
Personnel Contacted -
District No. 1: George Kinsel, Engineer; Robert Darrow, Assistant
Engineer; Al Davis, Chief Production Engineering
Technician
A-48
-------
^ High Pressure Gas to 2nd Stage Compressor
». Gas to 1st Stage Compressor
<£>
Emergency Bypass
To Pipeline
Transfer
Pump
. To
Pipeline
Figure A-12. Simplified Schematic of Company J Grand Isle Platform
-------
District No. 2: Elmo Hubble, Engineer; Jack Sandridge, Assistant
Engineer; Ted Hudson, Production Engineer; Derwood
Simpson, Chief Production Engineering Technician
Observations - As of June 1, 1971, The Gulf Region OCS operations had juris-
diction over the facilities summarized shown in Table A-2.
Table A-2. Summary of Facilities, Gulf Region OCS Operation
Facilities
Platforms
Single Wells
Multiple Wells
Production Platforms
District No. 1
372
219
134
29
District No. 2
955
496
357
102
New Orleans
479
122
321
36
In addition to the quantities of data shown in Table A-2, well status summaries
are available. These summaries are attached to the end of the USGS monthly
summaries and are available in their Washington, D. C. offices. A tabulation
of the quantities of various reports and documents at Districts 1 and 2 is given
in Table A-3.
Table A-3. Tabulation of Spill Reports - Districts 1 and 2
Report/Document
Pollution (Spill) Reports
Production Inspection Reports
(OCS-3)
Drilling Inspection Reports
(OCS-2)
Accident Reports
Semi-annual Industry Inspection
Records (1 Jan. - 1 July 1971)
Storm Chokes (12-month period)
District No. 1
Quantity
One 3 -inch Ringbinder
338*
98
12**
4,400***
4,400
District No. 2
Quantity
50/month
904
114
25
15,600***
26, 000
*From December 1971 to present, not including random "drop-in" inspections.
**Seven were major incidents. The first was dated May 14, 1971.
***For the first 6-month period. The next 6-month submittal which will be
approximately of equivalent quantities was due after 1 February 1972.
A-50
-------
Visit Number 4 - Office Visits to Companies B, H, and K and USGS Regional Office
Purpose - To determine the utility of Company H's data to the study, to discuss
Company K's maintenance records, to further discuss data with Company B, and
to discuss with the USGS various topics of interest.
Personnel Contacted - Area Staff Engineer of Company H, Assistant Drilling and
Production Manager of Company K, Special Staff Engineer of Company B, Robert
Evans (Regional Oil and Gas Supervisor), and Gene Marsh of the USGS.
Observations - The purpose of the visit to Company H was to determine if their
data would be useful to the study. However, the data was in response to OCS
Orders 8 and 9 and was already available through the USGS.
Company K's contact said that they did not keep failure or maintenance records.
They determine the adequacy of various brands of equipment by interviewing
their field personnel on their experience.
The letter to the environmental coordinator requesting failure and maintenance
data was discussed with the Company B contact. He felt he would be contacted
concerning the letter, but expressed the opinion that getting the failure and
maintenance data from Company B would be difficult.
Visit Number 5 - Company L's South Pass Facilities
Purpose - To observe facilities and procedures.
Personnel Contacted - Superintendent, South Pass; Chemical Engineer, Field
Foreman, South Pass Treatment Facility; Maintenance Foreman, South Pass
OCS Production.
Observations - The production from this facility is approximately 85,000 barrels
of crude oil daily produced from 250 dual and 300 single completion wells. The
wells are individually configured on platforms, with the produced well streams
A-51
-------
flowing to gas-liquid separation platforms and then transported to a freewater
knockout (FWKO) platform. After the offshore separation processes, the crude
oil and water are separately pipelined to onshore facilities where the crude oil
is further gas-oil separated, heated, further water-oil separated, reheated,
allowed to settle, then transferred and sold to a pipeline company or to barges.
The problems presently experienced in this operation have been external
corrosion on risers and plugging of bubbler valves in the water treatment
facilities. The oil spills occuring at the onshore facility have been at the barge
loading facility. Consequently, an automatic safety shut-in system with full-time
manned backup is enforced. Riser corrosion as well as corrosion at wellheads
and flowlines have been surveyed by X-ray to allow a maintenance program to
be set up. Sections of rubber-encased risers have been installed in the splash
zone areas of the flowlines to alleviate corrosion at these points.
While discussing the records for the USGS and Company L, it was learned that
job request records were filed at this facility for the period since March 1970.
The job request records contain the equipment involved, trouble indicated, date,
disposition, and related remarks. Approximately 15, 000 of these records are
available and accumulate at about 500 to 600 per month. This does not include
some repair actions which are accomplished without a formal job request.
Initially, the team was shown the onshore facility by the field foreman of the
treatment facility. It consists of two identical crude oil and salt water treatment
systems, one for OCS production and the other for State lease production. There-
fore, only one system will be described. The emulsified crude from offshore is
piped through a low pressure separator to further separate the gas from the
crude oil. The temperature of crude oil is raised 15 degrees by steam heat,
and the crude oil is transported to a surge tank where the water emulsion is sent
to the water treatment system. The crude oil is then passed through a heat
exchanger to be heated to 120°F before being transported to a settling tank
A-52
-------
(gun barrel). The water recovered at the settling tank is also sent to the water
treatment system. The crude oil is then piped to a LACT unit which consists
of a prover tank, meter, filter, BS&W probe-type monitor, and sampling tank.
The sampling tank oil is checked weekly to determine what corrections must be
made to the API gravity and BS&W content of the oil sold during the week.
The produced salt water and sand from offshore, between 12, 800 and 17,000
barrels per day, is routed to the water treatment facility along with water
recovered from the onshore surge and gun barrel tanks at the oil treatment
system. In addition, any emergency-diverted oil from the FWKO is diverted to
the water lines and transported to the onshore water treatment facility. Initially,
the produced water is diverted into two settling tanks. Each settling tank outlet
is diverted to two flotation cells prior to disposing clean water into the bay.
Recovered oil from the settling tanks and flotation cells is routed to the separator
at the crude oil treatment facility. Calcium deposits on the bubbling valves and
diaphragm of the flotation cells present a plugging problem which reduces the
efficiency of the water cleaning plant. A desander is also under test and evalu-
ation for potential use in reservoir pressure maintenance.
The maintenance foreman for South Pass OCS production showed the team a
platform typical of the gas-liquid separation platforms in the field. It is
positioned in 60 feet of water. This structure provides the gas-liquid separation
for 40 wells. The wells have pressure differential-activated storm chokes. The
wellheads and flowlines are cathodically protected. The production from these
wells enters the platform through a manifold equipped with high/low pressure
sensors. The flow then enters high, intermediate, and low gas-liquid separa-
tors. The gas is transported to the onshore compressor facility while the liquid
is transported to a FWKO platform. In addition to the three production separators
on the platform, there are three test separators (high, intermediate, and low).
All separators had high-level well shut-in capability. The separators are also
A-53
-------
equipped with throttling and surge dump valves, as are the FWKO vessels. The
FWKO vessels divert the crude oil into water and sand pipeline to shore in the
event of a high-level condition in the vessel {see Figure A-13). Both the gas-
liquid and the FWKO vessels are protected against corrosion by rectified cathodic
protection systems.
A simplified configuration schematic of the production system in South Pass and
the associated onshore facility is depicted in Figure A-13.
A. 4.7 Trip Number 7 - Company D*s New Orleans Division Office (15 through 18
August 1972)
Visit Number 1 - Company D's Office
Purpose - To view Company D's approach to crude oil spill prevention and
collect data.
Personnel Contacted - Environmental Control Engineer, Operations Engineering
Advisor, Task Force Engineer (Failure Reporting), Offshore Area Production
Superintendent, Associate Mechanical Engineer, Division Drilling Engineer, two
Division Computer Science Supervisors, and two Corporate Management Science
Engineers.
Observations - The team was presented with an overview of their approach to
spill prevention. The presentation lasted for the duration of this trip, conse-
quently, was the only facility planned for visitation. The presentation consisted
of descriptions of:
Failure data collection and analysis for safety devices
Failure data collection and analysis for storm chokes
Safety device inventory system
Blowout prevention school
A-54
-------
To 2nd Stage Gas Compressor
To 1st Stage Gas Compressor
To Vapor Recovery Stage of Gas Compressor Facility
Free
Water
Knockout
(FWKO)
Auto-
matic
Custody
Transfei
On Shore Crude Oil Treatment
-Liquid Separation Platform
From Flotation Cells
Emergency Diversion of Oil.
On Shore Water Treatment
To Bav
Sep.
Figure A-13. Company L's South Pass Production Operation
-------
Documented job descriptions
Procedures related to workover efforts
Procedure for ultrasonic inspection of piping
Computerized program for dynamic maintenance
Computerized program for redundancy considerations.
In February 1972, Company D organized a task force group to update its data
acquisition and control system to enhance its failure analysis capability and
collect the detailed data needed to allow them to utilize computerized reliability
and maintenance programs. This effort is presently directed to safety devices
and subsurface equipment. However, the task force will eventually address all
functional equipments in this production process. In conjunction with the failure
data collection, they are developing an inventory program to determine the
populations of the various equipments and components. With the failure data and
inventory systems, they will analyze the reliability and maintenance pertaining
to their operations to give them a capability to recommend the best items for
various applications, offshore safety equipment, and subsurface equipment
selections, and complete computerization of OCS Orders 5, 8, and 9. Copies of
Company D's safety device and storm choke failure reports, inventory worksheet,
and computer runs were examined. However, the data are preliminary and
contain too few entries to utilize for the present study.
A copy of Company D's drilling guidelines was also examined. They have had a
blowout prevention school since 1965. It consists of 2 days of lecture and 1 day
for each attendee to handle three different kick situations simulated in a well into
which a nitrogen bubble is introduced. Drilling foremen, drilling engineers, tool
pushers, and contract personnel involved in long-term programs are sent to the
school.
A-56
-------
Several computerized offshore facilities were discussed and a computer run from
1 day of operation was brought in. An example of how the computerized operation
lent itself as backup to the safety system was shown by the computer run as an
incidental fallout from computerization of the field.
The procedure followed, when a workover rig is brought to a platform, was
explained in relation to the wells and the platform. For example, these wells
not under the rig's substructure will be allowed to continue to produce after
inspection of their storm chokes. Downhole plugs are put in the wells under the
rig's substructure. A complete inspection of the safety equipment is made. A
judgement is made by the platform supervisor after discussion with the drilling
supervisor as to whether it is necessary to shut-in process equipment and fill
tanks with water. Another factor brought out during the discussion of production
was ultrasonic inspection of high pressure piping. It was learned that the
inspection frequency is increased if H S or CO are present. Whenever new
£ *»
storm chokes are installed on new wells or workovers, the chokes will be
inspected within 30 days. A manual of detailed job descriptions and personnel
requirements was shown. Computerized maintenance optimization strategies and
techniques were explained, followed by a walk-through of two examples based on
actual data from several refinery plants. An explanation was given as to the
extension and applicability of these programs to production facilities once the
production data system was in an implementable form.
A-57
-------
APPENDIX B
SUBSYSTEM DESCRIPTIONS
-------
TABLE OF CONTENTS
Appendix B - Subsystem Descriptions B-l
B. 1 Introductory Summary B-l
B. 2 Drilling System B-l
B. 2.1 Well Subsystem B-l
B. 2.2 Prime Power Subsystem B-4
B. 2.3 Hoisting and Rotating Subsystem B-5
B. 2.4 Mud Subsystem B-5
B. 2. 5 Drill String Subsystem B-6
B. 2.6 Blowout Preventer (BOP) Subsystem B-7
B. 3 Production System B-8
B. 3.1 Well Subsystem B-8
B. 3.2 Wellhead Subsystem B-9
B. 3.3 Gathering Subsystem B-9
B. 3.4 Separation Subsystem B-ll
B. 3. 5 Treater Subsystem B-ll
B. 3. 6 Local Storage Subsystem B-12
B. 3.7 Custody Transfer Subsystem B-12
B. 3. 8 Safety Subsystem B-14
B. 3.9 Water Disposal Subsystem B-14
B.4 Gathering/Distribution System B-15
B. 4.1 Pipeline Subsystem. B-15
B. 4.2 Storage Subsystem B-17
B.4.3 Pump Station Subsystem B-17
B. 4.4 Safety Subsystem B-18
B. 4. 5 Gathering Subsystem B-18
B-ii
-------
LIST OF ILLUSTRATIONS
Figure
B-l Elements of Crude Oil Systems B-2
B-2 Drilling System B-3
B-3 Well Subsystem B-4
B-4 Prime Power Subsystem B-4
B-5 Hoisting and Rotating Subsystem B-5
B-6 Mud Subsystem B-6
B-7 Drill String Subsystem B-7
B-8 Blowout Prevention Subsystem B-7
B-9 Production System B-8
B-10 Well Subsystem B-9
B-ll Wellhead Subsystem B-10
B-12 Gathering Subsystem B-10
B-13 Separation Subsystem B-ll
B-14 Treater Subsystem B-12
B-15 Local Storage Subsystem B-13
B-16 Custody Transfer Subsystem B-13
B-17 Safety Subsystem B-14
B-18 Water Disposal Subsystem B-15
B-19 Gathering/Distribution System B-16
B-20 Pipeline Subsystem B-16
B-21 Storage Subsystem B-17
B-22 Pump Station Subsystem B-18
B-23 Safety Subsystem B-19
B-iii
-------
APPENDIX B
SUBSYSTEM DESCRIPTIONS
B.1 INTRODUCTORY SUMMARY
This appendix supplements the system and subsystem descriptions presented in Volume I.
providing more detail to the descriptions and describing the functions in the equipment
within each subsystem. It is included to provide comprehensive description of petroleum
systems. The information was developed from field surveys, discussions with oil field
personnel, and study of texts, catalogs, and other petroleum system literature to provide
an analytical framework for data collection (Appendix D) and analysis (Appendix E). To
facilitate the use of this appendix, Figure B-l presents the systems and subsystems cross-
referenced to their appropriate block diagrams and functional details.
B.2 DRILLING SYSTEM
The Drilling System subsystems are given in Figure B-2 to allow orientation without
referring to Volume I. The Drilling System is broken down into six subsystems Well,
Prime Power, Hoisting and Rotating, Mud, Drilling String, and Blowout Preventer.
B.2.1 Well Subsystem
The Well Subsystem (Figure B-3) consists of equipment necessary for drilling operations
and provides protection from downhole natural phenomena, and protects the fresh water
strata. Sealing the casing to the hole walls is another function. The casing heads provide
a base upon which surface safety equipment and mud return control equipment can be
mounted and become a permanent part of the well. Consequently, the required functional
equipment are the hole, casing strings, casing heads, and cement. The depth, size, and
strength of the casings must be established from the anticipated pressures and formation
strengths downhole; the collapse, burst, and tensile requirements of the casing string;
and the future operational loads which may be imposed upon the casing. The casing
cement should be pressure tested at strategic intervals when approaching abnormal pres-
sure zones and drilling in them. The casing heads should be pressure rated with consid-
eration of maximum anticipated bottom hole pressure (BHP).
B-l
-------
DRILLING
SYSTEM
FIGURE B-2
SUBSYSTEMS
WELL {FIG. B-3)
PRIME POWER (FIG. B-4)
HOISTING AND
ROTATING (FIG. B-5)
MUD (FIG. 8-6)
DRILL STRING (FIG. B-7)
BLOWOUT
PREVENTER (FIG. B-8)
CRUDE OIL
SYSTEMS
PRODUCTION
SYSTEM
FIGURE B-9
SUBSYSTEMS
WELL (FIG.B-10)
WELLHEAD (FIG. B-11)
GATHERING (FIG. B-12)
SEPARATION (FIG. B-13)
TREATER (FIG. B-14)
LOCAL
STORAGE
(FIG. B-15)
CUSTODY
TRANSFER (FIG. B-16)
SAFETY
WATER
DISPOSAL
(FIG. B-17)
(FJG. B-18)
GATHERING/
DISTRIBUTION SYSTEM
FIGURE B-19
SUBSYSTEMS
PIPELINE (FIG. B-20)
STORAGE (FIG. B-21)
PUMP
STATION (FIG. B-22)
SAFETY (FIG. B-23)
GATHERING (FIG. B-20)
Figure B-l. Elements of Crude Oil Systems
B-2
-------
DRILLING
SYSTEM
WELL
SUBSYSTEM
MUD
SUBSYSTEM
PRIME
POWER
SUBSYSTEM
DRILL
STRING
SUBSYSTEM
HOISTING
AND
ROTATING
SUBSYSTEM
BLOWOUT
PREVENTER
SUBSYSTEM
Figure B-2. Drilling System
B-3
-------
OPEN
HOLE
WELL
SUBSYSTEM
CASING
STRINGS
CASING
HEADS
CEMENT
Figure B-3. Well Subsystem
B.2.2 Prime Power Subsystem
The Prime Power Subsystem (Figure B-4) provides power to the hoisting, rotating, and
circulating equipment, as well as utility power for peripheral uses and lights. The bulk
of the supplied power is used in either mud circulating and rotating or hoisting, which are
not usually simultaneous operations. The power is provided by internal combustion
engines or electric motors. Power transfer (both electrical and mechanical) and control
equipment are also parts of this subsystem.
PRIME
POWER
SUBSYSTEM
ENGINES
AND
CONTROLS
POWER
TRANSFER
AND
CONTROLS
Figure B-4. Prime Power Subsystem
B-4
-------
B.2.3 Hoisting and Rotating Subsystem
The Hoisting and Rotating Subsystem (Figure B-5) contains the equipment necessary to
raise and lower the drill string and to impart the rotary action that accomplishes the
drilling. The equipment includes the physical substructure over the well, which sup-
ports the derrick that provides the vertical clearance for drill string trips; the hoists
(draw works) that provide the control (clutches, engine throttles, sprockets, et cetera)
for the driller; the Rotary Table, which provides for collets (slips and drive bushings)
and rotates the drill string; and other related items shown in Figure B-5.
DERRICK
AND
SUBSTRUCTURE
CROWN
BLOCK
DRILLING
LINE
HOISTING
AND
ROTATING
SUBSYSTEM
ROTARY
HOOK
TRAVELING
BLOCK
DRAW
WORKS
ROTARY
TABLE
ELEVATORS
FLOOR
TOOLS
Figure B-5. Hoisting and Rotating Subsystem
B.2.4 Mud Subsystem
The Mud Subsystem (Figure B-6) controls the escape of fluids due to pressure of formula-
tions encountered during drilling, cools and cleans the drill bit, flushes the cuttings from
the hole, and cakes the walls of the hole to prevent sloughing and fluid loss. In perform-
ing these functions, the subsystem equipment provides circulating pressure, establishes
B-5
-------
a portion of the circulating flow path that interfaces with, the drill string and casing head,
and conditions the mud. Mud monitoring equipment is also vital to intelligent interpreta-
tion and control of downhole activity and conditions. Mud control is required to properly
handle hazards such as potential blowouts, lost circulation, heaving shale problems, and
salt section hole enlargement. The mud pump must circulate the mud at the desired
volume and pressure; the mud should not require excessive pump pressure at the desired
circulation rate.
Figure B-6. Mud Subsystem
B.2.5 Drill String Subsystem
The Drill String Subsystem (Figure B-7) includes the joined sections of drill pipe, the
drill bit, drill collars, kelly and kelly cock, swivel, and may also include special tools
to perform special functions. These are the tools required to drill to the necessary
depth while providing a circulating path for mud flow.
B-6
-------
Figure B-7. Drill String Subsystem
B.2.6 Blowout Preventer (BOP) Subsystem
The Blowout Preventer (BOP) Subsystem (Figure B-8) closes off the annular space between
the drill pipe and casing if the mud column in the hole becomes underbalanced with forma-
tion pressures and flow occurs during drilling operations. This situation is called a
"kick." Several available types of BOPs are pipe ram, blind ram, annular, or downhole
(new development). BOP equipment also controls pressures encountered until kicks are
cured by adjusting the weight of the mud column to the desired overbalanced condition.
Special kill equipment and procedures, in conjunction with the Mud Subsystem, can pro-
vide the means to maintain this control and to prevent blowouts.
"NEW DEVELOPMENT
(PART OF DRILL STRING)
Figure B-8. Blowout Prevention Subsystem
B-7
-------
B. 3 PRODUCTION SYSTEM
The Production System subsystems are given in Figure B-9 to allow reader orientation
without referring back to Volume I. The Production System is broken down into nine
functional subsystems Welt, Wellhead, Gathering, Separation, Treater, Local Storage,
Custody Transfer, Safety, and Water Disposal.
PRODUCTION
SYSTEM
WELL
SUBSYSTEM
TREATER
SUBSYSTEM
WELLHEAD
SUBSYSTEM
LOCAL
STORAGE
SUBSYSTEM
GATHERING
SUBSYSTEM
CUSTODY
TRANSFER
SUBSYSTEM
SEPARATION
SUBSYSTEM
SAFETY
SUBSYSTEM
WATER
DISPOSAL
SUBSYSTEM
Figure B-9. Production System
B.3.1 Well Subsystem
The Well Subsystem (Figure B-10) is a continuous path through which the liquids and gas
flow from the producing formation to ground level. The components required to perform
this task are producing zone, surface casing, intermediate casing (if required), oil
string casing, production tubing, packer, casing shoe, cement, liner hangers, and liners.
The basic Well Subsystem varies from well to well as production characteristics require.
The functions of the casing in a completed and producing well are to furnish a permanent
borehole of a known diameter through which production operation may be conducted, to
segregate formations behind pipe which permits production from specific zones and
B-8
-------
prevents interformational flow, and to provide a means of attaching surface valves and
connections. The cement provides additional support for casings and prevents formation
pressures from being imposed on the pipe. The cement also retards pipe corrosion by
minimizing contact between pipe and water formations.
WELL
SUBSYSTEM
PRODUCING
ZONE
CASING
STRING
AND
CEMENT
PRODUCTION
TUBING
DOWNHOLE
ASSEMBLY
Figure B-10. Well Subsystem
B. 3.2 Wellhead Subsystem
The Wellhead Subsystem (Figure B-ll) provides surface flow control of fluids produced
by the Well Subsystem and supports the weight of downhole equipment. As in the instance
of the well, the wellhead configuration is determined by the well characteristics. Basi-
cally, the wellhead equipment consists of casing head(s), tubing head, and surface con-
trols Christmas tree). Wellhead Subsystems vary widely to accommodate forms of arti-
ficial lift and flowing wells. Some of the variations encountered during the field surveys
were: Single Completion Flowing, Multiple Completion Flowing, Gas-Life, Rod Pump,
Hydraulic-Life, and Electric Downhole Pump.
B. 3.3 Gathering Subsystem
The Gathering Subsystem (Figure B-12) includes flowlines, manifolds, headers, fixed
and adjustable chokes, metering, and automatic control equipment. It transports the
crude oil from the various wells through the manifold at the gathering point, where
the output of the wells is directed to the separation and/or treatment processes to pre-
pare the oil for sale. Provision is usually made for isolating individual wells for peri-
odic well tests. The manifold consists of valve, headers, scraper (pig) traps, and
sometimes chokes, meters, and automatic control equipment.
B-9
-------
Figure B-ll. Wellhead Subsystem
Figure B-12. Gathering Subsystem
B-10
-------
B. 3.4 Separation Subsystem
The Separation Subsystem (Figure B-13) uses mechanical methods of separation, based
upon Stoke's law, to separate gas from produced liquids (oil, water, and emulsion).
Occasionally a three-phase separator is used to further separate the oil and emulsion
from the water. The basic equipment is gas-liquid separators and scrubbers. The gas-
liquid, gas-crude oil, or gas-crude oil-water separators fall into three categories:
high, intermediate, and low pressure. Scrubbers trap entrained liquids from the gas
prior to gas sale or other disposal. Throughput flow is controlled by automatic dump
valves and backpressure regulators, all of which are preset to automatically accommodate
continuous operations, normal variations, and surges.
HIGH PRESSURE
SEPARATORS &
CONTROLS
INTERMEDIATE
PRESSURE
SEPARATORS &
CONTROLS
SEPARATION
SUBSYSTEM
LOW PRESSURE
SEPARATORS &
CONTROLS
THREE
PHASE
SEPARATORS &
CONTROLS
SCRUBBERS &
CONTROLS
Figure B-13. Separation Subsystem
B.3.5 Treater Subsystem
The Treater Subsystem (Figure B-14) contains heater-treaters, chemical treaters, chem-
electric treaters, gun barrels, settling tanks, free water knockouts, skimming tanks,
and precipitators to further separate water/sediment which is emulsified within the crude
oil or to separate oil emulsified in water. Chemical injection to aid in demulsification
is also included under this subsystem. A vessel called a desander, designed to separate
sand from produced fluid, is included in the Treater Subsystem. The Treater Subsystem
throughput, like that of the Separation Subsystem, is controlled by automatically operated
dump valves and backpressure regulators.
B-ll
-------
TREATER
SUBSYSTEM
HEATER
TREATER
& CONTROLS
FREE WATER
KNOCKOUT &
CONTROLS
CHEMICAL-
ELECTRICAL
TREATER
& CONTROLS
GUN BARREL &
CONTROLS
DESANDER &
CONTROLS
SKIMMER
(SETTLING)
& CONTROLS
PRECIPITATOR &
CONTROLS
Figure B-14. Treater Subsystem
B. 3. 6 Local Storage Subsystem
The Local Storage Subsystem (Figure B-15) includes storage tanks, sump tanks, and
equipment such as pumps, valves, level indicators, and fire walls. The "flow," "lease,"
or "stock" tanks considered in the report are, primarily, or bolted or welded construction.
These tanks store the crude oil until it is sold to the pipeline. Either manual or automa-
tic monitoring and control of liquid levels provides for continuous receipt of oil into one
tank until it is full, and then switches the flow to another tank. High and low liquid
measurements can be used to calculate oil sales by the manual mode mentioned under the
Custody Transfer Subsystem.
B.3.7 Custody Transfer Subsystem
The Custody Transfer Subsystem (Figure B-16) gauges, switches, and measures the sales
grade crude oil to a customer, i. e., pipeline, barge, tanker. Typical configurations of
this subsystem are manual, lease automatic custody transfer (LACT). The subsystem
B-12
-------
consists of pumps and their controls, manifolds, prover tanks, BS&W monitor equipment,
metering, and sampling equipment.
TANKS
TANK
ASSOCIATED
EQUIPMENT
LOCAL
STORAGE
SUBSYSTEM
SUMP
FIREWALL
Figure B-15. Local Storage Subsystem
POWER
PUMPS
PUMP
CONTROLS
CUSTODY
TRANSFER
SUBSYSTEM
MANIFOLD
METER
EQUIPMENT
SAMPLING
EQUIPMENT
PROVER
TANK
POWER
Figure B-16. Custody Transfer Subsystem
B-13
-------
B.3.8 Safety Subsystem
The Safety Subsystem (Figure B-17) protects facilities, equipment, personnel, and wells
by providing selective or overall shutdown and/or alarm if a fire occurs or if pressures,
temperatures, liquid levels, or gas concentrations have exceeded previously determined
limits. The subsystem equipment may include remote (surface) controlled subsurface
safety valves, velocity controlled subsurface safety valves (storm chokes), surface
safety valves, monitoring and actuating pilots and sensors, fusible plugs, fusible control
distribution lines, liquid level sensors, pressure sensors, gas sniffers and detectors,
safety system energy source (s), and monitoring and alarm panels. Appendix J provides
additional information on safety shutdown devices from USGS data from Gulf OCS inspec-
tions.
Figure B-17. Safety Subsystem
B. 3.9 Water Disposal Subsystem
The Water Disposal Subsystem (Figure B-18) consists of water conditioning schemes used
to process the water to meet various requirements prior to disposal. These conditioning
processes include disposal of produced salt water or injection of water into oil producing
formations to enhance recovery of the oil. The equipment in this subsystem complements
B-14
-------
the equipment that processes water in various other subsystems, such as the Treater
Subsystem. Some of the equipment comprises filters, clarifying tanks, flotation cells
(both diffused gas or floculant types), oxygen stripping tanks, various pumps and turbines,
settling pits or tanks, and injection wells and associated equipment.
Figure B-18. Water Disposal Subsystem
B.4 GATHERING/DISTRIBUTION SYSTEM
The Gathering/Distribution System subsystems are given in Figure B-19 to allow reader
orientation without referring back to Volume I. The Gathering/Distribution System is
broken down to five subsystems Pipeline, Storage, Pump Station, Safety, and Gather-
ing.
B. 4.1 Pipeline Subsystem
The Pipeline Subsystem (Figure B-20) is the pipeline network through which crude oil
is transported from a control gathering point to a terminal area. The Pipeline Subsystem
consists of pipe, scraper trap equipment, pipe supporting structures, stream crossing
equipment, and road crossing equipment. The latter two are underwater or underground
to provide safe crossing of waterways, land rights-of-way (including highways and rail-
roads), and populated areas. Overhead crossings (or bridge crossings) are not considered
since the data were insufficient to support analysis.
B-15
-------
GATHERING
AND
DISTRIBUTION
SYSTEM
PIPELINE
SUBSYSTEM
PUMP STATION
SUBSYSTEM
STORAGE
SUBSYSTEM
SAFETY
SUBSYSTEM
GATHERING
SUBSYSTEM
Figure B-19. Gathering/Distribution System
PIPE
Figure B-20. Pipeline Subsystem
B-16
-------
B. 4.2 Storage Subsystem
The Storage Subsystem (Figure B-21) provides short-term storage for receiving, sorting,
measuring, and rerouting. The subsystem includes tanks, tank firewalls, tank-associated
equipment, and power. The spacing of tanks is determined by the safe containment of
oil in the event of a catastrophe. The firewall is designed to contain more than the
contents of the tanks it surrounds.
STORAGE
SUBSYSTEM
TANK
TANK
FIREWALLS
TANK
ASSOCIATED
EQUIPMENT
POWER
Figure B-21. Storage Subsystem
B.4.3 Pump Station Subsystem
The principal function of the Pump Station Subsystem (Figure B-22) is to provide the
energy to overcome transmission energy losses and to transport the oil through the
Gathering/Distribution System to its destination. Pumps, driven by their associated
prime movers, overcome these losses. Flow control and switching in the subsystem are
done by manifold equipment. Batch control at the Pump Station is done by metering equip-
ment and communications equipment used to coordinate with the pipeline dispatcher.
B-17
-------
PUMP
STATION
SUBSYSTEM
PUMP&
CONTROLS
POWER &
CONTROLS
MANIFOLDS &
CONTROLS
COMMUNICATIONS
EQUIPMENT
METERING
EQUIPMENT
Figure B-22. Pump Station Subsystem
B.4.4 Safety Subsystem
The Safety Subsystem (Figure B-23) provides for alarm or shutdown of operations through
instruments indicating pipeline breaks, leaks, pump vapor locks, fire, explosive mixtures,
or other undesirable conditions. Monitoring and control instrumentation of other sub-
systems are used to maintain desirable suction and discharge pressures and to detect
leaks, breaks, or other pump station failures. High-level alarms on sumps and low air-
pressure alarms on controllers of automated valves are examples of other safety devices
in- use. Appendix J provides additional information on safety shutdown devices from Gulf
OCS inspections.
B. 4. 5 Gathering Subsystem
The Gathering Subsystem performs a switching and gathering function using components
essentially the same as those in the Pipeline Subsystem (see Figure B-20).
B-18
-------
Figure B-23. Safety Subsystem
B-19
-------
APPENDIX C
SOURCE DATA BANK DESCRIPTIONS
-------
TABLE OF CONTENTS
Appendix C - Source Data Bank Description C-l
C. 1 Introductory Summary C-l
C. 2 Description of Source Data Banks C-l
EPA Headquarters-OHM File C-4
EPA Anchorage Alaska C-6
DOT/FRRC C-7
U. S. Coast Guard C-9
U. S. Geological Survey C-10
Alaska Department of Natural Resources C-12
Arkansas Oil and Gas Commission C-13
California Department of Fish and Game Commission. C-14
California Water Quality Control Board C-16
California Division of Oil and Gas C-17
California City of Long Beach C-18
Colorado Department of Health C-19
Louisiana Department of Conservation (New Orleans File) C-20
Louisiana Department of Conservation (Baton Rouge File) C-22
Mississippi Oil and Gas Board C-23
New Mexico Oil Conservation Commission C-24
Oklahoma Corporation Commission C-25
Texas Railroad Commission C-26
California Western Oil and Gas Association C-27
Alberta Oil and Gas Conservation Board C-28
Alberta Department of Mines and Minerals C-30
C-ii
-------
LIST OF ILLUSTRATIONS
Figure
C-l Format for Development of Source Data Bank Descriptions C-2
C-2 List of Oil Spill Data Sources Contacted 0 ....... C-3
C-iii
-------
APPENDIX C
SOURCE DATA BANK DESCRIPTION
C.I INTRODUCTORY SUMMARY
The spill prevention program described in this report has wide application to United
States petroleum systems as a result of the broad data base from the several sources
described in this appendix. Data requirements, in terms of specific data elements,
were established early in the study and are documented in Appendix K. A search was
conducted to locate sources of oil spill data from Federal activities and agencies of
major oil-producing States. Data were collected by having study team engineers con-
tact the source agencies, review the data at the agency's facilities and identify the
spill records of interest to this study. To properly use the data, information describ-
ing each source was required. This appendix is included to evaluate the data in
Appendix D in terms of the specific data sources. The format shown in Figure C-l
was developed as a guide to the type of information desired for each data bank.
C.2 DESCRIPTION OF SOURCE DATA BANKS
The data banks that were contacted as sources for oil spill events are listed in
Figure C-2. The remainder of this appendix presents descriptions of each bank, to
the extent that information was available, according to the format of Figure C-l.
C-l
-------
1. Data Bank Name; Indicate the name of the data bank.
2. Data Bank Location: Indicate the name and address of the agency that has custody
of the Data Bank.
3. Data Bank Structure; Indicate the way the data is presented, such as use of forms,
summary reports, computerization, etc.
4. Scope: Describe the coverage and depth of the data. Indicate what is and is not
covered by the data source in regard to cause and prevention of oil spillage.
Identify reporting relationships with other data banks: Is this a central data
bank? Are there other banks that supply this bank? Is this a local or regional
bank? Are there other banks that receive data from this bank? Identify name and
location for related banks.
5. Reporting Requirements; Describe the requirements for reporting a spill. Indicate
when the report is to be filed, who is required to report, to whom, where, and the
regulation that sets down the requirement. Include copies of any reporting forms
and instructions.
6. Purpose: Describe, to the extent possible, the agency's purpose for having the data
bank and what the agency does with the bank. Is the actual use of the same as the
stated purpose? If purpose of the data bank is not clear, so state.
7. Items Contained in Data Bank: Describe any data elements that may need clarifica-
tion or interpretation. Include any data element description or definitions.
8. Time Span Covered by Study Data: Indicate the start and end dates of the data used
in the study.
9. Volume of Data: Indicate the number of reports on crude oil spills. Record the
number of reports on spills of other products also.
10. Limitations and General Comments on Data Bank: Present any comments on the
data and specify any deficiencies of the data bank with regard to this study.
Figure C-l. Format for Development of Source Data Bank Descriptions
C-2
-------
Federal
1. Environmental Protection Agency Headquarters Oil and Hazardous Material File
2. EPA Anchorage, Alaska
3. Department of Transportation/Federal Railroad Commission Pipeline Carrier
Accident Reports
4. U. S. Coast Guard
5. U.S. Geological Survey, Conservation Division, Washington, D.C. Office
States
* 1. Alaska Department of Natural Resources, Division of Oil and Gas
* 2. Arkansas Oil and Gas Commission
3. California Department of Fish and Game Commission
4. California Water Quality Control Board
5. California Division of Oil and Gas
6. California City of Long Beach, Department of Oil Properties
7. Colorado Department of Health, Water Pollution Control Division
8. Louisiana Department of Conservation, Division of Minerals
(2 files: New Orleans and Baton Rouge)
9. Mississippi Oil and Gas Board
10. New Mexico Oil Conservation Commission
11. Oklahoma Corporation Commission, Oil and Gas Conservation Division
12. Texas Railroad Commission, Oil and Gas Division
Other
* 1. Western Oil and Gas Association, California
2. Alberta, Canada Alberta Oil and Gas Conservation Board
* 3. Alberta, Canada Department of Mines and Minerals, Superintendent of
Pipelines
* Data from these sources were not pertinent to this study.
Figure C-2. List of Oil Spill Data Sources Contacted
C-3
-------
EPA HEADQUARTERS-OHM FILE
1. Data Bank Name: Environmental Protection Agency
Oil and Hazardous Material (OHM) File
2. Data Bank Location; Environmental Protection Agency
Office of Water Programs
Arlington, Virginia
3. Data Bank Structure; Narrative data are transcribed from situation reports onto
data forms for subsequent entry into a time-shared computer system file. Twenty-
eight data items are included, the majority of which are of unknown length.
4. Scope; The file provides a record of oil and hazardous material spills reported
to EPA via a number of government agencies.
5. Reporting Requirements; Extracted normally from situation reports by USCG
and USGS, related to spills of interest. EPA does not generally get direct
reports, although representatives may provide on-site monitoring.
6. Purpose; The file serves the EPA staff as a ready in-house source of up-to-date
information on OHM spill events of interest. It may also provide data to support
recommended regulations.
7- Items Contained in Data Bank; The data file record permits the storage of at least
the following data items that were of use to this study:
Title - a short title given to the spill event, followed by the spill location:
State, County, City.
Date spill occurred - self explanatory: month, day, and year.
Duration of spill - self explanatory: in days, hours, and minutes.
Type of water area - one of 11 specific descriptors.
Quantity spilled - the quantity of oil spilled: in barrels, gallons, or pounds.
Source of spill - identity of the exact or suspected source of pollution or
threat of pollution.
Organization causing spill - the name and address of the responsible party
or suspected responsible party.
Specific cause - description of activity surrounding the cause.
Type of operation - self-explanatory.
8. Time Span Covered by Study Data: June 1969 to June 1971.
C-4
-------
9. Volume of Data; 113 reports of crude oil spill events. 108 reports were used in
this study.
10. Limitations and General Comments on Data Bank; A manual review of all data
recording forms for the file indicates three deficient areas that limit its utility
in some applications. These are:
a. The data items are stored in narrative format with little recording
standardization.
b. Many of the identified data items contain no information.
c. The file does not provide specific information on the hardware-related
causes of spills.
C-5
-------
EPA ANCHORAGE ALASKA
1. Data Bank Name; Environmental Protection Agency
Anchorage Office File
2. Data Bank Location: Environmental Protection Agency
Federal Building (Post Office Building)
602 4th Street
Anchorage, Alaska
3. Data Bank Structure; The data bank consists of handwritten notes of observations,
telephone messages, USCG Form CG 3639 Water Pollution, Federal Water
Quality Administration (Alaska Operations Office) Oil Pollution Report, memoranda,
FAA reports, and TWXs. Reports are chronologically filed.
4. Scope: It was indicated that this oil spillage file was the most complete in the
Alaskan area, including State and Coast Guard files. The following data is
usually attained, even though in widely variable format:
Date and Time Received
Date and Time of Occurrence
Location
Source of Information
Description
Action Taken
5. Reporting Requirements; No formal requirements are apparent. However,
reports usually contain the items listed in item 4, Scope.
6. Purpose; To keep track of oil pollution in waters and to identify offenders for
appropriate action. Also monitors events and evaluates clean ups.
7. Items Contained in the Data Bank; Any pollution affecting water quality or game
and wildlife. Very informal reporting, therefore, it cannot be presented in a
formalized approach.
8. Time Span Covered by Study Data; The data cover the period from 1966 through
the first week of August 1971.
9. Volume of Data; There were 70 reported crude oil spills contained in the data
bank. The number of reports on spills of other products is unknown. 68 reports
were used in this study.
10. Limitations and General Comments on Data Bank: The data is limited for purposes
of reliability analysis. The data is oriented toward environmental effects, contain-
ment, and clean up of spills.
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DOT/FRRC
1. Data Bank Name; Department of Transportation (DOT)
Federal Railroad Administration
Pipeline Carrier Accident Reports, DOT Form 7000-1
2. Data Bank Location; Federal Railroad Administration
Department of Transportation
400 6th Street, S.W.
Washington, D. C.
3. Data Bank Structure; Report forms are filed as they are received. They
are grouped by company with each file folder containing spills by a company.
These reports are not computerized.
4. Scope; An accident report (DOT 7000-1) is required to be submitted
within 15 days of any failure in a pipeline system resulting in any of
the following:
a. Explosion or fire not intentionally set by carrier.
b. Loss of 50 or more barrels of liquid.
c. Escape to the atmosphere of more than five barrels a day of
liquefied petroleum gas or other liquefied gas.
d. Death of any person.
e. Bodily harm to any person.
f. Property damage of at least $1000 to other than the carrier's
facilities.
5. Reporting Requirements; The report is to be filed with the Administrator,
Federal Railroad Administration, Department of Transportation, Washing-
ton, D. C. by the responsible carrier company.
6. Purpose; Any company coming under ICC regulations is required to
submit Form 7000-1. The reports are intended to form a basis for
judging the effectiveness of existing regulations and for indicating need
for action in protecting public interests.
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7. Items Contained in Data Bank;
a. Part I - Accidents caused by corrosion.
b. Part J - Accidents caused by equipment rupturing the pipeline.
c. The carrier is to provide an account of the accident.
8. Time Span Covered by Study Data; Beginning of 1968 to August 1971.
9. Volume of Data; There were 860 reports on file at DOT containing
data on crude oil spills. 802 reports were used in this study.
10. Limitations and General Comments on Data Bank; The major deficiencies
of Form 7000-1 are as follows:
a. There is no consistency of information contained in the narrative
portion of the form.
b. No accurate assessment can be made of the volume of oil spilled.
c. The repairs made and the parts replaced are not often given.
d. The length of time of the leak is not often given.
e. It is usually impossible to distinguish between production and
transportation pipelines.
f. It is usually impossible to distinguish between gathering
and trunk pipelines.
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U. S. COAST GUARD
1. Data Bank Name; Department of Transportation
U. S, Coast Guard
Law Enforcement Branch File
2. Data Bank Location; Department of Transportation
U. S. Coast Guard
Washington, D.C.
3. Data Bank Structure; Water pollution incidents are classified as major
or minor. Major events are covered by U.S. Coast Guard Form CG 3639
(Rev. 7-68). Minor events are reported as single line entries, usually
by TWX. Data in 1970 and subsequent have been coded and computerized
but no narrative has been included. A series of computer summaries is
available.
4. Scope; Data prior to 1970 is very limited. The data bank covers all
types of water pollution within coastal and navigable waters (including inland
waters, the Great Lakes, the high seas, and the continuous zone).
5. Reporting Requirements; Any pollution incident threatening navigable water
is reported.
6. Purpose: The data bank supports the law enforcement responsibilities
of the Coast Guard and provides a basis for pollution control or prevention
in water under cognizance of the U. S. Coast Guard.
7. Items Contained in Data Bank; Only those incidents that resulted in a
water pollution problem.
8. Time Span Covered by Study Data; January 1970 through June 1971.
9. Volume of Data; 3743 major pollution incidents were recorded in 1970.
No reports were used in this study.
10. Limitations and General Comments on Data Bank;
a. Less than 1 percent of the recorded incidents pertained to crude oil
spills from Drilling, Production, and Gathering/Distribution Systems.
b. Inland incidents, which did not threaten navigable water were not
usually recorded in this data bank.
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U.S. GEOLOGICAL SURVEY
1. Data Bank Name; Department of the Interior
Geological Survey
Monthly Pollution Report
2. Data Bank Location; Department of the Interior
Geological Survey
Conservation Division
General Services Administration Building
Room 3243
Washington, D.C.
3. Data Bank Structure; The USGS Office in Washington receives a Monthly
Pollution Report from Regional Offices in New Orleans and Los Angeles.
These reports give brief descriptions of all reported oil spills in each
OCS region in short narrative form. About 12 incidents are recorded,
sequentially by date of occurrence, on each page.
4. Scope; For each reported offshore oil spill the information includes date
of spill, place, amount, cause, and repair action taken. The USGS
exercises control over about 40,000 oil wells on Federal and Indian
lands. The main offshore drilling and production of petroleum is in the
Gulf Coast region. About 8000 wells are included in U. S. offshore
operations. There are no reports on spills in land operations.
5. Reporting Requirements; The USGS has initiated a monitoring program
of all offshore drilling and production wells. As of July 1971, a fleet of
six helicopters continually observe drilling and production activities.
6. Purpose; The USGS supervises operations incident to the prospecting,
development, and production of minerals on Federal, Indian, and Naval
Petroleum Reserve Lands under Federal lease, license, and prospecting
permits.
7. Items Contained in Data Bank; A file of the Monthly Pollution Reports is
maintained.
8. Time Span Covered by Study Data; The Monthly Pollution Report was
initiated in June 1970. The data coverage extends from June 1970 through
October 1971.
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9. Volume of Data; 643 oil spill events. 633 reports were used in this study.
10. Limitations and General Comments on Data Bank;
a. The Monthly Pollution Report contains quite brief summaries entered
by dates of occurring events, but the data content does not support
reliability analysis.
b. In the onshore area of USGS responsibility there is no documentation
of pipeline spills and none on drilling or production except for major
blowouts.
C-ll
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ALASKA DEPARTMENT OF NATURAL RESOURCES
1. Data Bank Name; Alaska Department of Natural Resources
Division of Oil and Gas File
2. Data Bank Location; Division of Oil and Gas
3001 Porcupine Drive
Anchorage, Alaska 99504
3. Data Bank Structure; Undefined.
4. Scope; It was indicated that any crude oil spillage event would be in the
EPA Anchorage, Alaska file.
Information on Items 5 through 10 was not determined.
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ARKANSAS OIL AND GAS COMMISSION
1. Data Bank Name: No spill data file exists.
2. Data Bank Location; None.
3. Data Bank Structure; A letter report to the Commission is required for oil losses
that exceed 25 barrels.
4. Scope; Rule B-34 of the General Rules and Regulations Relating to Oil and Gas of
the State of Arkansas requires that the Commission be notified immediately by
letter of fire, breaks, leaks, or blowouts. The letter should cover any destruction
of gas or oil, leaks from tanks or pipelines, overflowing of tanks, and steps taken
or in progress to remedy the situation. A report is necessary only when losses
exceed 25 barrels.
5. Reporting Requirements: It was indicated that spill reports are not required.
However, there is a requirement that pipeline losses are reported as to quantity
spilled, how much recovered, and where the balance went. No additional details
are given. This information is noted and included in monthly inventory reports
required by the state. The same type reports are submitted monthly by producers;
these are purely inventory control and do not require spill reports.
6. Purpose: Inventory control of crude produced, stored, and transported in advance
for regulatory purposes.
7. Items Contained in Data Bank; None at time of review.
8. Time Span Covered by Data Bank; None.
9. Volume of Data; None.
10. Limitations and General Comments on Data Bank; A legal requirement exists for
letter reporting of certain types of oil spillage exceeding 25 barrels. However,
a permanent record file has not been established.
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CAIIFORNIA DEPARTMENT OF FISH AND GAME COMMISSION
1. Data Bank Name; State of California
Department of Fish and Game (F&GD)
2. Data Bank Locations: Data on pollutants, including oil, entering California
water bodies are maintained in the headquarters office in Sacramento and
the regional offices.
3-4. Data Bank Structure and Scope; The structures of the three data banks
that were reviewed varied considerably. Each data bank is discussed
separately.
a. Headquarters - Reports, including those on the WQCB Form C-ll,
are submitted on all types of polluting incidents. A majority of these
reports deal with pollution by manufacturing, transportation, and
agricultural systems.
b. Region 3 - A "Citation Record" card file is maintained which contains
items of legal action proposed or pending against polluters. This file
contains mostly complaints against shipping companies for bilge
pumping and loading-unloading spillages. The information items on
the cards are designed to provide documentation on the history of
legal action and do not generally delve into causes.
c. Region 5 - The only formal data was a compilation made for the year
1967. It contained information on (1) date, (2) company name, (3)
operation (i. e., production, tank farm, etc.), (4) cause, (5) barrels
spilled and (6) action (legal).
Note: Data from Regions 1, 2, & 4 was nil.
5. Reporting Requirements; The Department of Fish and Game has a standard-
ized form for use throughout the state.
6- Purpose; To support legal action by the Department of Fish and Game
against those who are responsible for pollution of California waters.
7. Items Contained in Data Bank; The total data bank consists of complaints
from all sources of pollution, i. e., petroleum, transportation, manufactur-
ing, agricultural and other industries or individuals. On oil spills related to
the petroleum reliability study, the most common information items are
(1) spill date, (2) operator's name, (3) time, (4) location, (5) limited
details and (6) data related to actions and activities of Federal, State, and
local agencies.
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8. Time Span Covered by Study Data; The data collected covers the period
as follows:
Headquarters - January 5, 1970 to September 8, 1971
Region 3, San Francisco - May 25, 1969 to January 3, 1970
Region 5, Long Beach - January 3, 1967 to December 29, 1967
9. Volume of Data:
Headquarters - Of 1000 spills recorded, only 24 were relevant to this study.
Region 3, San Francisco - Of 200, only seven were relevant.
Region 5, Long Beach - Of 78 citations in 1967, 55 were relevant.
A total of 63 non-duplicated records were used in this study.
10. Limitations and General Comments on Data Bank; The major deficiencies
are as follows:
a. Mandatory written reports on a standardized form are not required.
b. Available reports lack technical detail necessary to reliability
analysis.
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CALIFORNIA WATER QUALITY CONTROL BOARD
1. Data Bank Name; State of California
Water Quality Control Board (WQCB)
2. Data Bank Locations; Oil spill data records are maintained in some
regional offices, but not in the headquarters office, Sacramento.
3. Data Bank Structure; WQCB Form C-ll is used to document details of
pollutants entering state waters. Use of this form does not seem to be
a standard practice for all districts in the state and for all polluting
incidents within any district.
Data for three oil spills for Region 3 was provided from information in
the files.
4-5. Scope and Reporting Requirements; The Porter-Cologne Water Quality
Control Act of November 1970 establishes that any discharge of waste
that could affect water quality in the state must be reported.
6. Purpose; To serve the intent of the Porter-Cologne Water Quality Control
Act.
7. Items Contained in Data Bank; The total data bank consists of complaints
from all sources of pollution, i. e., petroleum, transportation, manu-
facturing, agricultural and other industries or individuals. On oil spills
which are related to this study, the most common information items are
(1) spill data, (2) operator's name, (3) time, (4) location, (5) limited de-
tails, and (6) data related to actions and activities of Federal, State and
local agencies.
8. Time Span Covered by Study Data; September 1968 through September 1971.
9. Volume of Data; Twenty-one spill events, of which one was water, one
was refined petroleum products, and the balance were crude oil. 19
reports were used in this study.
10. Limitations and General Comments on Data Bank; Available reports
lack technical detail necessary to reliability analysis.
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CALIFORNIA DIVISION OF OIL AND GAS
1. Data Bank Name; State of California
Division of Oil and Gas File
2. Data Bank Location; Oil spill data records are maintained in the district
offices.
3. Data Bank Structure; Report forms are not required by the Division of
Oil and Gas. All spills are phoned in by representatives of Federal, State,
county, or city political entities, oil companies, or private citizens. On
occasions, the oil companies submit a letter. Some districts maintain
no records; other districts keep a clipboard file.
4-5. Scope and Reporting Requirements; In 1969, the Division of Oil and Gas
was assigned responsibility for monitoring all oil spills.
When an oil spill occurs, the event is logged into the file and relayed to
interested parties.
6. Purpose; To monitor oil spills.
7. Items Contained in Data Bank; Key elements are spill date and time,
operator's name, product spilled, location, volume of spill, area
covered by spill and cause (if known).
8. Time Span Covered by Study Data; January 1969 through September 1971.
9. Volume of Data; Forty crude oil spill reports are on file in the
various districts and were used in this study.
10. Limitations and General Comments on Data Bank; Available reports
lack technical detail necessary to reliability analysis.
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CALIFORNIA CITY OF LONG BEACH
1. Data Bank Name: City of Long Beach, California
Department of Oil Properties File
2. Data Bank Location: Department of Oil Properties
Harbor Building
Long Beach, California
3. Data Bank Structure; Narrative record maintained on a clipboard, no format.
4-5. Scope and Reporting Requirements; The Department of Oil Properties requires
all oil companies that produce hydrocarbons from city-owned properties to report
oil spills.
6. Purpose; To monitor and control spills of oil and other hazardous material.
7. Items Contained in Data Bank; Information items usually obtained are (a) spill
date and time, (b) operator's name, (c) location, and (d) volume of spill
or area covered by oil. Occasionally the cause and material spilled is reported.
8. Time Span Covered by Study Data; April 1968 through January 1971.
9. Volume of Data; Thirty crude oil spills were recorded and used in this study.
10. Limitations and General Comments on Data Bank; Data lacks technical detail
necessary to reliability analysis.
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COLORADO DEPARTMENT OF HEALTH
1. Data Bank Name; State of Colorado
Department of Health
Water Pollution Control Division File
2. Data Bank Location; Colorado Department of Health
Water Pollution Control Division
4201 East llth Avenue
Denver, Colorado 80220
3. Data Bank Structure; Oil spillage incidents are reported by means of memoranda,
letters, activity reports, etc., which are generated by field observers of many
state and some Federal agencies.
4. Scope; Reporting is chiefly oriented toward fresh water pollution. State Oil and
Gas Board Rules and Regulations adopted in August 1971 do not establish any data
requirements for pollution control or reporting of oil spills.
5. Reporting Requirements; There are no definite reporting requirements prescribed.
6. Purpose; A spill report form seems to be an "in-house" medium for documenting
any kind of a substance spill.
7. Items Contained in Data Bank; The data items covered vary with individual reports
and pertain to any spilled substance.
8. Time Span Covered by Study Data; April 1968 through September 1971.
9. Volume of Data; 12 spill events, of which 10 were crude oil, one was refined
petroleum products, and one was other hazardous material. The 10 crude oil
reports were used in this study.
10. Limitations and General Comments on Data Bank; Available data lack technical
detail necessary for reliability analysis.
C-19
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LOUISIANA DEPARTMENT OF CONSERVATION (NEW ORLEANS FILE)
1. Data Bank Name; State of Louisiana
Department of Conservation
Division of Minerals
New Orleans District Office File
2. Data Bank Location; 307 Louisiana State Office Building
Civic Center
New Orleans, Louisiana 70112
3. Data Bank Structure; The earliest data is in narrative form. Later data
is on an earlier {pre-October 28, 1970) form, and current data is on a
standard but limited form.
4. Scope; Data related to oil spills and slicks of known and unknown origin
were collected here starting in late 1969. Later, a very simplified form
evolved and all reports received in the New Orleans District office were
transcribed onto this form for transmittal to headquarters in Baton Rouge,
Louisiana. Ultimately, the reporting format was made uniform and a
specific requirement to report any spill was made, by directive.
Since the language in the directive relates strongly to spills or slicks on
water, and since there is an abundance of maritime activity in the area
of the offshore and inland bay oilfields in this district, a large number of
these reports identified slicks of unknown origin in the area and heading
their way. These data have been deleted, although it was counted for
information. There are 390 such "John Doe" reports.
5. Reporting Requirements; See Item 7.
6. Purpose; The Department requires information concerning corrective
action follow-up.
This Department has long had the authority to take (summary) action _
against producers who were dumping saltwater into the streams and onto
the land, but until recently (about 1969) had left oil pollution up to the
Louisiana Stream Control Commission. They have now become active
also in oil spills.
7. Items Contained in Data Bank;
a. Field location
b. Company
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c. Date and time
d. Amount of oil lost
e. Cause of incident
f. Corrective action taken
g. Size of sighted oil spill - length and width
h. Direction of movement
i. Weather conditions
j. By whom reported.
8. Time Span Covered by jitudy Data; Late 1969 through November 1971.
9. Volume of Data; There were 690 pieces of data in the file, all relating
to oil or oil products. Of this total, approximately 300 are relevant to
to this study. The remainder are related to maritime traffic (ships, boats,
barges, docks, etc.), fuel spills, bilge pumping, product spillage, etc.
Many were "John Doe" reports - that is, unknown source, unknown
quantity, etc. A total of 707 reports (combined with the Baton Rouge
File) were used in this study.
10. Limitations and General Comments on Data Bank; Data forms are
extremely simple and lacking in the specific detail.
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LOUISIANA DEPARTMENT OF CONSERVATION (BATON ROUGE FILE)
1. Data Bank Name; State of Louisiana
Department of Conservation
Division of Minerals
Headquarters Office File, Baton Rouge
2. Data Bank Location; Oil and Gas Division Building
P. O. Box 44275 Capitol Station
Baton Rouge, Louisiana 70804
3. Data Bank Structure; Data are presented on limited and simple standard
forms. Data not computerized.
4. Scope; Data received and filed daily. All "John Doe" reports, as well
as all reports of less than three barrels (as reported), are discarded.
File is kept by operator names and all data over 1 year is deleted from
the file. Form is that prescribed in a letter directive of October 28, 1970.
5. Reporting Requirements; See Item 7 of Louisiana Conservation Commission
New Orleans File for data elements to be reported.
6. Purpose; Refer to Item 6, New Orleans File.
7. Items Contained in Data Bank; Refer to Item 7, New Orleans File.
8. Time Span Covered by Study Data; One year previous to October 15, 1971.
9. Volume of Data; There were 1105 spill reports in the file, with approxi-
mately 100 not relevant to this study. See New Orleans File.
10. Limitations and General Comments on Data Bank; Generally the same re-
marks as apply to the New Orleans data. Note the different time frame and
different amount of the spill between those records here and those of the
New Orleans bank. There is no doubt that some overlap. The New Orleans
file is the most nearly complete for that district both over a longer time
and covering some smaller spills.
C-22
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MISSISSIPPI OIL AND GAS BOARD
1. Data Bank Name; State of Mississippi
Oil and Gas Board File
2. Data Bank Location; Mississippi Oil and Gas Board
State Office Buildings
P. O. Box 1332
Jackson, Mississippi 39205
3. Data Bank Structure; Reports by letter are required, but not in any specified
format.
4. Scope: Letter reports from operators cover details on all fires which destroy oil
or gas, details of any breaks or leaks in pipelines or tank overruns, and steps taken
to correct situation. Amounts of oil spill are to be reported if loss exceeds 100
barrels. The letter file is the central data bank for the State of Mississippi.
State Oil and Gas Board Order 245-56 provides rules for prevention of pollution
of fresh waters and contamination of soils; However, no reporting is required
in the enforcement procedures.
5. Reporting Requirements; Rule 17 of the Statewide Rules and Regulations sets
forth the requirement for letter reporting immediately to the Board of fires,
leaks, and blowouts.
6. Purpose; To gather information on petroleum production losses to protect public
and private interests against waste in production and use of oil and gas.
7. Items Contained in Data Bank; General description of damage and the location,
given by section, township, range, and property.
8. Time Span Covered by Study Data; December 1959 through November 1971.
9. Volume of Data; 202 spill events, all of which are crude oil (except for four con-
densate) spills. All were used in this study.
10. Limitations and General Comments on Data Bank; Data lacks the technical detail
necessary for reliability analysis.
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NEW MEXICO OIL CONSERVATION COMMISSION
1. Data Bank Name: State of New Mexico
Oil Conservation Commission Rule 116 File
2. Data Bank Locations; The state is divided into four districts and each district
maintains its own data bank.
3. Data Bank Structure; There are no forms required. Spills are reported by letter
to the district office.
4. Scope: Not defined.
5. Reporting jtequirements; New Mexico Oil Conservation Commission Rule No. 116
requires that all oil spills of 100 barrels or more be immediately reported in writing
to the district office. New Mexico requires oil spill reports for purposes of
inventory production, transfer, and storage of petroleum within the district.
6-7. Purpose and Items Contained in Bank; The requirements are that the amount of
the spill, location, cause, and clean up, if any, be reported. Sometimes the
repair action taken is also reported. New Mexico requires oil producers to
report all movements of oil from one lease to another. These reports are filed
with the spill data reports, making a large volume of data pertaining to oil transfer
and/or spillage.
8. Time Span Covered; January 1968 through August 1971. Districts keep data only
5 years.
9. Volume of Data; 58 relevant reports. All were used in this study.
10. Limitations and General Comments; The reports are more for control of production
and oil transfer than for pollution; therefore, they lack the technical detail
necessary for reliability analysis.
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OKLAHOMA CORPORATION COMMISSION
1. Data Bank Name; State of Oklahoma
Corporation Commission
Oil and Gas Conservation Division File
Form 1036-Complaint (Informal)
2. Data Bank Location; Oklahoma Corporation Commission
Oil & Gas Conservation Division
380 Jim Thorpe Building
Oklahoma City, Oklahoma
Only the district offices maintain permanent files of their Form 1036-Complaint.
3. Data Bank Structure; Data are submitted on Form 1036-Complaint, which is a
universal form used by the field inspectors to report all types of field violations
of the Rules and Regulations.
4. Scope; Form 1036-Complaint is designed for reporting all infractions of the Rules
and Regulations and not specifically for oil spills. Data depositories are main-
tained in each of the four districts.
5. Reporting Requirements: All reports of any commission rule violations are
investigated and filed on Form 1036. Pollution or damage to any surface or
underground fresh water is such a violation.
6. Purpose; To comply with the Rules and Regulations of the Oil & Gas Conservation
Division.
7. Items Contained in Data Bank; Numerous identification items such as identity of
violator, description of conditions, corrective action necessary, and time to
correct.
8. Time Span Covered by Study Data; November 1967 through November 1971. The
file contains very few reports in 1967, 1968 and 1969.
9. Volume of Data; A total of 399 spill events were relevant and used in this study.
10. Limitations and Genera^Comments on Data Bank; Data lacks technical detail
necessary to reliability analysis.
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TEXAS RAILROAD COMMISSION
1. Data Bank Name; Texas Railroad Commission
Oil and Gas Division File
?,. Data Bank Location; Texas Railroad Commission
Oil and Gas Division
Corner 10th and Colorado Streets
Drawer EE
Austin, Texas 78711
3. Djtta Bank Structure; Data have been presented on standard forms since about
June 1970. Prior to that, they were in narrative form by letter, or on some in-
dividual company forms. They are not computerized. The reports from each of
the 12 districts are separated into oil pipeline and producing operations spills.
4. Scope: The data is meant to include all reports of spills of crude oil, gas well
liquids, or associated products lost in a quantity of more than five barrels.
5. Reporting Requirements; Form H-8, Crude Oil Loss Report is filed with the
Railroad Commission District Office by operating company causing spill.
6. Purpose; The R.R. C. is required by law to: (a) prevent waste, and (b) prorate
production, and (c) protect correlative rights. Form H-8 was designed for this
purpose - to follow up and enforce rules against waste (spillage is one form) and
to keep inventory of all oil produced so that proration is practiced and enforced.
The use of this form as a tool to help stop pollution is a "newly acquired" useful
function, and not necessarily intended at the outset.
7. Items Contained^ inJPata Bank; Usually, only general information is given; details
important to reliability study are rare.
8. Time Span Covered by Study Data: Approximately January 1, 1970 through
November 1971. Headquarters file is regularly purged of data more than 2 years'
old.
9. Volume of Data: 5170 spill events. 5094 records were used in this study.
10. Limits and General Comments on Data Bank; Hard, specific facts are few, and the
main value of this, the largest collection of raw data found, is statistical use -
indicating general and specific areas of problems only, and suggesting some general
remedies. There are probably almost as many designs, or configuration of
"systems, " and "subsystems" as pieces of data.
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CALIFORNIA WESTERN OIL AND GAS ASSOCIATION
This source was contacted, but they indicated that no records were available that
would be pertinent to this study.
C-27
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ALBERTA OIL AND GAS CONSERVATION BOARD
1. Data Bank Name: Alberta Oil and Gas Conservation Board
Drilling and Production Monthly Pollution Summaries.
2. Data Bank Location; Oil and Gas Conservation Board
603 Sixth Avenue, S. W.
Calgary, Alberta, Canada
3. Data Bank Structure; No standardized format is used among the field offices or
by the same field offices from month to month.
4. Scope; Pollution summaries are submitted monthly from each of five field offices.
Pipeline spills do not fall under the jurisdication of this office; they are handled
by the Alberta Department of Mines and Minerals. The summaries appear to be
based on the results of investigations instigated by complaint rather than formally
required submissions by the cognizant oil company. The field offices which provide
the summaries to this central bank may possibly have more detailed information,
although this is currently unknown. The related field offices are:
Medicine Hat
Red Deer
9 Black Diamond
Edmonton
Drayton Valley
5. Reporting Requirements; Any operator of a well or an oil sands scheme is required
to immediately report (a) any fire at a battery, well, storage tank, or pit where
the loss exceeds 100 barrels of oil; (b) any break or leak at an installation used in
the operation of an oil sands scheme from which the loss exceeds 100 barrels of
oil. In a report of such accidents, the location of the well, tank, pit, or line
break is required to be given. The report is sent to the Oil and Gas Conservation
Board at the address in Item 2. This requirement is included in a paragraph of
the Oil and Gas Conservation Regulations.
6. Purpose; To effect conservation of petroleum products, prevent waste, control
pollution, and secure the observance of safe and efficient field practices. Data
are collected, summarized, evaluated, and published in support of these goals.
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7. Items Contained in Data Bank; The data bank includes odor complaints, oil and
salt water spills, and black smoke contraventions.
8. Time Span Covered by Study Data: The data cover the period from January 1970
through July 1971.
9. Volume of Data; The bank includes 419 reports of crude oil spillage. It does not
include spills of other products. 235 reports were used in this study.
10. limitations and General Comments on Data Bank; The data bank appears to be in
a state of flux as far as presentation format is concerned. The data are not
conducive to problem analysis below subsystem level or cause.
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ALBERTA DEPARTMENT OF MINES AND MINERALS
1. Data Bank Name: Province of Alberta
Department of Mines and Minerals
Pipeline Spill File
2. Data Bank Location: Department of Mines and Minerals
Edmonton, Alberta
Canada
3. Data Bank Structure; The data bank consists of telephone messages and letter
reports. Access to the records without a court order was not permitted; therefore,
the above description is all that could be ascertained from conversation.
4-5. Scope and Reporting Requirements: The permittee or licensee is required to
inform the Superintendent of Pipelines or an inspector as soon as possible when
a break in a pipeline occurs. If the break is on Crown land or in a forested area,
the operator is required to notify the Department of Lands and Forests of the
location and the quantity of oil spilled. After the break is repaired, the permittee
or licensee is required to submit a written report to the Superintendent of Pipelines
showing:
a. The time the break occurred
b. Quantity of substance lost
c. The conditions that caused or contributed to the break.
6. Purpose; Not defined.
7. Items Contained in the Data Bank; The data bank includes gas and other petroleum
product losses as well as crude oil. It is not known if other data are included.
8. Time Span Covered by Study Data: Not specified.
9. Volume of Data; Not specified. None were used in this study.
10. Limitations and General Comments on Data Bank; Insufficient knowledge of the
data bank precludes discussion.
C-30
-------
APPENDIX D
TABULATION OF OIL SPILL RECORD DATA
-------
TABLE OF CONTENTS
Appendix D - Tabulation of Oil Spill Record Data D-l
D. I Introductory Summary D-l
D.2 Tabulations of Oil Snill Record Data D-2
D-ii
-------
LIST OF ILLUSTRATIONS
Figure
D-l Source Data Summary D-3
LIST OF TABLES
Table
D-l EPA Headquarters - OHM File D-5
D-2 EPA Anchorage, Alaska D-6
D-3 DOT/FRRC - Pipeline Carrier Accident Reports D-7
D-4 California Department of Fish and Game Commission D-8
D-5 Geological Survey, Conservation Division, Washington, D.C.
Office D-9/D-10
D-6 California Water Quality Control Board D-ll
D-7 California Division of Oil and Gas D-12
D-8 California - City of Long Beach, Department of Oil Properties D-13/D-14
D-9 Colorado Department of Health, Water Pollution Control
Division D-15/D-16
D-10 Louisiana Department of Conservation, Division of Minerals. . D-17/D-18
D-10A Louisiana Department of Conservation, Division of Minerals -
Onshore Spills D-19/D-20
D-10B Louisiana Department of Conservation, Division of Minerals -
Offshore Spills D-21
D-ll Mississippi Oil and Gas Board D-22
D-12 New Mexico Oil Conservation Commission D-23/D-24
D-13 Oklahoma Commission, Oil and Gas Conservation Division . . . D-25/D-26
D-14 Texas Railroad Commission Oil and Gas Division D-27/D-28
D-15 Alberta, Canada - Alberta Oil and Gas Conservation Board. . . D-29/D-30
D-16 Component Versus System Element for Moderate Spills
Offshore D-31/D-32
D-17 Component Versus System Elements, Major Spills Onshore. . . D-33/D-34
D-18 Component Versus Cause, Gathering/Distribution Systems, All
Spills D-35
D-19 Component Versus Cause, Drilling Systems, All Spills D-36
D-20 Component Versus Cause of Spill for the Production System . . D-37/D-38
D-21 Component Versus Cause, G/D Onshore, Major Spills D-39/D-40
D-22 Component Versus Cause, Production Onshore, Major Spills. . D-41/D-42
D-iii
-------
LIST OF TABLES (Cont'd)
Table
D-23 Component Versus Cause, G/D Offshore, Moderate Spills. . . . D-43/D-44
D-24 Component Versus Cause for Offshore Production System
Moderate Spills D-45/D-46
D-25 Cause Versus System Element for Major Spills D-47/D-48
D-26 Cause Versus System Elements, Offshore Moderate Spills . . . D-49/D-50
D-27 Component Versus Quantity Spilled Category by System D-51/D-52
D-28 Component Versus Quantity Spilled Category G/D By Shore
Code D-53/D-54
D-29 Component Versus Quantity Spilled Category Production by
Shore Code D-55/D-56
D-iv
-------
APPENDIX D
TABULATION OF OIL SPILL RECORD DATA
D. 1 INTRODUCTORY SUMMARY
The spill prevention program described in this report relies strongly on the spill data
presented in this appendix. The spill data are essential to the analysis of Appendix E,
and identify the types and frequencies of failures of equipments, personnel, and pro-
cedures resulting in oil spills. Additional data for Gulf OCS safety shutdown devices
are given in Appendix J. This appendix provides a basis to evaluate the spill preven-
tion program in terms of the spill data used.
A spillage or noncontainment of crude oil or condensate was the criterion used to define
a petroleum system failure to determine the types of data required for the study.
Spills related to marine transportation were excluded in accordance with program
guidelines. It was found that primary sources of oil spill reports were data banks
maintained by various State and Federal agencies, which contained spill reports sub-
mitted in response to individual agency requirements. Most of the requirements relate
to regulating traffic in the petroleum products and to protecting the public interest.
Generally, a minimum of technical detail is required.
A review of potential spill data sources was made and contacts at some of these organi-
zations revealed other possible sources. The initial visits to collect spill records
were made in the Washington, D.C. area at the Environmental Protection Agency,
Department of Transportation, U.S. Coast Guard, and U.S. Geological Survey.
Since spills from marine transportation sources were not sought, the extensive USCG
data bank contained only a few events pertinent to this study. These were evaluated
but not entered into the study's computer file.
Over 15,000 oil spill events were reviewed during this study. The majority of the
records had been generated in the 1970-1971 period as a result of increased public and
political interest in environment preservation. Of these, 8473 were found to apply to
D-l
-------
the study objectives and were extracted from the data banks. Of the 20 data sources
examined, seven used prepared forms required to be submitted to an agency office
when a spill occurred. Only narrative reports or summary records were kept in the
remainder of the sources. Summary descriptions of each source data bank are con-
tained in Appendix C. The volume of data collected from the individual sources varied
widely, as did the relative sizes of the data banks.
As information was gathered it became evident that the oil spill data, while containing
useful information, were submitted in response to requirements not necessarily aimed
at deriving specific reliability parameters of petroleum systems.
Some of the deficiencies of the data included:
1. Equipment failure data not resulting in spills were totally lacking;
all the information collected and analyzed consisted of spill event data.
2. Equipment population could not be identified.
3. Equipment identification codes or nomenclature were not standardized.
4. Equipment configurations could not be determined.
5. Maintenance actions and repair time information were not available.
6. There were many instances of inconsistent equipment and event nomenclature.
7. Often the effect of an oil spill was identified but not the cause.
8. Cost of repair parts or cleanup operations was not available.
In spite of these deficiencies, the data did support analysis leading to an identification
of the most common failure points leading to oil spillage. This analysis is documented
in Appendix E.
D.2 TABULATIONS OF OIL SPILL RECORD DATA
Tables D-l through D-15 contain data taken from each data source used in this study.
The data are arranged such that the subsystem elements of the Gathering/Distribution
Drilling, and Production Systems are shown across the top and the components are
D-2
-------
listed down the page. The elements and components were derived from the systems
description in Appendix B, as documented in Appendix K. The number of spills is
indicated in the appropriate column under the equipment involved and in the row of
the responsible component. Columns of totals are shown with the heavier-lined
borders. Figure D-l summarizes the source data given in Tables D-l through D-15.
Federal
EPA Headquarters - OHM File
EPA Anchorage, Alaska
DOT/FRRC - Pipeline Carrier Accident Reports
U.S. Geological Survey, Conservation Division,
Washington, D, C. Office
States
California - Department of Fish and Game Commission
California - Water Quality Control Board
California - Division of Oil and Gas
California - City of Long Beach,
Department of Oil Properties
Colorado - Department of Health,
Water Pollution Control Division
Louisiana - Department of Conservation,
Division of Minerals
Mississippi - Oil and Gas Board
New Mexico - Oil Conservation Commission
Oklahoma - Corporation Commission
Oil and Gas Conservation Division
Texas - Railroad Commission
Oil and Gas Division
Other
Alberta, Canada - Alberta Oil and Gas Conservation
Board
Number of
Records Used
108
68
802
633
63
19
40
30
10
707
202
58
399
5094
235
Type of Report
Form Narrative
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Table
Number
D-l
D-2
D-3
D-4
D-5
D-6
D-7
D-8
D-9
D-10
D-ll
D-12
D-13
D-14
D-15
Systems
Reported*
G/D, D, P
D, P
G/D
G/D, D, P
G/D, P
G/D, D, P
G/D, D, P
G/D, D, P
G/D, P
G/D, P
G/D, P
G/D, P
G/D, D, P
G/D, D, P
G/D, D, P
*G/D = Gathering/Distribution Systems
D = Drilling Systems
P = Production Systems
Figure D-l. Source Data Summary
D-3
-------
The remaining tables (D-16 through D-29) present various compilations of the source
data, as indicated below:
Tables D-16 and D-17 present components versus system elements for
offshore moderate spills and onshore major spills, respectively.
Tables D-18 through D-20 present the spill data tabulated for the
Gathering/Distribution, Drilling, and Production Systems, respectively,
to show the causes versus components involved for all spills.
Tables D-21 through D-24 present data for causes versus components
involved for onshore major spills and offshore moderate spills for the
Gathering/Distribution and Production Systems.
Tables D-25 and D-26 present the system elements versus causes for
all major spills and offshore moderate spills, respectively.
Table D-27 persents component versus spill quantity for all spills
grouped by system into minor, moderate, and major spill categories.
Tables D-28 and D-29 present data similar to that in Table D-27, but
specifically for the Gathering/Distribution and Production Systems,
respectively, and further grouped by onshore and offshore systems.
The numbers in the column headers and the CODE column are described in Appendix K
and relate to the corresponding items in the computerized data bank established for
correlating and analyzing the collected data for presentation in this report.
D-4
-------
Table D-l. EPA Headquarters - OHM File
-GATHERING/DISTRIBUTION SYSTEM
DRILLING SYSTEM
\. Element
Component ^\
Not Identified
Disc, Rupture
Pipe
Riser
Tank Shell
Valve
Valve, Ball
Valve , Dump
TOTALS
0
s
tj
00
16
46
55
67
74
78
82
10000 Gathering/
Distribution
System
4
4
11000
Pipeline
Subsystem
0
o a
H O,
" 0,
2
55
57
11200
Scraper Trap
Equipment
11400
Submerged Water
Crossing
1
1
12000
Storage
Subsystem
o ^
s|
2n
4
1
5
12300
Tank Associated
Equipment
1
1
13000
Pump Station
Subsystem
§1
B£
13BOO
Pressure
Controllers
« 3
*H >
13EOO
Valve Operating
Equipment/
Controls
Gathering/
Distribution
System Totals
10
57
I
68
20000
Drilling System
21000
Well
Subsystem
g3s
3 SS
CM O M
1
1
23100
Derrick
Platform
1
1
25000
Drill String
Subsystem
1
1
Drilling System
Totals
3
3
N. Element
Component x.
}ot Identified
Disc, Rupture
Pipe
^iser
rank_Shell _._
Valve
Valve ,Ball
Valve. Dump
TOTALS
8
u
nn
IR
4fi
55
R7
74
| 7S
HV
30000
Production
System
25
1
26
31000
Well
Subsystem
1
1
2 a
S s
re «
§* >>
^J CO
O aj ^
N S 3
n S tS
32100
Casing Head
Equipment
1
1
33100
Flow Line
Equipment
1
1
2
CQ
o a
o c
to a
en 3
n PH
1
1
34000
Separation
Subsystem
1
1
PRODUCTION SYSTER
34500
Scrubber
Equipment
35000
Treater
Subsystem
1
1
351000
Heater
Treater
1
1
35600 ,-
Skimmer
i
36000
1-ocal
Storage
Subsystem
o w
«> S
n H
36200
Tank Associated
Equipment
1
f"
2
36300 Sump System
38000
Safety Shutdown
& Alarm Subsystem
39000
Water Disposal
Subsystem
Production
System
Totals
31
1
1
1
1
37
Bank Totals
44
J.
58
1
1
108
-------
Table D-2. EPA Anchorage, Alaska
Not Identified
Coupling
Fasteners
Flange
Pig
'jiipe
Pump
Sensor, Hi-Level
Valve
Valve, Ball
Valve, Check
Valve, Dump
TOTALS
I
00
12
IS
2
4S>
«1
74
76
80
82
DRILLING
SYSTEM
bo
° C ra '
3
a
Drilling
System
Totals
3
3
30000
Production
System
T
7
31000
Well
Subsystem
32000
Well Head
Subsystem
2
2
33100
Flowline
Equipment
7
, _,
i
4" '"
1 "
1
4 " '
"it
II
i
i ' "
i
3
6
n & H
.. t .
1
ODUCTION SYi
35000
Treater
Subsystem
e
i
7 '
35100
Heater
Treater
3
3
A
35600
Skimmer
4
4 1
36000
Local Storage
Subsystem
g|
SH
2
1
3
36200
Tank Associated
Equipment
2
2
1
S
36300 Sump System
1
1
38000
Safety Shutdown
ti Alarm Subsystem
I
1
39000
Water Disposal
Subsystem
3
1
1
5
[Production
System Totals
39
1
1
4
1
1
1
6
4
2
1
4
65
en
H
42
1
1
4
1
1
1
6
4
2
1
4
68
o
O5
-------
Table D-3. DOT/FRRC - Pipeline Carrier Accident Reports
O
I
^v Element
Component N.
Not Identified
Coupling
Fasteners
Fittings
Flange
Foundation
Gasket
Gasket, Ring
Gland, Packing
Meters
Nipple
Pig
Pipe
Plug ,Bull
Pump
Seals
Seam
Sensor, Hi -Level
Switches
Tees
Threads
Valve
Valve , Ball
Valve Check
Valve , Dump
Valve , Gate
Valve, Pressure Relief
Welds
Strainer
TOTALS Total
w
§
00
12
18
19
20
24
25
?,fi
28
40
41
45
46
4ft
49
59
60
61
66
6fi
69
74
76
80
R9
83
86
89
99
10000 Gathering/
Distribution Systen
0
11000 Pipeline
Subsystem
1
2
3
0
o o
rH Qri
2
11
2
1
1
2
687
3
2
1
1
2
10
3
13
741
GA
11200
Scraper Trap
Equipment
1
1
THERING/I
12000
Storage
Subsystem
0
3ISTRIB
(N *
H H
9
1
2
1
13
UT1ON SY
12300
Tank Associated
Equipment
1
1
1
1
1
5
10
STEM
13000
Pump Station
Subsystem
1
1
1
1
2
2
1
9
l|
5
1
1
1
3
1
1
2
1
16
13BOO
Pressure
Controllers
1
1
II
CO ,*
5
1
6
_
siojiuoo
/^uauidmba
SUT^BjadQ SApSA
0038T
1
1
2
si
a o
ffl H
24
4
1
13
3
1
5
1
1
2
2
688
3
1
3
2
1
1
4
21
4
1
15
1
802
-------
Table D-4. California Department of Fish and Game Commission
GATHERING/DISTRIBUTION
SYSTEM
PRODUCTION SYSTEM
\y Element
Component N.
Not Identified
Coupling
Pipe
Rods
Tank Shell
Valve
Totals
1
u
00
12
46
56
67
V4
10000 Gathering/
Distribution System
3
1
4
11000 Pipeline Sub-
system
g.
S
o
o
1-H
i-l
i-«
32
32
12000 Storage Sub-
system
I
§
iH
N
rH
1
1
Gathering/Distri-
bution System
Totals
3
32
1
1
37
30000 Production
System
4
7
11
32000 Well Head
Subsystem
1
&
o
s
8
2
2
33000 Gathering
Subsystem
33100 Flow Line j
Equipment j
2
2
34000 Separation
Subsystem
1
Ll
35000 Treater
Subsystem
tn
O
§
9
7
7
36000 Local Storage
Subsystem
36200 Tank Associ-
ated Equipment
, 1
1
8
01
I
&
Q.
O
o
'5.
«
1
1
39000 Water Disposal
Subsystem I
39200 Precipitator
1
1
Production Systenx
Totals
14
2
1
2
7
26
to
1
H
17
2
33
2
1
8
63
I
00
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
Table D-6. California Water Quality Control Board
GATHER
HDISTRIBU
SYSTE
Not Identified
Hose
Pipe
Plue.Bull
Valve
TOTALS
1
u
on
»4
45
4R
74
11100 Pipeline
Subsystem
11100 Pipe
1
10
11
ING/
TION
M
Gatherlng/Dlstrlbu
tion System Totals
1
10
11
DRILLING
SYSTEM
21000 Well
Subsystem
«
I
o
o
C4
1
1
Drilling System
Totals
1
1
32000 Well Head
Subsystem
32100 Casing Head
Equipment
1
1
32200 Tubing Head
Equipment
1
1
2
33000 Gathering
Subsystem
UCTION SYSTI
3
j
1
E
8
«
e*a
i
i
36000 Local Storage
Subsystem
36200 Tank Associ-
ated Equipment
2
2
37000 Custody
Transfer Sub-
system
00
a
E
£
o
o
t-
w
~T
~1
Production System
Totals
"I
1
7
n
g "3
I -s
n H
2
10
'
-------
Table D-7. California Division of Oil and Gas
GATHERING/
i DISTRIBUTION
I SYSTEM
^ DRILLING .
SYSTEM *" 1
PRODUCTION SYSTEM
>^ Element
Component >v
Not Identified
Box , Stuffing
Pipe
Pump
Rods
Rnri.Pnlishori
Tank Shell
Valve
Valve .Check
Valve Pressure Relief
Oil/Leg
TOTALS
i
o
00
05
46
49
M
>'l
67
74
SO
S6
96
11000 Pipeline
Subsystem
1 s.
ss
8
1
9
14000 Safety
Subsystem
1
1
Gathering/
Distribution
System Totals
1
8
1
10
24000 Mud
Subsystem
1
|
is
i
i
Drilling System
Totals
1
1
30000 Production
System
3
3
32000 Well Head
Subsystem
32500 Rod 1
Pump
1
1
2
32700 Gas
Lift
1
1
33000 Gathering
Subsystem
i s
S3
5
2
7
i|
8*
i
i
35000 Treater
Subsystem
35600
Skimmer
1
1
3600 Local
Storage Sub-
system
O «g
HI
i
2
3
36200 Tank
Associated
Equipment
1
1
1
1
4
° &
n 6
to 3
« DO
2
5
7
Production
System Totals
7
1
5
1
1
1
5
3
3
i
i
29
,2
|l
«fH
8
1
14
1
1
1
5
3
3
2
1
40
O
I*
to
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
Table D-9 . Colorado Department of Health, Water Pollution Control Division
GATHERING/DISTRIBUTION
SYSTEM
-PRODUCTION SYSTEM
Element
Component
fe 0
rd O
a
2 ^ «
O 4J +1
o oo to
w
O (U
o a
0
1
,3
JjJ 53 to
^3 * "*
O S H
I
s
I
lal
a a to
!«1
fi^g
5
£
Not Identified
00
Pipe
TOTALS
D-15
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
Table D-10B. Louisiana Department of Conservation, Division of Minerals -
Off-Shore Spills
GATHERING/
DISTRIBUTION
.SYSTEM
PRODUCTION SYSTEM
\ CLEMENT
COMPONENT \
Mot tafflriwd
Ml - Alarm
Bo«~Stullmg
ChottBody
Coupling
Detector- H«it
Duphitfm
DrtC- Rupturl
Fcitvnwt
Fitting,
fujf*.
Gnktt
G.U*.
Hwdti
Hwtx
HOM
Mmtt
O-Ring
PM*«t
N
P«(M
Plug- tull
Pump
Kiw
SHU
S.OM.ML
Swiwt I. P
Swlchn
UnUXI
V«lv«
V.ly. - * Pint
Vtln- Chw*
V«l.t- Conttol
Vim- Dump
Vllvt-NMtflt
V.l.« Pirn IM
Fin- Tub.
Conuolt
TtnTink
W«« lin«/l«J
Strunw
TOTALS
8
DO
1
06
OB
2
4
S
t
a
*
10
76
77
X
31
34
40
43
44
44
44
48
4»
K
»9
fll
M
M
11
>4
JS
K
at
62
8<
16
W
m
17
w
z
1
'
i
i
i
X
i!
iz
ll
1
\
2
M
I
z
1
2
1
\
4
30OOO PRODUCTION
IVtTEU |
20
\
\
1
1
1
2
2
1
33
1
1
1
X
IS
i!
2
1
2
1
1
1
9
!
)
[|_
ti
52
i
i
i
ii
2
1
1
4
17700
-------
Table D-ll. Mississippi Oil and Gas Board
GATHERING/DISTRIBUTION SYSTEM-
PRODUCTION SYSTEM
to
to
>v Element
Component >^
Not Identified
Box, Stuffing
Coupling
Gasket
Hose
Meters
Pipe
Reeu later. Pressure
Valve
ValvejGate
Welds
Vent
Totals
i
00
65
12
25
34
40
46
52
74
83
89
94
HOOO Pipeline
Subsystem
£
5
o
o
I-l
1
5
1
56
1
2
2
168
If
0 >>
l«
H ts
0 >>
U5 3
U
V
1
* s
o -^
3 o
U5 *J
2
2
16000 Local
Storage Subsystem
1
1
(0
U
g
f-l
0
o
r-4
to
m
1
1
2
6200 Tank
Usociated
Equipment
1
2
1
4
1
^
|
1 m
|-a
&H
4
1
3
2
1
11
CD
13
Si2
9
1
1
6
1
1
170
1
7
2
2
1
202
-------
Table D-12. New Mexico Oil Conservation Commission
-GATHERING/DISTRIBUTION SYSTEM
PRODUCTION SYSTEM
\y Element-
Component N^
Not Identified
Coupling
Disc , Rupture
Gasket
Nipple
Pipe
Pump
Tank Shell
Valve
Valve, Check
Valve, Dump
TOTALS
tt
O
00
12
16
25
41
46
49
67
74
80
82
11000 Pipeline
Subsystem
11100 Pipe
2
1
13
16
11500 Submerged
Crossing Land
3
3
12000 Storage
Subsystem
12100 Tank
1
1
12300 Tank Associ-
ated Equipment
1
1
2
13000 Pump Station
Subsystem
«
^
73
>
o
o
3
r*
1
1
2
13100 Pump
1
1
Gathering/Distribu-
tion System Totals
2
2
16
1
3
1
25
33000 Gathering
Subsystem
33100 Flow Line
Equipment
1
1
1
3
6
34000 Separation
Subsystem
34200 Separators
High Controls
1
1
35000 Treater
Subsystem
1
1
35100 Heater
Treater
4
1
5
36000 Local
Storage Subsystem
OB
J£
H§
§
to
w
11
i
4
16
36200 Tank Associ
ated Equipment
1
1
1
3
37000 Custody
Transfer Sub-
system
!
&
o
o
^-
rt
1
1
Production
System Totals
16
1
1
1 H
1
2
1
4
4
2
33
GO
11
«H
16
3
1
3
1
18
1
5
7
1
2
58
O
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
Table D-18. Component Versus Cause, Gathering/Distribution Systems, All Spills
NV CAUSE
COMPONENT \
Not Identified
Coupling
Disc, Rupture
Fasteners
Finings
Flanae
Float
Foundation
Gasket
Gasket Ring
Gauge
Gland. Packing
Header
Hose
Joint, Blast
Meters
Nipple
O-fiing
Packers
Pi9
Pipe
Plug, Bull
Pump
Recorders
Riser
Rods
Seals
Seam
Swage
Switches
Tank Shell
Tees
Threads
Tubing, Instrument
Union
Union, Flange
Valve
Valve, Bypass
Valve, Check, Reverse
Flow
Valve, Control
Valve, Gate
Valve, Relief, pressure
Vessel, Pressure
Welds
Motor
Control
Strainer
TOTALS
Ul
§
o
00
12
16
18
19
20
21
24
25
26
27
28
30
34
36
40
41
43
44
4E
46
48
49
52
55
56
59
60
6E
66
67
68
69
71
72
73
74
79
80
81
83
86
Bf.
89
91
93
99
UNKNOWN
1
14
7
1
t
23
NO MALFUNCTION
2
20
3
2
25
NOT REPORTED
3
14
1
1
1
127
1
1
|
147
EQUIPMENT
FAILURE
10
9
2
1
1
1
2
1
11
3
1
2
1
2
1
39
BROKEN
12
15
1
1
3
3
4
1
3
1
14
19
1
2
1
2
4
1
1
1
3
1
2
4
88
BURST/RUPTURED
14
13
1
2
25
1
2
1
1
141
1
1
1
4
2
1
1
1
1
6
1
4
1
6
1
219
CORRODED
15
27
1
1
2
1
1
639
1
1
674
CORRODED
EXTERNALLY
16
82
1
1383
1
1
3
1471
CORRODED
INTERNALLY |
T7
23
1
1
1
336
1
1
1
1
366
DEFECT,
MATERIAL
20
1
3
2
1
1
1
2
3
14
FAILURE.
OPENED |
22
5
1
31
2
39
FROZE & BURST
24
36
1
37
LU
_1
O
T
25
7
46
1
1
55
LEAKING
26
19
12
9
6
8
6
1
1
240
2
4
1
2
1
1
1
10
8
1
6
2
441
NON-FUNCTION-
ING
30
7
1
1
1
7
1
a
13
1
2
42
OVERFLOWED
31
9
1
1
1
2
14
OVER-PRESSURE
32
8
11
1
1
21
PARTED, LINE
OR UNION
33
3
11
8
2
3
1
1
32
2
2
2
1
68
a
u
_J
a.
34
1
16
1
1
9
28
WELD DEFECTIVE
39
1
1
40
9
51
DEACTIVATED OR
REMOVED |
44
1
10
1
12
OPERATION
INCORRECT
51
5
1
7
3
2
18
TEMPERATURE
79
2
2
1
13
2
1
21
THIRD PARTY
90
41
41
COLLISION
92
4
8
1
1
1
15
FARM MACHINERY
93
4
1
43
2
1
51
FOREIGN OBJECT
94
1
9
1
1
1
13
I ROAD MACHINERY |
96
19
1
1
1
1
216
4
2
1
3
5
254
VANDALISM
99
5
4
3
12
TOTALS
39t
33
1
3
30
16
1
2
39
1
1
16
4
4
1
3
20
1
1
0
3456
ID
21
1
6
2
7
3
2
1
5
6
8
3
2
1
55
3
65
1
27
4
1
26
0
4
11
4299
CO
01
-------
Table D-19. Component Versus Cause, Drilling Systems, All Spills
u
eo
Cause
Component
o
Unkno
No Malfun
ptu
Burs
14
Failure Closed
23
erflowed
31
Over Pressure
32
3"
33
Plug
34
ed
Seized/Ja
37
Operator/Main-
tenance Error
40
48
Operation
Incorrect
51
er Press
53
Design Error
£
I
S
f «
I
61
72
82
83
TOTALS
Not Identified
00
29
hoke Body
Disc, Rupture
16
Pipe
46
ontrol
93
TOTALS
37
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
Table D-23. Component Versus Cause, G/D Offshore,
Moderate Spills
\ CAUSE
COMPONENTS.
Not Identified
Gasket
Gauges
O- Rings
Pig
Pipe
Pump
Valve
Valve, Check,
Reverse Flow
TOTALS
CODE
00
25
27
43
45
46
49
74
80
EQUIPMENT 1
FAILURE
10
1
1
BROKEN
12
1
1
BURST/
RUPTURED/SPLIT
14
1
1
2
4
o
4
us
o
19
1
1
FAILURE
OPENED
22
1
1
2
LEAKING
26
2
1
1
1
5
NON "1
FUNCTIONING ]
30
4
4
OVERFLOWED
31
1
1
OVERPRESSURE
32
3
3
PARTED LINE 1
OR UNION
33
1
1
SEIZED/ I
JAMMED |
37
2
2
U.UJ
UIIL
-JO
48
1
1
COLLISION
92
1
1
TOTALS
9
1
1
1
2
4
6
1
2
27
D-43
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
Table D-28. Component Versus Quantity Spilled Category G/D By Shore Code
Not Identified
Coupling
Disc, Rupture
Fasteners
Fittings
Flange
Float
Foundation
Gasket
Gasket Ring
Gauges
Gland, Packing
Header
Hose
Joint, Blast
Meters
Nipple
O- Rings
Packers
Pig
Pipe
Plug, Bull
Pump
Regulator, Pressure
Riser
Rods
Seals
Seam
Swage
Switches
Tank Shell
Tees
Threads
Tubing, Instrument
Union
Union, Flange
Valve
Valve, By-Pass
Valve, Check, Reverse Flow
Valve, Control
Valve, Gate
Valve, Relief, Pressure
Vessel, Pressure
Welds
Motor
Controls
Strainer
TOTALS
GATHERING/DISTRIBUTION SYSTEM
ON-SHORE
Ul
8
u
00
12
16
18
19
?0
21
24
25
26
27
28
30
34
3fi
40
41
43
44
45
46
48
49
52
55
56
59
RO
65
66
67
68
69
71
72
73
74
79
8t)
81
83
86
88
89
91
93
99
MINOR
3
1
44
48
MODERATE
293
26
1
3
18
11
1
36
11
4
2
1
19
1
1
2783
6
7
1
4
2
6
1
2
3
4
4
3
2
1
53
4
64
1
28
2
1
8
1
2
6
3427
MAJOR
70
8
14
5
2
".
£
2
5
3
609
5
1
1
2
1
2
1
3
1
20
2
4
?
17
?
3
5
796
UNKNOWN
26
1
69
5
1
1
1
1
96
TOTALS
392
34
1
3
32
16
1
2
39
1
14
4
4
1
5
23
1
1
3496
11
12
1
5
2
7
3
2
1
6
6
8
4
2
1
73
4
66
1
32
4
1
26
3
5
11
4367
OFF-SHORE
MINOR
p
4
2
1
1
3
4
3
21
MODERATE
c
1
1
1
2
4
6
1
1
2
28
MAJOR
1
1
UNKNOWN
4
2
t>
TOTALS
18
4
£
1
1
1
3
10
10
1
4
2
TOTALS
MINOR
8
^
2
1
1
1
47
4
3
MODERATE
302
26
1
3
18
11
1
37
1
11
4
2
1
19
2
1
2
2787
6
13
1
5
2
6
1
2
3
4
4
3
2
1
54
4
66
1
28
2
1
8
1
2
6
3455
MAJOR
70
8
14
5
4
£
1
2
5
3
610
5
1
1
2
1
2
1
3
1
20
2
4
2
17
2
3
b
UNKNOWN
30
'
1
62
5
1
1
1
1
TOTALS
410
36
1
3
32
16
1
2
42
1
1
14
4
4
1
5
24
2
1
3
3506
11
22
1
6
2
7
3
2
1
6
6
8
4
2
1
77
4
68
1
32
4
1
26
3
5
11
D-53
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
APPENDIX E
PRESENTATION OF SPILL DATA
-------
TABLE OF CONTENTS
Appendix E - Presentation of Spill Data E-l
E. 1 Introductory Summary E-l
E. 1.1 Purpose and Scope E-l
E. 1.2 Analytical Approach E-2
E.I.3 Appendix Organization E-4
E.2 Production Systems Spill Data Analysis E-5
E. 2.1 An Overview of Data and Analytical Scope E-5
E.2.2 Well Subsystem Analysis E-5
E. 2. 3 Wellhead Subsystem Analysis E-6
E.2.4 Gathering Subsystem Analysis E-9
E. 2.5 Separation Subsystem Analysis E-ll
E.2.6 Treater Subsystem Analysis E-13
E.2.7 Local Storage Subsystem Analysis E-15
E. 2.8 Custody Transfer Subsystem Analysis E-16
E. 2.9 Safety Subsystem Analysis E-17
E.2.10 Water Disposal Subsystem Analysis E-18
E.2.11 Analysis of Total Equipment Spills for the Production System E-19
E.3 Gathering/Distribution Systems Spill Data Analysis E-27
E.3.1 An Overview of Data and Analytical Scope E-27
E.3.2 Analysis of Pipeline Subsystem E-27
E.3.3 Storage Subsystem Analysis E-35
E.3.4 Pump Station Subsystem Analysis E-36
E.3.5 Gathering Subsystem Analysis E-36
E.3.6 Analysis of Total Equipment Spills for the Gathering/Distribution
System E-38
E. 4 Analysis of Total Component Spills E-45
E.4.1 Pipe E-45
E. 4.2 Valve E-45
E.4.3 Dump E-45
E.4.4 Check Valve E-48
E.4.5 Hi Level Sensor E-48
E.4.6 Stuffing Box E-48
E.4.7 Coupling E-49
E.5 Analysis of Spill Quantity E-51
E. 5.1 Overview of Spill Quantity Data E-51
E.5.2 Drilling System E-51
E. 5.3 Production System E-53
E.5.4 Gathering/Distribution System E-55
E. 5.5 Analysis of Major Spill Events E-57
E.6 Analysis of Reported Spill Causes E-59
E-ii
-------
LIST OF TABLES
Table
E-l Total Spill Events by System and Shore Code E-l
E-2 Analysis Cross-Reference to Data Tabulations of Appendix D. . . . E-3
E-3 Spill Criticality Rating Guide E-4
E-4 Production System Spill Events by Subsystem and Shore Code ... E-5
E-5 Well Subsystem Spill Events by Spill Category and Shore Code ... E-6
E-6 Wellhead Subsystem Spill Events by Spill Category and
Shore Code E-7
E-7 Wellhead Subsystem Moderate Spill Events by Equipment E-8
E-8 Wellhead Subsystem Moderate Spill Events by Component E-9
E-9 Gathering Subsystem Spill Events by Spill Category and
Shore Code E-10
E-10 Gathering Subsystem Moderate Spill Pipe Leaks by Location
and Year E-10
E-ll Separation Subsystem Spill Events by Spill Category and
Shore Code E-12
E-12 Separation Subsystem Moderate Spill Events by Equipment E-12
E-13 Treater Subsystem Spill Events by Spill Category and Shore
Code E-14
E-14 Storage Subsystem Spill Events by Spill Category and Shore
Code E-15
E-15 Custody Transfer Subsystem Spill Events by Spill Category
and Shore Code E-l 7
E-16 Safety Subsystem Spill Events by Spill Category and Shore Code . . E-l8
E-l7 Water Disposal Subsystem Spill Events by Spill Category and
Shore Code E-19
E-19 Ranking of Production System Equipment by Number of
Reported Spill Events E-20
E-20 Flowline Equipment Spill Events by Component and Cause (1220
Events Reported) E-20
E-18 Production System Spill Events by Subsystem and Equipment. . . . E-21/E-22
E-21 Tank Equipment Spill Events by Component and Cause (461
Events Reported) E-23
E-22 Tank Associated Equipment Spill Events by Component and
Cause (335 Events Reported) E-24
E-23 Heater Treater Equipment Spill Events by Component and
Cause (265 Events Reported) E-25
E-24 Separator, Low Pressure Equipment Spill Events by Component
Cause (157 Events Reported) E-25
E-25 Pump Equipment Spill Events by Component and Cause (103
Events Reported) E-26
E-iii
-------
LIST OF TABLES (Cont'd)
Table
E-26 Gathering/Distribution System Spill Events by Subsystem and
Shore Code E-27
E-27 Pipeline Subsystem Spill Events by Spill Category and Shore
Code . E-28
E-28 Pipe Equipment Onshore Major Spill Events by Component E-29
E-29 Pipe Equipment Onshore Major Spill Events by Cause and
Component E-30
E-30 Pipe Component Onshore Major Spill Events Attributed to
External Corrosion (by State) E-31
E-31 Storage Subsystem Onshore Spill Events by Spill Category E-35
E-32 Pump Station Subsystem Onshore Spill Events by Spill Category. . E-36
E-33 Gathering Subsystem Onshore Spill Events by Spill Category .... E-37
E-34 Gathering Subsystem Onshore Major Spill Events by Cause and
Component E-38
E-35 Gathering/Distribution System Spill Events by Subsystem and
Equipment E-39
E-36 Ranking of Gathering/Distribution System Equipment by Number
of Reported Spill Events E-40
E-37 Pipe Equipment Spill Events by Component and Cause (3117
Reported Events) E-41
E-38 Pipe Component (Gravity Gathering) Spill Events by Cause E-43
E-39 Pipe Component (Road Crossing) Spill Events by Cause E-44
E-40 Ranking of Component Spill Events for All Systems by Component. E-46
E-41 Ranking of Pipe Component Spill Events for All Systems by
Cause E-46
E^t2 Ranking of Valve Component Spill Events for All Systems by
Cause E-47
E-43 Ranking of Dump Component Spill Valve Events for All Systems
by Cause E-47
E-44 Ranking of Check Valve Component Spill Events for All Systems
by Cause E-48
E-45 Ranking of Stuffing Box Component Spill Events for All Systems
by Cause E-49
E-46 Ranking of Coupling Component Spill Events for All Systems by
Cause E-50
E-47 Summary of Reported Spill Events by System and Spill Category. . E-51
E-48 Summary of Drilling System Spill Events by Spill Category E-52
E-49 Drilling System, Minor Spill Events by Component E-52
E-50 Production System Spill Events by Spill Category E-53
E-51 Production System Major Spill Events by Component E-53
E-iv
-------
LIST OF TABLES (Cont'd)
Table
E-52 Production System Moderate Spill Events by Component E-54
E-53 Production System Minor Spill Events by Component E-54
E-54 Gathering/Distribution System Spill Events by Spill Category. . . . E-55
E-55 Gathering/Distribution System Major Spill Events by Component . E-55
E-56 Gathering/Distribution System Moderate Spill Events by
Component E-56
E-57 Gathering/Distribution System Minor Spill Events by Component . E-57
E-58 Ranking of Reported Component Major Spill Events by Cause and
Equipment E-58
E-59 Spill Events by Cause Category and System E-60
E-v
-------
APPENDIX E
PRESENTATION OF SPILL DATA
E.I INTRODUCTORY SUMMARY
E.I.I Purpose and Scope
This appendix, drawing on the total spill data presented in Appendix D, is essential to
the development of the spill prevention program described in this report. It presents
analysis and discussion leading to the identification of spill vulnerable points of petroleum
systems and spill prevention guidelines presented in Volume I . The analyzed data com-
prised 8473 total spill events distributed as shown in Table E-l.
Table E-l. Total Spill Events by System and Shore Code
System
Drilling System
Production System
Gathering/Distribution
System
System not Identified
Total
Number of Spill Events
Offshore
18
935
56
10
1019
Onshore
19
3059
4367
9
7454
Total
37
3994
4423
19
8473
The data from Production and Gathering/Distribution (G/D) Systems are analyzed in this
appendix (see Appendix B for System definitions and descriptions). Offshore data on the
G/D System is minimal. The data includes experience from offshore California, Alaska,
and the Gulf Coast. The gathering function for crude oil in the Gulf Coast (the dominant
source of offshore data) is accomplished primarily by operator flowlines from offshore
platforms to the shore, rather than by carrier G/D Systems. As a result, the G/D Sys-
tems' quantity is small compared to the data from the local flow and gathering subsystems
of offshore production.
E-l
-------
The data associated with either Drilling or unidentified systems are not analyzed here.
The Drilling Systems' data has been examined and found not to contain trends significant
to this study (see Tables D-19 and D-27 for presentation of Drilling System data).
Reliance is placed on failure modes and fault tree analyses to develop spill prevention
guidelines for drilling operations (see Appendix F).
E.I.2 Analytical Approach
The approach used in this study was to examine combined crude oil and condensate spill
data separately for the Production and G/D Systems. Each system was examined by
onshore and offshore applications and the reported spill size. Each spill event is defined
in terms of a number of data elements (including geographic or administrative area)
described by the Data Code Book, presented in Appendix K. The analysis, drawing data
support from Appendix D as shown by Table E-2, was conducted through the following
steps for each system's offshore and onshore data:
1. Identify subsystems with significant major or moderate spill experience.
2. Within each affected subsystem, identify equipment elements having signi-
ficant spill experience.
3. For each affected equipment element, analyze the data for significant
causes and components associated with the spill events, and prominent
cause/component combinations and trends (e. g., geographic location,
age of facility, time of year, and increasing or decreasing rate of
occurrence).
4. For each affected subsystem, examine component/cause relationships
for significant and prominent combinations and perform analyses similar
to those of Step 3.
5. Examine, for all system spills (offshore, onshore, and combined), system
components most often identified as responsible for the reported spills.
6. Examine, from the total system's spill data, the equipments most often
identified as responsible for the reported spills.
E-2
-------
Table E-2. Analysis Cross-Reference to Data Tabulations of Appendix D
Analysis
Component Versus System Elements
Component Versus Cause
Cause Versus System Elements
Component Versus Quantity Spilled
Category by System and Shore Code
Table Title
Component Versus System Elements, Moderate Spills Offshore
Component Versus System Elements, Major Spills Onshore
Component Versus Cause, G/D Systems, All Spills
Component Versus Cause, Drilling Systems, All Spills
Component Versus Cause, Production Systems All Spills
Component Versus Cause, G/D Onshore Major Spills
Component Versus Cause, Production Onshore Major Spills
Component Versus Cause, G/D Offshore Moderate Spills
Component Versus Cause, Production Offshore Moderate spills
Cause Versus System Elements, Major Spills
Cause Versus System Elements, Offshore Moderate Spills
Component Versus Quantity Spilled Category by System
Component Versus Quantity Spilled Category G/D by Shore Code
Component Versus Quantity Spilled Category Production by
Shore Code
Table
No.
D-16
D-17
D-18
D-19
D-20
D-21
D-22
D-23
D-24
D-25
D-26
D-27
D-28
D-29
w
-------
These analytical steps are designed to identify the spill vulnerable points of each system
at system, subsystem, equipment, and component levels. The criteria of Table E-3
were used to evaluate these points in support of the methodology presented in Volume I.
Table E-3. 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
E.I.3 Appendix Organization
Paragraph E. 1 has provided an overview of all of the spill data, and outlined the general
analytical approach. Paragraph E.2 provides the analysis for Production Systems' data
following the analytical format previously outlined in Paragraph E. 1.2. Paragraph E. 3
provides, in similar format, the analysis for G/D System data. Paragraph E.4 presents
an analysis at component level, of total spill events. Paragraph E. 5 provides an analysis
of spill events by quantity of spill. Paragraph E. 6 provides an analysis of total spill
events by reported cause of spill.
E-4
-------
E. 2 PRODUCTION SYSTEMS SPILL DATA ANALYSIS
E.2.1 An Overview of Data and Analytical Scope
The data to be analyzed comprised 3994 spill events distributed by subsystem and shore
code as shown in Table E-4.
Table E-4. Production System Spill Events by Subsystem
and Shore Code
Subsystem
31 Well
32 Wellhead
33 Gathering
34 Separation
35 Treater
36 Local Storage
37 Custody Transfer
38 Safety
39 Water Disposal
30 Not Identified
Total
Number of Spill Events
Offshore
14
44
169
211
142
185
17
39
10
104
935
Onshore
54
229
1196
166
393
734
73
6
46
162
3059
Total
68
273
1365
377
535
919
90
45
56
266
3994
The data appeared sufficient to support analyses for all subsystems. Offshore subsystem
analysis is based on moderate spill data since only eight major offshore spills were
reported. Onshore subsystem analysis is based on major spills where the data were suf-
ficient and on both major and moderate spills where the data were insufficient. The follow-
ing paragraphs present analyses of the subsystems.
E.2.2 Well Subsystem Analysis
The well subsystem performs the functions necessary to transport fluid from the producing
formation to the surface of the earth. The subsystem includes the bore, casing string,
production tubing, and downhole assembly, as applicable. The analyzed data comprised
88 spill events distributed by shore code and size of spill, as shown in Table E-5.
E-5
-------
Table E-5. Well Subsystem Spill Events by Spill Category
and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
4
8
0
2
14
Onshore
1
15
2
36
54
Total
5
23
2
38
68
The offshore analysis covered moderate spills while the onshore analysis examined
moderate and major spills and spills of unreported quantify.
E. 2.2.1 Offshore Well Subsystem Analysis
The eight moderate spill events exhibited no significant trend
E. 2.2.2 Onshore Well Subsystem Analysis
The two major spills were reported from Texas and occurred during periods of wireline
operation and repair/maintenance activity. The 15 moderate spills were distributed
among six components and nine reported causes, and exhibited no significant trend. The
36 spills of unreported amount included 28 from Oklahoma. Each reported flow from an
abandoned well. It is assumed, therefore, that changes in ground water pressure caused
inadequately plugged wells to seep. The Oklahoma Corporation Commission (OCC) regu-
lations (effective 1 January 1971) include Rule 3-400, which makes detailed provision for
abandonment and plugging of wells under supervision of an authorized OCC representative.
E.2.3 Wellhead Subsystem Analysis
The wellhead subsystem (or Christmas tree) controls the produced fluids from the well to
the production flowlines. The subsystem contains casing head equipment, tubing head
equipment, fixed and adjustable chokes, artificial lift when used, and power equipment.
E-6
-------
The analyzed data comprised 273 spill events distributed by shore code and size of spill
as shown in Table E-6.
Table E-6. Wellhead Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
12
28
0
4
44
Onshore
16
136
4
73
229
Total
28
164
4
77
273
The offshore analysis considered moderate spills; the onshore analysis considered major
and moderate spills.
E. 2.3.1 Offshore Wellhead Subsystem Analysis
The 28 moderate spill events exhibited 10 instances of fixed choke or choke body being
sand cut. All were in the Gulf Coast with the majority reported from the outer continen-
tal shelf (OCS). Four of these events were from the South Pass area.
E. 2.3.2 Onshore Wellhead Subsystem Analysis
The four major spills exhibited no significant trend. However, one event in Texas
occurred during workover (a major spill during wireline operations). The 136 moderate
spill events were distributed among the wellhead equipments as shown in Table E-7.
E-7
-------
Table E-7. Wellhead Subsystem Moderate Spill Events
by Equipment
Equipment
Rod Pump
Casing Head
Tubing Head
Fixed Choke
Other
Not Identified
Total
Number of
Moderate Spill Events
41
22
17
9
6
41
136
The trends exhibited by each equipment type in Table E-7 were as follows:
1. Rod Pump Equipment - The 41 events included 10 stuffing box leaks, including
six due to overpressure, and nine valve leaks with a variety of causes and
exhibited no significant trend. The stuffing box events were predominantly
from Texas District 6 (see Appendix K for District definition).
2. Casing Head Equipment - The 22 events included nine valve events which
exhibited no significant trend.
3. Tubing Head Equipment - The 17 events included five valve leaks which exhi-
bited no significant trend.
4. Fixed Choke Equipment - The nine events included seven due to sand cutting
and were predominantly from the New Orleans District.
5. Subsystem Component/Cause Combinations - The 136 spill events were distri-
buted among components as shown in Table E-8.
E-8
-------
Table E-8. Wellhead Subsystem Moderate Spill Events
by Component
Component
Stuffing Box
Valves
Other
Not Identified
Total
Number of
Moderate Spill Events
41
25
54
16
136
The 41 stuffing box events included 14 attributed to overpressure and 17 as leaking or
failed. The 25 valve events were distributed among 14 different causes with the most
significant being operational errors of leaving the valve in the incorrect open/close
position. The valves left closed in error could contribute to the stuffing box failures
from overpressure. No other subsystem component/cause combinations of significance
were exhibited.
E. 2.4 Gathering Subsystem Analysis
This discussion is limited to gathering subsystems of the Production Systems. Paragraph
E.3 presents an analysis of Gathering/Distribution Systems and Paragraph E.3.5 discus-
ses gathering subsystems of the Gathering/Distribution Systems. The gathering subsystem
collects and transfers the produced fluids by flowline from the wellhead to required surface
equipment in the Production System. The transported fluids contain wide variations in
content of oil, gas, water, sand, parafin, and asphaltine, often stated summarily as a high
basic sediment and water (BS & W) content, in comparison to the pipeline-quality oil
(BS & W content limited to 1 percent) normally transported by the Gathering/Distribution
Sjystem. The gathering subsystem contains flowline equipment, fixed and adjustable chokes,
manifold equipment, metering, pumping and automatic control equipment, and power equip-
ment. The analyzed data comprised 1365 spill events distributed by shore code and size of
spill as shown in Table E-9.
E-9
-------
Table E-9. Gathering Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
64
90
4
11
169
Onshore
76
1004
44
72
1196
Total
140
1094
48
83
1365
E. 2.4.1 Offshore Gathering Subsystem Analysis
The four major spill events exhibited no trend. The 90 moderate spill events were distri-
buted among flowline (61), manifold (5), and pump (23) equipment, with one not identified
to an equipment. The 5 manifold exhibited no trend. The 23 pump included seven of burst
gaskets, seals, and packing. The 61 flowline exhibited two trends; 11 of sandcut or flow-
cut pipe, fittings, and valves, and 26 involving pipe, of which 14 were described as leaking.
Twelve of the 14 leaking pipe events, all reported from Gulf waters off Louisiana, were
distributed by location and period of occurrence as shown in Table E-10.
Table E-10. Gathering Subsystem Moderate Spill Pipe Leaks
by Location and Year
Location
State Waters
(22 months)
OCS
(17 months)
Total Spills
Period of Occurrence
To 30 Jan. 1971
3 spills in
13 months
6 spills in
8 months
9
From 30 Jan. 1971
2 spills in
9 months
1 spill in
9 months
3
Total Spills
5
7
12
E-10
-------
Although the quantity of data is small, by inspection of the data, the spills due to leaking
pipe in State waters occurred at the same rate (about three spills per year) before and
after January, 1971. However, OCS data exhibited a decrease from nine spills per year
to less than two per year after January, 1971. Provisions of Gulf OCS Order Number 8,
issued by the USGS, require high and low pressure sensors close to the wellhead on flow-
lines from wellheads, effective 30 January 1971, to control abnormal pressure.
E. 2.4.2 Onshore Gathering Subsystem Analysis
The major and moderate spills indicated that flowline equipment and, in particular, pipe
events were dominant in gathering subsystem spills. Beyond this observation no signifi-
cant trends were indicated at the subsystem level. Analyses of flowline equipment and
component pipe are given in Paragraphs E.2.11 and E.4, respectively.
E. 2.5 Separation Subsystem Analysis
The separation subsystem comprises equipment which separates produced liquids and gas.
The equipment types used include high and low pressure separators and controls, and
scrubbers with scrubber controls. Some applications use three-phase separators which
perform the additional function of separating water from the produced fluids. The sepa-
rator's function is to remove gas from the produced fluids. When a significant amount of
gas is produced, a scrubber may be used to remove the relatively small quantity of liquid
in the gasline before the gas is used, processed, or sent to a flare. Depending on the
production conditions, some facilities use a single low pressure separator for one or sev-
eral wells. Some facilities with high tubing pressure wells use two or more separation
stages, in series, from high to low pressure. Other facilities with high volume production
or with both high and low pressure wells use parallel separation paths to handle the flow.
The analyzed data comprised 377 spill events distributed by shore code and size of spill
as shown in Table E-ll.
E-ll
-------
Table E-ll. Separation Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
100
100
0
11
211
Onshore
21
126
11
8
116
Total
121
226
11
19
377
E. 2.5.1 Offshore Separation Subsystem Analysis
Moderate spill events for the separation subsystem were distributed among the equipments
as shown in Table E-12.
Table E-12. Separation Subsystem Moderate Spill
Events by Equipment
Equipment
Low Pressure Separators
Low Pressure Separator Controls
High Pressure Separator
High Pressure Separator Controls
Scrubbers
Scrubber Controls
Not Identified
Total
Number of Spill Events
42
12
7
4
6
2
27
100
The scrubbers provided insufficient data to support analysis. The 54 spill events from low
pressure separators and controls presented three trends of interest: 13 dump valves which
failed to open, close, or function; nine high level sensors which failed to function; and 11
pressure relief valves and rupture discs which burst, failed open, or overflowed. The data
E-12
-------
do not distinguish between rupture disc actions as normal protective action and those due
to disc deterioration or misapplication. The 11 spill events from high pressure separators
and controls exhibited one significant finding: six were attributed to dump valves, and five
of these failed as a result of sand or flow cutting.
E.2.5.2 Onshore Separation Subsystem Analysis
The 11 major spill events exhibited no trends. The 126 moderate spill events were domi-
nated by failures of dump valves (38) and rupture discs (23). The dump valve events
included 27 with cause reported as failed upon, failed closed, and nonfunction. The rup-
ture disc events included 20 with cause reported as burst. No information was given to
indicate whether rupture disc action was due to deterioration or misapplication of the disc,
or due to normal protective action in response to abnormally high pressure in the separator.
Only 13 of the spill events were assigned to high pressure separator and scrubber equipment.
The data exhibited no significant indication of sand or flow cutting in either the high pressure
separators or elsewhere in this analysis.
E.2.6 Treater Subsystem Analysis
The treater subsystem treats and conditions the crude oil for emulsion and provides for
separation of produced water and oil. The subsystem includes heater treaters and controls,
chemical-electric treaters and controls, gun barrels, skimmers, free water knock out
(FWKO), and power equipment. The treaters and gun barrel separators break down the oil/
water emulsion and separate the water from the produced fluid. When the well produces a
Ugh cut of free water (water which will separate from the oil and emulsion by gravity
Within 5 minutes and without heat or chemical treatment), the facility may use FWKO equip-
ment to separate out the free water before sending the fluids to the treater. The skimmer
is used to retain the relatively small quantity of crude oil from the water discharged from
Hie treater subsystem and prior to water disposal. The analyzed data comprised 535 spill
events distributed by shore code and size of spill as shown in Table E-13.
E-13
-------
Table E-13. Treater Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
63
67
0
12
142
Onshore
22
306
38
27
393
Total
85
373
38
39
535
E. 2.6.1 Offshore Treater Subsystem Analysis
The 67 moderate spill events were distributed among all of the equipments with heater
treaters (22 events) being the most frequently identified and chemical-electric treaters
(five events) being the least frequently identified. The most prominent trend with all
equipments was 18 spill events attributed to dump valves, with 16 either failed open,
failed closed, or nonfunctioning. Of these, 10 were specifically identified as failed open.
For the facilities visited (see Appendix A), instrument gas for valve operation was drawn
from a separate supply rather than from the treater itself, thus providing protection
against loss of instrument gas pressure when the treater dump valve hangs open. Thus,
spillage resulting from an open dump valve is believed to have involved the salt water
dump valve with a subsequent overflow of oil from the skimmer tank.
A second trend resulted from nine spill events due to high level sensors. The cause of
most of these events was reported as nonfunction and was attributed to heater treaters.
Failure of the oil level sensor would allow oil to flow out the gasline. Failure of the level
sensor at the oil-water interface would cause water to flow with the oil out the oil leg and
possibly overflow the oil tank. It is also possible for the same malfunction to cause oil to
overflow the gas line if the oil leg could not handle the entire flow of oil and salt water.
A third (and minor) trend involved bursting of four rupture discs.
E-14
-------
E. 2.6.2 Onshore Treater Subsystem Analysis
The 38 major spills included 23 attributed to heater treaters and controls, with the
remainder distributed among the chemical-electric treaters, gun barrels, skimmers, and
FWKO equipment. Only the heater treater equipment reflected a trend. That trend con-
sisted of six dump valve spill units, including five attributed to fail open, fail closed, and
nonfunction causes. The 306 moderate spill events included 211 attributed to heater
treaters and controls, with the remainder distributed over the other subsystem equip-
ments. Only the heater treaters and control equipment exhibited trends of significance.
Dump valve events (32) were reported in fail open, fail closed, and nonfunction modes.
Fire tube events (14) were reported for leaking. Pipe events (16) were reported as being
plugged. A number of valve events (28) were reported over a variety of causes and
exhibited no significant trend.
E.2.7 Local Storage Subsystem Analysis
This discussion is limited to production storage subsystems. Paragraph E.3.3 presents
a discussion of storage subsystems of the Gathe'ring/Distribution Systems. The storage
subsystem provides for the local storage of produced oil until guaging or metering and sale
of the oil (usually to a pipeline) occurs. The system includes tanks, firewalls, tank-
associated equipment, sump (when applicable), and power equipment. The analyzed data
comprised 919 spill events distributed by shore code and size of spill as shown in
Table E-14.
Table E-14. Storage Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
99
74
2
10
185
Onshore
21
486
85
142
734
Total
120
560
87
152
919
E-15
-------
Offshore analysis considered moderate spills; onshore analyses considered major
spills.
E. 2.7.1 Offshore Storage Subsystem Analysis
The 74 moderate spill events were predominantly assigned to tanks (14), tank associated
equipment (23), and sump equipment (36). Among these events, three trends were
exhibited:
1. Nonfunctioning high level sensors were prominent for both storage tanks
and sump systems.
2. Nonfunctioning pumps were predominant in sump systems and, to a
lesser degree, in storage tanks.
3. Tank and sump spill events reported overflow as predominant.
The sump events were reported only for the Gulf Coast OCS. Gulf OCS Order Number 8
requires a sump with control of level but does not require inspection or test of the pumps.
Louisiana requires a sump or other suitable means of containment, but does not require
level control or specific inspection or test.
E. 2.7.2 Onshore Storage Subsystem Analysis
The 85 major spill events were predominantly assigned to tanks (59), tank-associated
equipment (19), and sump equipment (4). No trends were exhibited among the tank-
associated equipment or sump events. The 59 tank events included 20 of tank and tank
shell leak. Only four were reported for overflow. The spill was contained within a
firewall in only eight instances and the spill was trapped in a natural depression in only
five instances. The 486 moderate spill events were examined and exhibited the same
trends as for the major spill events.
E.2.8 Custody Transfer Subsystem Analysis
The custody transfer subsystem monitors BS & W content, meters fluid flow, and transfers
crude oil from production storage to sales or pipeline. The subsystem contains pumps and
pump controls, metering equipment, manifold and sampling equipment, prover tanks and
E-16
-------
associated equipment, and power equipment. In nonautomated custody transfer functions,
gauger and trunk transfer activity may be considered in series with the applicable hard-
ware. The data to be analyzed comprised 90 spill events distributed by shore code and
spill size as shown in Table E-15.
Table E-15. Custody Transfer Subsystem Spill Events
by Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
7
8
1
1
17
Onshore
2
66
5
0
73
Total
9
74
6
1
90
E.2.8.1 Offshore Custody Transfer Subsystem Analysis
The eight moderate spill events included four instances of loss of pumping function for
different causes. No trends of significance were exhibited.
E.2.8.2 Onshore Custody Transfer Subsystem Analysis
The five major spill events exhibited no trend of significance. The 66 moderate spill
events exhibited 11 instances of electrical malfunction or power loss as the only trend
of significance.
E.2.9 Safety Subsystem Analysis
The safety subsystem monitors and shuts down any phase of the production, or all pro-
duction in an emergency, and provides visual and audible alarms in the event of undesired
system operation or condition. The subsystem contains energy source (e. g., instrument
gas) and distribution equipment, sensing and detecting equipment, monitoring and alarm
equipment, subsurface safety valves, and high/low pressure valves. In general, a spill
E-17
-------
event attributed to the safety subsystem requires a discrepancy elsewhere in the system
(which places a demand for safety system operation) in addition to a failure within the
safety subsystem itself. The data to be analyzed comprised 45 spill events distributed
by shore code and spill size as shown in Table E-16.
Table E-16. Safety Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
13
21
1
4
39
Onshore
0
5
I
0
6
Total
13
26
2
4
45
E. 2.9.1 Offshore Safety Subsystem Analysis
The 21 moderate spill events included four attributed to high level sensors and four attri-
buted to valves which did not function. No significant trend was observed.
E. 2.9.2 Onshore Safety Subsystem Analysis
The five moderate spill events included three occasions of high level sensors failing to
function.
E.2.10 Water Disposal Subsystem Analysis
The water disposal subsystem provides for the disposal of produced water through water
processing equipment to meet various requirements prior to water disposal or injection.
The subsystem includes, as appropriate, filters, clarifying tanks, flotation cells, oxygen
stripping tanks, settling pits or tanks, power equipment, and injection wells. The analyzed
data comprised 56 spill events distributed by shore code and size of spill as shown by
Table E-17.
E-18
-------
Table E-17. Water Disposal Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
4
4
0
2
10
Onshore
6
34
5
1
46
Total
10
38
5
3
56
E. 2.10.1 Offshore Water Disposal Subsystem Analysis
The four moderate spill events exhibited no trends.
E.2.10.2 Onshore Water Disposal Subsystem Analysis
The five major spills exhibited no trends. The 34 moderate spill events identified mal-
functioning pumps as the dominant trend. No other trend of significance was exhibited.
£.2.11 Analysis of Total Equipment Spills for the Production System
A detailed record of spill events reported against the Production System is presented in
Table E-18. Each system, subsystem, and equipment element is shown with the number
of events or failures reported for that element. To provide a measure of each element's
performance, Table E-18 also includes a percentage of contribution to the higher levels.
Subsystem events are shown as a percentage of total combined events for all systems and
fatal reported Production System events. Equipment failures are shown as a percentage
of total Production System and subsystem events.
Table E-19 presents a ranking of Production System equipments from Table E-18 that
caused significant numbers of system events. It was necessary to analyze the data on
tower tier equipment and component events to identify those that represent significant
problem areas at the subsystem level. Table E-19 shows that flowline equipment accounted
i>r the majority of events with 30.54 percent followed by tanks with 11.54 percent. The
E-19
-------
remaining events were distributed among the rest of the equipment with no equipment
accounting for more than 10 percent of the events reported.
Table E-19. Ranking of Production System Equipment by
Number of Reported Spill Events
Equipment
Flowline Equipment
Tanks
Tank Associated
Equipment
Heater Treater
Separator L. P.
Pumps
Subsystem
Gathering
Storage
Storage
Treater
Separation
Gathering
No. of
Spill
Events
1220
461
335
265
157
103
% of Total
Events
14.43
5.45
3.96
3.13
1.86
1.22
% System
Events
30.54
11.54
8.39
6.63
3.93
2.58
Approximately 88 percent of the spill events for flowline equipment involved pipe (Table
E-20). The major cause was leaking, accounting for about 54 percent. Leaks were due
to material failure caused by corrosion.
Table E-20. Flowline Equipment Spill Events by Component
and Cause (1220 Events Reported)
Cause
Code
Leaking
Broken
Farm
Machinery
Valve Opened
Hole
Corroded
Burst/Ruptured/
Split
Parted, Line
Total
Code
26
12
93
98
25
15
14
33
Pipe
46
375
91
92
65
60
683
Not
Ident.
00
24
20
8
52
Valves
74
7
4
4
4
19
Coupling
12
7
~
5
12
Check
Valve
80
~
4
4
Nipple
41
3
6
9
Union
72
6
4
10
Total
422
121
4
4
92
65
72
9
789
E-20
-------
PAGE NOT
AVAILABLE
DIGITALLY
-------
The second major category associated with flowline equipment events was "not identified"
(i.e., components were not identified in the data sources). The causes associated with
this group could also result from corrosion. The third-ranked component was valves.
Of the 19 events caused by valves, 42 percent were caused by a third party and 58 percent
were caused by material failure. All of the other component events were caused by a
material failure.
Of the reported tank events, leaking and hole accounted for about 35 percent (Table E-21.)
In about 80 percent of these cases the component involved was not identified. All valve
events were caused by third party or operator error. Most of the tank shell and foundation
events were attributed to leak and hole. The data sources did not provide information as
to why the tanks leaked or had holes.
Table E-21. Tank Equipment Spill Events by Component and
Cause (461 Events Reported)
Cause
Code
Leaking
Overflowed
Hole
Lightning
Not Reported
Valve Open/Closed
Vandalism
Left Open
Incorrect Operation
Burst/Ruptured/
Split
Corroded
Total
Code
26
31
25
77
03
98
99
48
51
14
^^L
15
Not
Ident.
00
71
73
59
32
29
264
Valve
74
5
5
4
4
18
Tank
Shell
67
7
16
5
5
33
Foundation
24
10
__
mm^
Total
88
73
75
32
29
5
5
4
4
5
5
325
E-23
-------
For tank associated equipment, valves and pipe contributed the most spill events, 11.6
percent (Table E-22). However, 82 percent of the valve events were caused by operator
error or third party damage and 18 percent were a result of material failure. All of the
pipe events were a result of material failure. Three percent of the components could not
be identified and were attributed to personnel error. Pump events caused 3 percent of the
events reported
Table E-22. Tank Associated Equipment Spill Events by
Component and Cause (335 Events Reported)
Cause
Code
Left Closed
Left Open
Livestock
Failure
Closed
Leaking
Hole
Broken
Plugged
Improper
Maint.
Incorrect
Operation
Equip. Failure
Nonf uncti oning
Total
Code
47
48
95
23
26
25
12
34
50
51
10
30
Valve
74
13
10
9
7
39
Pipe
46
-
12
11
8
8
39
Not
Went.
00
5
5
10
Pump
49
~
6
5
11
Total
13
10
9
7
12
11
8
8
5
5
6
5
99
Of heater treater events, dump valves were a major contributor, accounting for 13.6 percent
(Table E-23). Other valves were second, contributing approximately 8.7 percent. However,
since the data sources did not specify the type of valves, they could also be dump valves.
Pipe and rupture discs ranked third and fourth, respectively. No other component reported
a significant number of events.
E-24
-------
Table E-23. Heater Treater Equipment Spill Events by
Component and Cause (265 Events Reported)
Cause
Code
Equip. Failure
Leaking
Nonfunctioning
Hole
Overflowed
Not Reported
Failure Opened
Failure Closed
Plugged
Total
Code
10
26
30
25
31
03
22
23
34
Not
Went.
00
17
12
11
8
6
54
Valve
74
17
6
23
Dump
Valve
82
6
20
10
36
Pipe
46
--
8
8
Disc
Rupture
16
9
~
9
Total
34
12
17
17
6
6
20
10
8
130
Of the 157 events reported against separator, low pressure, disc rupture accounted for
15.3 percent (Table E-24). The cause of events in ail cases was burst or ruptured.
Since the function of the disc is to rupture under excess pressure, the initial cause of the
event should be attributed to some other component. However, the data sources did not
provide enough information to determine the responsible component.
Table E-24. Separator, Low Pressure Equipment Spill Events by
Component and Cause (157 Events Reported)
Cause
Code
Overflowed
Nonfunctioning
Equip. Failure
Sand Cut
Failure Closed
Burst/Ruptured/
Split
Total
Code
31
30
10
19
23
14
«._
Not
Went.
00
15
9
6
30
Dump
Valve
82
~
6
5
5
~
16
Disc
Rupture
16
__
24
24
Relief
Valve
86
6
~
~
6
Hi Level
Sensor
61
9
~
9
Total
21
24
6
5
5
24
85
E-25
-------
The largest component event category for pumps was "not identified" with 13 (Table E-25).
The identified component with the most events was packing gland. The remaining 103
events reported on pump were distributed among many components.
Table E-25. Pump Equipment Spill Events by Component
and Cause (103 Events Reported)
Cause
Code
Nonfunctioning
Equip. Failure
Burst/Ruptured/
Split
Leaking
Total
Code
30
10
14
26
Not
Hent.
00
7
6
13
Pipe
46
4
4
Packing
Gland
28
4
4
8
Pump
49
4
4
Total
7
6
8
8
29
E-26
-------
E. 3 GATHERING/DISTRIBUTION SYSTEMS SPILL DATA ANALYSIS
E.3.1 An Overview of Data and Analytical Scope
The analyzed data comprised 4423 spill events distributed by subsystem and shore code as
shown in Table E-26.
Table E-26. Gathering/Distribution System Spill Events
by Subsystem and Shore Code
Subsystem
Pipeline
Storage
Pump Station
Safety
Gathering
Not Identified
Total
Number of Spill Events
Offshore
44
2
5
1
2
2
56
Onshore
3182
136
160
2
868
19
4367
Total
3226
138
165
3
870
21
4423
For offshore events, only the pipeline subsystem was analyzed; the remaining subsystems
were examined and found not to exhibit any significant trends. For onshore events, the
pipeline, storage, pump station, and gathering subsystems had sufficient data. The data
for the unidentified subsystems was examined and found to contain no information deemed
significant to the study.
E.3.2 Analysis of Pipeline Subsystem
The pipeline subsystem comprises the manifold and distribution network through which
pipeline-quality crude oil is transported to a refinery or other terminal facility. When
the data specifically indicated that a spill was associated with a gathering function, it was
assigned to the gathering subsystem. Otherwise, the spill event was associated to this
subsystem which comprises equipment elements identified as pipe, scraper trap, pipe
E-27
-------
support structure, stream crossings, and road crossings. The analyzed data comprised
3226 spill events, distributed by shore code and size of spill, as shown in Table E-27.
Table E-27. Pipeline Subsystem Spill Events by
Spill Category and Shore Code
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
Offshore
19
21
1
3
44
Onshore
36
2429
634
83
3182
Total
55
2450
635
86
3226
E.3.2.1 Offshore Pipeline Subsystem Analysis
The 21 moderate spill events did not exhibit any significant trends at the equipment level.
Two component/cause combinations were exhibited; overflow as a result of pumps failing
to function (four), and overpressure within the subsystem itself (three). These events are
associated with Gulf OCS operations with none reported in Louisiana State waters. This
may have been a result of high and low pressure shut-in devices for pipeline pumps
required (effective 30 April 1971) by OCS Order Number 9, but not specifically required
Louisiana Title 30 Stream Control Regulations. The increased sophistication required for
OCS facilities could increase the opportunity for equipment malfunction and spills to be
exhibited in the data; the benefits of reduced spill frequency due to added protection
against unusual pipeline pressure could not be evaluated. It is not clear from the data
whether these events occurred in an offshore gathering pipeline or in operator production
flowlines from the platforms to the offshore pipeline.
E-28
-------
E. 3.2.2 Onshore Pipeline Subsystem Analysis
Pipe and road crossing equipment were analyzed; the other equipment categories had
insufficient data to support analysis.
E. 3.2.2.1 Pipe Equipment
1. Component Analysis - Of the 634 major subsystem spills, 614 were attri-
buted to pipe equipment and distributed among components as shown in
Table E-28.
Table E-28. Pipe Equipment Onshore
Major Spill Events by Component
Component
Pipe
Welds
Fittings
Valves
Other
Not Identified
Total
Number of Major Spill Events
513
13
11
9
29
39
614
2.
An examination was made of data for welds, fittings, valves, and equipment
events not identified. None showed a significant trend from the major spill
events, but did show repetitive events attributed to bursting and rupture
from the moderate spill events.
Analysis of Reported Cause - The 614 pipe equipment spill events are distri-
buted by cause as shown in Table E-29.
E-29
-------
Table E-29. Pipe Equipment Onshore Major Spill Events
by Cause and Component
Cause
Code
Burst
Corrosion
External Corrosion
Internal Corrosion
Defective Material
Leak
Defective Weld
O/M Error
Natural Causes
Third Party (Other)
Farm Machinery
Road Machinery
Other
Total
Code
14
15
16
17
20
26
39
40
70
90
93
96
Component
Pipe
46
35
41
155
50
24
15
19
9
12
24
14
69
46
513
Other
N/A
4
0
2
1
6
1
8
5
2
0
0
3
30
62
Not
Identified
00
3
6
5
8
0
5
0
2
0
0
2
2
6
39
Total
42
47
162
59
30
21
27
16
14
24
16
74
82
614
The spills for component pipe will be analyzed for the causes identified
in Table E-29. A total of 107 spill events due to a third party are pre-
sented. Those attributed to road machinery (69 events) and farm machi-
nery (14 events) are shown separately. All other reported third party
causes account for the remaining 24 spill events.
3. Analysis of Pipe Cause Combinations
a. Burst - Of the 35 reported events, 12 occurred in Texas, six in
Mississippi, and four in Colorado. The Texas events occurred
E-30
-------
during normal operation and without seasonal or geographic trend.
Most spills were from large (6-inch or larger) diameter pipe. No
significant trends were observed in the Mississippi or Colorado
events.
b. Corrosion - Of the 41 events related to corrosion (as distinguished
from the more specific causes of external or internal corrosion)
27 occurred in Texas and 12 in Mississippi. The Texas events
occurred most frequently from April through September. District
4 (see Appendix K) accounted for 10 of the Texas events, with nine
in the April through September period. The Mississippi events
occurred from large diameter pipe mostly from October through
March. None showed substantial recovery of oil.
c. External Corrosion - The 155 events are distributed by State in
Table E-30.
Table E-30. Pipe Component Onshore Major Spill Events
Attributed to External Corrosion (by State)
State
Illinois
Indiana
Louisiana
Mississippi
New Mexico
Ohio
Oklahoma
Pennsylvania
Texas
Other
Total
Number of Major
Spill Events
10
9
7
4
4
8
8
9
82
14
155
E-31
-------
(1) Illinois - The 10 spill events affected pipe installed in the 1930s.
In seven events the pipe was under cathodic protection and in nine
events it was coated.
(2) Indiana - The nine spill events appeared in two groups: pipe
installed before 1920 in Lake, Porter, and Fulton Counties with-
out cathodic protection or coating; and pipe installed between
1930 and 1950 in Wayne, Putnam, Shelby, and Vigo Counties with
cathodic protection but uncoated.
(3) Louisiana - Most of the seven events were for pipe laid in the
1940s in the Lafayette District. In five events the pipe was
under cathodic protection. In all events the pipe was uncoated.
(4) Mississippi - The four events were from pipe laid in the 1950s in
Perry and Lamar Counties. None were coated or under cathodic
protection.
(5) New Mexico - The four events were from pipe installed in the
1930s in Lea County. All affected pipe was under cathodic pro-
tection and one event was reported for coated pipe.
(6) Ohio - Of the eight events, five occurred in pipe laid in Trumbull County
prior to 1920, with no protection. Three occurred in pipe laid in
Wood County between 1920 and 1950 with one event reporting
cathodic protection. The pipe was not coated in any of these
events.
(7) Oklahoma - The eight events primarily from Districts 1 and 4
(see Appendix K), included three with coating and cathodic pro-
tection, two with cathodic protection only, and two with no pro-
tection. Six of the events occurred in pipe laid between 1920
and 1940.
E-32
-------
(8) Pennsylvania - All nine events were reported for pipe laid in
Clarion, Butler, and McKean Counties before 1920 and without
protection.
(9) Texas - Of the 82 events, 38 reported information concerning
the status of the pipe. Of these 38, nine had coating and cath-
odic protection, 13 had either coating or cathodic protection,
and 16 had no protection. The pipe ranged in age from before
1920 through the 1960s without significant trend between age
and protection provided.
d. Internal Corrosion - The 50 events included five from Montana and 39
from Texas. The five from Montana occurred in pipe laid in the 1950s
in Wibaux County. In all events the pipe had both coating and cathodic
protection. The 39 Texas events are discussed in two groups
(1) In one group of 26 events, 22 occurred in Districts 7, 8 and 10
(see Appendix K). Four events in District 10 occurred in pipe
laid in the 1960s coated and under cathodic protection. All occur-
red in large (6-inch or larger) diameter pipe and were reported
for October and November.
(2) In a second group of 13 events, 11 occurred in pipe with coating
and cathodic protection.
It may be significant that most instances of internal corrosion occurred
in pipe with both coating and cathodic protection. Two possible expla-
nations are offered:
(1) External corrosion is exhibited by the data at about three times
the frequency of internal corrosion. Coated and cathodically pro-
tected pipe will resist external corrosion to such an extent that
internal corrosion has an opportunity to damage the pipe, whereas
unprotected pipe can experience external corrosion before the
effects of internal corrosion are significant.
E-33
-------
(2) The protective coatings and cathodic protection (and possibly
ground potential conditions generating a requirement for pro-
tection against external corrosion) may create conditions
capable of accelerating existing mechanisms of internal cor-
rosion. No experience or support for this possibility was
obtained from consultation with industry representatives.
e. Defective Material - Eighteen of the 24 reported events occurred in
Kansas, Montana, Oklahoma, and Texas. Pipe installation dates
ranged from 1920 through the 1960s.
f. Leak - These 15 events were primarily from Texas with District 7
being most prominent. Pipe age and protection information were
not reported.
g. Defective Weld - Eleven of these 19 events were reported in
Oklahoma on pipe installed between 1930 and 1950. In all events
the pipe was coated; the status of cathodic protection was not
reported. The distribution of these events by type of weld, i. e.,
longitudinal (factory) and girth (field), was not determined.
h. Operation and Maintenance Error - No trend was observed in the
nine events reported.
i. Natural Causes - Of the 12 events reported, five were attributed
to flooding. No other trend was observed.
j. Third Party - The most prominent third party action reported
was damage from road machinery with 69 events, including 44
from Texas and 11 from Oklahoma. No other trends were exhibited.
E. 3.2.2.2 Road Crossing Equipment
Of the 634 onshore major spills in Table E-28, 16 were attributed to road crossing equip-
ment. Of the 16 events, 15 were reported for pipe with predominant causes being corro-
sion (five) and road machinery (eight). The corrosion events were all reported from
E-34
-------
Colorado, and all were sited for violation of regulations. Only one has occurred since
1970. Of the road machinery events, five were reported from Texas. No other trends
were exhibited.
E.3.3 Storage Subsystem Analysis
This discussion is limited to storage subsystems of Gathering/Distribution (G/D) Systems.
Production storage subsystems are discussed in Paragraph E. 2.7. The storage sub-
system comprises a temporary storage or holding facility for incoming crude oil pending
transshipment. The subsystem is divided into equipment elements of tank, tank firewall,
tank-associated equipment, power equipment, and equipment not identified. As previously
indicated, only onshore data are of sufficient quantity to support analysis. The analyzed
data comprised 136 events distributed by size of spill, as shown in Table E-31.
Table E-31. Storage Subsystem Onshore Spill Events
by Spill Category
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
1
96
38
1
136
The 38 major spills were examined and found to contain 32 events for the equipment tank
and six events for tank-associated equipment. Seventeen events were distributed among
nine components. These included five valve failures due to four different causes, and four
meter failures due to three different causes. Twenty-one tank failures were distributed
over 13 causes with not more than three repetitions of any single cause. As a result, no
significant trend was found. However, tank and tank-associated equipment are among the
top five equipments in frequency of total spills and will be analyzed on the basis of total
spills in Paragraph E.3.6.
E-35
-------
E.3.4 Pump Station Subsystem Analysis
The pump station subsystem comprises the means for pumping and controlling the flow of
crude oil during transfer through the G/D System. The subsystem is divided into 19
equipment elements as defined in Appendix B. The analyzed data comprised 160 events
distributed by size of spill as shown in Table E-32.
Table E-32. Pump Station Subsystem Onshore Spill Events
by Spill Category
Spill Category
Minor
Moderate
Major
Not Identified
Total
Number of Spill Events
1
111
38
10
160
The 38 major spill events were distributed among six equipment elements, 18 causes, and
16 components with only one combination of more than two occurrences. The single com-
bination represented three events of a plugged pump strainer. As a result, no trends of
significance were exhibited. However, pump equipment in this subsystem is among the
top five equipments in frequency of total spills. It will be analyzed on the basis of total
spills in Paragraph E.3.6.
E.3.5 Gathering Subsystem Analysis
This discussion is limited to gathering subsystems of the Gathering/Distribution System.
Production gathering subsystems were discussed in Paragraph E.2.4. The gathering sub-
system comprises the network of pipelines and associated manifolding which gathers crude
oil from the oil fields and brings it to a central gathering point. If the function in a
reported spill event is not specifically identified as gathering, the event is assigned to the
pipeline subsystem. The gathering subsystem is subdivided by type of facility rather than
equipment, as for the other subsystems. The type breakdown is made for gravity, suction,
E-36
-------
pressure, and not identified. As previously indicated, only onshore data provided support
for analysis. The analyzed data comprised 868 events distributed by size of spill, as
shown in Table E-33.
Table E-33. Gathering Subsystem Onshore Spill Events
by Spill Category
Spill Category
Minor
Moderate
Major
Not Known
Total
Number of Spill Events
8
775
83
2
868
This analysis covered the group of major spill events. Of these 83 events, 69 were
reported with system type not identified. An inspection of the data indicated that no sig-
nificant trends may be found by facility type. Seventy-four of the 83 events were identified
to the component pipe. The remaining nine were distributed among several other compo-
nents with no additional component trends indicated. The 74 component pipe spill events
are distributed by cause in Table E-34. The causes exhibiting trends with the component
pipe were:
1. Burst - All six events occurred in Texas from large (6-inch diameter or
larger) pipe. No other trends were exhibited.
2. Corrosion - All 21 events occurred in Texas. No further trends were
indicated from the data.
3. Internal Corrosion - The 16 events were reported from Texas Districts
8 and 9, primarily in the winter months.
4. External Corrosion - The seven events were reported from Texas, from
large diameter pipe. No data on pipe age or protection was reported. No
other trends were exhibited.
E-37
-------
5. Third Party - The 12 third party events included eight attributed to road
machinery damage. These eight were reported from Texas with the
majority reported from October through March. Most were from District
9 (see Appendix K) and indicate substantial nonrecovery of spilled oil.
Table E-34. Gathering Subsystem Onshore Major Spill Events
by Cause and Component
Cause
Burst
Corrosion
Internal Corrosion
External Corrosion
Leak
Ported
O/M
Natural Causes
Third Party (Total)
Other
Code
14
15
16
17
26
33
40
70
90
Total
Component
Pipe
6
21
16
7
2
4
3
1
12
2
74
Other
0
1
0
0
2
0
0
1
1
4
9
Total
6
22
16
7
4
4
3
2
13
6
83
E.3.6 Analysis of Total Equipment Spills for the Gathering/Distribution System
A display of total spill events reported against the Gathering/Distribution System is given
in Table E-35. The system, subsystem, and equipment elements are shown with the total
number of events or failures reported for each. To provide a measure of the performance
of each element, Table E-35 also includes each element's percentage of contribution to the
higher levels. Subsystem failures are shown as a percentage of total events reported for
all systems, and total reported Gathering/Distribution System failures. Equipment
failures are shown as a percentage of total events, Gathering/Distribution System events,
and subsystem events.
E-38
-------
Table E-35. Gathering/Distribution System Spill Events by
Subsystem and Equipment
ELEMENT
Pipeline Subsystem
Pipe
Scraper Trap Equipment
Pipe Support Structure
Stream Crossing
Road Crossing
Equipment Not Identified
Storage Subsystem
Tanks
Tank Firewall
Tank Associated Equipment
Power Equipment
Equipment Not Identified
Pump Station Subsystem
Pumps
Centrifugal Pumps
Reciprocating Pumps
Manifold Equipment
Rotary Pumps
Steam Engine
Gas Turbine
Steam Turbine
Internal Combustion Engine
Electrical Motor
Pressure Controls
Metering Equipment
Valve
Valve Operating & Control Equipment
Electric Power & Control Equipment
Communications Equipment
Drainage System Equipment
Power Equipment
Equipment Not Identified
Safety Subsystem
Pressure Sensing Equipment
Pressure Switching Equipment
Flow & Gauge Equipment
Temperature Recorders
Power Equipment
Equipment Not Identified
Gathering Subsystem
Gravity
Suction
Pressure
Equipment Not Identified
Subsystem/Equipment Not Identified
Total G/D System Failures
Total Failures All Systems
NUMBER
OF EVENTS
3226
3117
28
0
7
50
30
138
78
0
57
0
3
165
88
1
3
6
0
0
0
0
0
0
1
4
23
4
2
0
3
0
27
3
0
0
1
0
0
1
870
73
41
8
748
21
4423
8453
% TOTAL
EVENTS
33.23
36.87
0.33
0.08
0.59
0.35
1.63
0.92
0.67
0.04
1.92
1.04
0.01
0.04
0.07
0.01
0.05
0.27
0.05
0.02
-
0.04
-
0.32
0.02
-
-
0.01
-
0.01
10.29
0.86
0.49
0.09
8.85
0.25
52.35
100.00
% SYSTEM
EVENTS
73.03
70.44
0.63
0.16
1.13
0.68
3.12
1.76
1.29
0.07
3.66
1.99
0.02
0.07
0.14
_
0.02
0.09
0.52
0.09
0.05
-
0.07
-
0.61
0.05
-
-
0.02
-
0.02
19.66
1.65
0.93
0.18
16.90
0.47
100.00
N/A
% SUBSYSTEM
EVENTS
100.00
96.44
0.87
0.22
1.55
0.93
100.00
56.52
41.30
2.17
100.00
4.32
0.62
1.85
3.70
_
_
0.62
2.47
14.20
2.47
1.23
1.85
6.67
100.00
-
50.00
50.00
100.00
8.39
4.71
0.92
85.98
N/A
N/A
N/A
E-39
-------
After extracting and displaying the system data shewn in Table E-35, the most significant
contributing elements were selected. Each of the equipments was ranked according to its
contribution to spills. The six worst-case elements (those responsible for more than 1
percent of the system spills) were selected for further study. The equipment ranking,
shown in Table E-36, lists equipment, subsystem, number of events, percentage of sys-
tem, and total events. Each equipment listed in Table E-36 is discussed in the following
paragraphs.
Table E-36. Hanking of Gathering/Distribution System Equipment
by Number of Reported Spill Events
Equipment
Pipe
Pumps
Tanks
Gravity
Tank Associated
Equipment
Road Crossing
Subsystem
Pipeline
Pump Station
Storage
Gathering
Storage
Pipeline
Number of
Spill Events
3117
88
78
73
57
50
% of Total
Events
70.44
1.99
1.76
1.65
1.29
1.13
% System
Events
36.87
1.04
0.92
0.86
0.67
0.59
Within the Gather ing/Distribution System, each of the 3117 data records for which pipe was
reported was screened to identify the associated component (where applicable) and the
cause. The results of the detailed analysis of these spill report records are shown in
Table E-37. The table shows that the components most frequently reported for pipe equip-
ment related spills were pipe and "not identified." The three corrosion categories com-
bined were responsible for 1785 of the 3117 total spill events charged to pipe. Of the three
corrosion categories, corroded externally was the most frequently reported cause for
spills, accounting for 1083 events. The remaining causes most frequently reported were:
1. Leaking - for which the actual cause of the leak could not be determined
2. Road Machinery - such items as ditching machines, maintainers, bulldozers,
and other construction and maintenance machinery
E-40
-------
Table E-37. Pipe Equipment Spill Events by Component
and Cause (3117 Reported Events)
Cause
Component
o
0,
0)
03
o
fH
m
T3
(1)
f-i
a
"S
T3
O
J-i
f-t
O
o
w
T3
0)
TD
O
!H
f-i
O
O
rt
Q)
g
"O
01
-B
^
t<
o
O
bo
1
oi
!-i
0)
s
O
03
(U
CO
03
O
S-t
o
S 0
< u
03
0)
03
U
"8 o
H O
Code
03
12
14
15
16
17
26
96
N/A
Pipe
46
116
126
432
1004
229
199
170
92
2368
Not Identified
00
13
22
79
19
103
18
13
285
Total
116
13
126
454
1083
248
302
188
105
2653
3. Burst/Ruptured - for failures resulting from internal pressure,
presumably exceeding the capability of the component
4. Broken - for which the cause of the break could not otherwise be
determined.
In addition to the component/cause relationships, there were five components for which 20
or more events were reported. They were:
1. Valves - with 24 events reported, the most frequently reported cause
was burst/ruptured (four).
2. Fittings - with 24 events reported, the most frequently reported causes
were sand cut (eight) and leaking (six).
3. Couplings - with 23 events reported, the most frequently reported
causes were parted line or union (ten) and leaking (nine).
4. Check Valves - with 22 events reported, the most frequently
reported causes were failed, opened (seven), leaking (five), and
nonfunctioning (three).
-------
5. Gasket - with 20 events reported, the most frequently reported cause
was burst/ruptured (nine).
The remaining spill events assignable to pipe equipment were widely dispersed among the
remaining components and causes, with no significant quantity of events reported against
any single component/cause combination.
The second element on the equipment ranking list for the Gathering/Distribution System
is pumps. The 88 events for this element were reviewed to determine the components and
causes associated with spills reported against it. From this review, the predominant
component/cause combinations were found to be:
1. Nipple - with nine events reported, the reported causes were broken
(six), and road machinery (three).
2. Gland, Packing - with 11 events reported, the reported causes were
leaking (five), broken (two), and four without pattern.
3. Pipe - with eight events reported, the reported causes were broken
(three), corrosion (two), and three without pattern.
4. Hose - all eight events were attributed to vandalism.
5. Seals - with five events reported, the reported causes were burst/
ruptured (three) and leaking (two).
6. Gasket - all four events were attributed to burst/ruptured.
7. Fasteners - all three events were attributed to broken.
The remaining 40 events reported against pump equipment were without pattern.
Tanks accounted for 78 events and is third ranked. The 78 event reports were screened
and the components and causes were identified. These component/cause combinations
which were reported as occurring more than once were:
1. Component Not Identified - with 36 events reported, the causes were overflowed
(seven); operation incorrect (five); leaking (five); burst/ruptured (four);
E-42
-------
corroded (four): hole (three); high wind, temperature, vandalism, corroded
internally and externally (two each); and six single occurrence events.
2. Check Valve - all four events were reported as failed, open.
3. Tank Shell - with five events reported, the causes were corroded internally
(two), and burst/ruptured, hole, and leaking (one each).
4. Pipe - with five events reported, the causes were corroded (two), corroded
externally (two), and hole (one).
5. Valve - with four events reported, the causes were left closed (two), left
open (one), and operated incorrectly (one).
The remaining reported spill events charged to tanks were single occurrence events and
formed no pattern.
The total number of spill events attributed to gravity equipment was 73, making this
element the fourth-ranked item. A review of these spill records disclosed that pipe
accounted for 66 of the events. The causes associated with these 66 events and the num-
ber of events reported for each cause is shown in Table E-38.
Table E-38. Pipe Component (Gravity Gathering) Spill Events
by Cause
Cause
Corroded Externally
Corroded
Corroded Internally
Road Machinery
Burst
Farm Machinery
Leaking
Temperature
Third Party (Other)
Total
Number of
Spill Events
31
11
10
6
3
2
1
1
1
66
E-43
-------
The seven remaining events were single occurrences of component/cause combinations
involving five components and six causes.
The fifth ranked equipment element is tank associated equipment, for which 57 events
were reported. A review of these disclosed that the component/cause combinations
reported as occurring more than one time were:
1. Check Valve - with 23 events reported, the causes were failed opened
(14), nonfunctioning (five), and four other causes (one each).
2. Valve - with 12 events reported, the causes were failed opened (three),
nonfunctioning (three), and six other causes (one each).
3. Pipe - with nine events reported, the causes were leaking (two) and
seven other causes (one each).
4. Control - the two events reported for this component were nonfunctioning.
The 11 remaining events were single occurrences of component/cause combinations in-
volving eight components and ten causes.
Road crossing equipment was cited in 50 events. A review of the records showed that
pipe was reported in 47 events. The causes associated with these 47 events and the num-
ber of events reported for each cause is shown in Table E-39.
Table E-39. Pipe Component (Road Crossing) Spill Events by Cause
Cause
Road Machinery
Leaking
Corroded
Corroded Externally
Farm Machinery
Unknown
Maintenance Improper
Manufacturer's Defect
Total
Number of Spill Events
18
11
8
4
3
1
1
1
47
E-44
-------
E.4 ANALYSIS OF TOTAL COMPONENT SPILLS
This appendix has addressed component performance as it relates to system, subsystem,
and equipment performance. This paragraph considers the impact of component perform-
ance on total system performance. The total data bank of 8453 spill events developed for
this program contains 6791 records with component identity defined. A review of these
6791 event records disclosed that while 83 component types were identified, almost 85
percent (5719) were attributed to only eight component types. These are listed in Table
E-40 in rank order based on the total number of events and the percent of contribution to
the total. Each is discussed in the following paragraphs.
E.4.1 Pipe
The most frequently reported component category for all systems combined was pipe, with
4646 assigned events. Pipe also ranked first in the Gathering/Distribution System with
3506 assigned events and first in the Production System with 1135 assigned events. A
review of these 4646 pipe event records revealed that eight causes collectively accounted
for 3910 (84 percent) of the pipe events. Table E-41 lists these causes in rank order
based on the number of assigned events. The table also shows the number of events and
the percent of the total pipe events for each cause listed.
E.4.2 Valve
The component category that ranked second for all systems combined was valve, with 377
events assigned. Valve also ranked second in both the Gathering/Distribution System
(77 events) and the Production System (300 events). A review of the 377 valve event
records revealed that 10 causes collectively accounted for 223 (59 percent) of the valve
events. Table E-42 lists these causes in rank order based on the number of assigned
events and shows the number of events and the percent of the total events for each cause.
E.4.3 Dump
The third-ranked component category was dump valve, with 206 assigned events. All
were reported against the Production System because this component is restricted to that
system. Review of these events showed that five causes collectively accounted for 88
E-45
-------
Table E-40. Ranking of Component Spill Events for All Systems by Component
Component
Pipe
Valves
Dump Valves
Pumps
Check Valves
Hi Level Sensors
Stuffing Box
Coupling
Other
Total
Not Identified
Total - All Events
Number of
Spill
Events
4646
377
206
118
104
92
88
72
1088
6791
1662
8453
% Total
Reported
Events
54.96
4.46
2.44
1.40
1.23
1.09
1.04
0.85
12.56
80.34
19.66
100.00
% Total
Component
Events
68.41
5.55
3.03
1.74
1.53
1.35
1.30
1.06
15.79
100.00
N/A
N/A
Table E-41. Ranking of Pipe Component Spill Events for All
Systems by Cause
Cause
External Corrosion
Corrosion
Leaking
Internal Corrosion
Road Machinery
Burst/Ruptured
Hole
Broken
Other
Total
Number of
Spill Events
1445
706
653
361
227
213
162
143
736
4646
% Pipe
Events
31.10
15.26
14.06
7.77
4.89
4.58
3.49
3.01
15.84
100. 00
E-46
-------
Table E-42. Ranking of Valve Component Spill Events
for All Systems by Cause
Cause
Left Open
Leaking
Failure, Closed
Failure, Opened
Nonfunctioning
Valve Opened/Closed
Vandalism
Broken
Operation Incorrect
Livestock
Other
Total
Number of
Spill Events
37
33
31
24
24
18
17
13
13
13
154
377
% Valve
Events
9.81
8.75
8.22
6.37
6.37
4.78
4.51
3.45
3.45
3.45
40.84
100.00
percent of the dump valve events. Table E-43 lists the causes in rank order based on the
number of events and the percent of the total dump valve events for each cause.
Table E-43. Ranking of Dump Component Spill Valve Events
for All Systems by Cause
Cause
Failure, Closed
Failure, Opened
Nonfunctioning
Equipment Failure
Sand Cut
Other
Total
Number of
Spill Events
65
51
28
25
13
24
206
% Dump
Valve Events
31.55
24.76
13.59
12.14
6.31
11.65
100. 00
E-47
-------
E.4.4 Check Valve
The fifth-ranked component category was check valve, with 104 assigned events. It
ranked third in the Gathering/Distribution System, but with 36 assigned events, it was not
included in the ranking table for the Production System. Review of these events shows
that five causes accounted for 71 percent of the check valve events. Table E-44 lists the
causes in rank order based on the number of assigned events and shows the number of
events and the percent of the total events for each cause.
Table E-44. Ranking of Check Valve Component Spill Events
for All Systems by Cause
Cause
Failure, Opened
Leaking
Nonfunctioning
Failure, Closed
Burst/Ruptured
Other
Total
Number of
Spill Events
36
15
14
5
4
30
104
% Check Valve
Events
34.62
14.42
13.46
4.81
3.85
28.84
100. 00
E.4.5 Hi Level Sensor
The sixth-ranked component category was hi level sensor with 92 assigned events. It was
fifth-ranked in the Production System and no events were charged to the Gathering/
Distribution System. Review of these events shows that one cause (nonfunctioning) was
responsible for 58 or 63 percent of the events.
E.4.6 Stuff ing Box
The seventh-ranked component category was stuffing box with 88 assigned events. It
ranked sixth in the Production System with all events occurring within that system due to
application limitations. Review of these events shows that seven causes collectively
accounted for 89 percent of the events. Table E-45 lists the causes in rank order based on
E-48
-------
the number of assigned events and shows the number of events and the percent of the total
events for each cause.
Table E-45. Ranking of Stuffing Box Component Spill Events
for All Systems by Cause
Cause
Leaking
Equipment Failure
Improper Maintenance
Overpressure
Burst/Ruptured
Plugged
Worn
Other
Total
Number of
Spill Events
30
13
11
9
8
4
3
10
88
% Stuffing Box
Events
34.09
14.77
12.50
10.23
9.10
4.55
3.41
11.35
100. 00
E.4.7 Coupling
The eighth-ranked component category was coupling, with 72 assigned events. It ranked
fifth in the Gathering/Distribution System with 36 assigned events but was not included in
the ranking table for the Production System.
Review of these events revealed that seven causes collectively accounted for 61 (85 per-
cent) of the events. Table E-46 lists these causes in rank order based on the number of
assigned events and shows the number of events and the percent of the total events for
each cause.
E-49
-------
Table E-46. Hanking of Coupling Component Spill Events for
All Systems by Cause
Cause
Leaking
Line or Union Parted
Temperature
Broken
Burst/Ruptured
Assembled Improperly
Material Defect
Other
Total
Number of
Spill Events
22
18
6
4
4
4
3
11
72
% Coupling
Events
30.55
25.00
8.33
5.56
5.56
5.56
4.17
15.27
100. 00
E-50
-------
E.5 ANALYSIS OF SPILL QUANTITY
E.5.1 Overview of Spill Quantity Data
Tables D-27 through D-29 in Appendix D present spill quantity categories versus the
responsible component. The spill quantities are categorized into major, moderate, and
minor spills. A minor spill is less than 2.4 barrels (100 gallons), a moderate spill is
from 2.4 to 238 barrels (100 to 10, 000 gallons) and a major spill is 238 barrels (10, 000
gallons) or more. The distribution of total spill events by system and size of spill is
given in Table E-47.
Table E-47. Summary of Reported Spill Events by
System and Spill Category
System
Drilling
Gathering/Distribution
Production
Total
% of Total
Minor
7
70
585
662
7.8
Moderate
10
3456
2673
6139
72.6
Major
4
794
215
1013
12.0
Quantity
Not Determined
16
103
520
639
7.6
Total
37
4423
3993
8453
100.0
Table E-47 shows that the moderate category accounts for the largest number and the
minor category accounts for the smallest number. Events occurring within these spill
categories are discussed for each system in the following paragraphs.
E.5.2 Drilling System
There were 37 spill events reported against the Drilling System, representing 0.44 per-
cent of the total spills for all systems, of which 16, representing 43.2 percent of the total
Drilling System spills, could not be related to a quantity size. Table E-48 presents a
summary of the spill quantity quantification for the Drilling System.
E-51
-------
Table E-48. Summary of Drilling System Spill Events
by Spill Category
Spill Category
Minor
Moderate
Major
Not determined
Total
Number of
Spill Events
7
10
4
16
37
% of Total
18.9
27.0 .
10.8
43.3
100.0
There were four major spill events reported against the Drilling System, representing
10.8 percent of the total system spills. No trends of significance were exhibited.
There were ten moderate spill events reported against the Drilling System, representing
27 percent of the total system spills. Only one component associated with these spills
(choke) was identified.
There were seven minor spill events reported for the Drilling System, representing 18.9
percent of the total system spills. No trends were exhibited. As shown in Table E-49,
the spill events were distributed among a few components with no component having a sig-
nificant percentage of the total.
Table E-49. Drilling System, Minor Spill Events by Component
Component
Not Identified
Pipe
Rupture-Disc
Control
Total
Number of Minor
Spill Events
3
2
1
1
7
% of Total
42.8
28.6
14.3
14.3
100.0
E-52
-------
E.5.3 Production System
There were 3993 spill events reported against the Production System representing 47.2
percent of the total spills. The distribution of Production System spill events by spill
category is given in Table E-50. There were 520 spills from Production Systems whose
spill category could not be determined accounting for 13 percent of the total system spills.
Each spill category is discussed in the following paragraphs.
Table E-50. Production System Spill Events by Spill Category
Spill Category
Minor
Moderate
Major
Not determined
Total
No. of Spill Events
585
2673
215
520
3993
% of Total
14.7
66.9
5.4
13.0
100.0
There were 215 major spill events reported in the Production System representing 5.4
percent of the total system spills. Table E-51 presents the components responsible for
the majority. Of the identified components, pipe and valves were the largest contributors.
The remaining spills were distributed among several components.
Table E-51. Production System Major Spill Events by Component
Component
Not Identified
Pipe
Valve
Dump Valve
Other
Total
Number of Major
Spill Events
78
47
35
12
43
215
% of Total
36.3
21.9
16.3
5.6
19.9
100.0
E-53
-------
There were 2673 moderate spill events reported against the Production System repre-
senting 66.9 percent of the total spills. Table E-52 shows the components responsible
for the majority of the spills. The identified components responsible were pipe and
valves.
Table E-52. Production System Moderate Spill Events by Component
Component
Pipe
Not Identified
Valve
Dump Valve
Other
Total
Number of Moderate
Spill Events
920
657
218
150
728
2673
% of Total
34.4
24.6
8.2
5.6
28.2
100.0
There were 585 minor spill events reported in the Production System representing 14. 7
percent of the total. Table E-53 presents the components associated with the majority.
Of the identified components, pipe and valves account for the largest contributors.
Table E-53. Production System Minor Spill Events by Component
Component
Not Identified
Pipe
Dump Valve
Hi Level Sensor
Valve
Pressure Relief Valve
Other
Total
Number of Minor
Spill Events
178
95
54
30
24
24
180
585
% of Total
30.4
16.2
9.2
5.1
4.1
4.1
30.9
100.0
E-54
-------
E.5.4 Gathering/Distribution System
The Gathering/Distribution System had 4423 spill events reported, representing 52.3
percent of the total spills for all systems. A total of 103 spills, representing 2.3 percent
of the system total, could not be related to a quantity size. Table E-54 presents a sum-
mary of the spill quantity quantification for the Gathering/Distribution System.
Table E-54. Gathering/Distribution System Spill Events
by Spill Category
Spill Category
Minor
Moderate
Major
Not Determined
Total
Number of
Spill Events
70
3456
794
103
4423
% of Total
1.6
78.1
17.9
2.4
100.0
There were 794 major spill events reported for the Gathering/Distribution System repre-
senting 17.9 percent of the total spills. Table E-55 shows the components responsible for
the majority. Pipe had 608 events attributed to it. Valves and welds were the second and
third largest contributors. The remainder were distributed among other components.
Table E-55. Gathering/Distribution System Major Spill Events by
Component
Component
Pipe
Not Identified
Valves
Welds
Other
Total
Number of Major
Spill Events
608
70
20
17
79
794
% of Total
76.6
8.8
2.5
2.1
10.0
100.0
E-55
-------
There were 3456 moderate spill events reported in the Gathering/Distribution System
representing 78.1 percent of the total spills. Table E-56 shows the components respon-
sible for the largest number. Pipe was involved most with 2787, or 80.6 percent of the
system total. Valves were next. The three types of valves accounted for 148 spills or
4.3 percent of the total.
Table E-56. Gathering/Distribution System Moderate Spill Events
by Component
Component
Pipe
Not Identified
Check Valves
Valves
Gate Valve
Other
Total
Number of Moderate
Spill Events
2787
302
66
54
28
219
3456
% of Total
80.6
8.7
1.9
1.6
0.8
6.4
100.0
In the Gathering/Distribution System there were 70 minor spill events reported repre-
senting 1.6 percent of the total. Table E-57 shows those components responsible for the
largest number of spills. Pipe was responsible for 47 spills, or 67 percent. Those
spills for which the data sources did not specify a responsible component are classified
as "not identified. " The remaining spills are distributed among the other components.
E-56
-------
Table E-57. Gathering/Distribution System Minor Spill Events
by Component
Component
Pipe
Not Identified
Pump
Other
Total
Number of Minor
Spill Events
47
8
4
11
70
% of Total
67.1
11.4
5.7
15.8
100.0
E.5.5 Analysis of Major Spill Events
The major spill category was investigated to determine if any unique components or
causes could be found that specifically caused major spills. As a first step, Table D-25,
in Appendix D, was generated. This table shows equipment versus cause for each major
spill. There were 1013 major spills reported. Table E-58 presents a ranking of the
major causes and equipments associated with the major spills. This table contains 640 of
the 1013 spill events ranked according to the equipment having the most incidents of spills.
In this table, 109 spill events were reported due to a third party. Those attributed to
road machinery (71) and farm machinery (14) are shown separately. All other reported
third party causes account for the remaining 24 events.
Referring to Table E-58, pipe was associated with 496 major spills, representing 48.9
percent. Corrosion was the most prevalent cause of these pipe failures, accounting for
260 spill events or 52.4 percent of the pipeline spills. The second most frequent equip-
ment associated with spills was tanks, with 41 major spills, representing 4.1 percent of
the total. The most frequent cause of tank equipment spills was hole, 41.5 percent. The
gathering pipeline subsystem accounted for 3.9 percent of the total spills. The major
cause for spills relative to this equipment was corrosion, accounting for 31 spills or 77.5
percent of the total gathering pipeline subsystem major spills.
E-57
-------
Table E-58. Ranking of Reported Component Major Spill Events by Cause
and Equipment
w
en
oo
Cause
Externally Corroded
Road Machinery
Internally Corroded
Corroded
Burst/ Ruptured/ Split
Material Defective
Defective Weld
Third Party (Other)
Leaking
Parted Line or Union
Farm Machinery
Broken
Plugged
Hole
Overflowed
High wind
Equipment Failure
Failure Opened
Total
Code
16
96
17
15
14
20
39
90
26
33
93
12
34
25
31
81
10
22
11100
Pipe
162
71
54
44
40
30
27
24
16
14
14
496
15000
Gathering
Pipeline
Subsystem
11
5
15
5
4
40
11500
Road
Crossing
8
5
13
13100
Pump
4
3
3
10
36100
Tanks
8
8
17
4
4
41
33100
Flow Line
Equipment
5
8
4
6
5
28
35100
Heater
Treater
3
6
3
12
Total
173
79
59
64
62
30
27
24
36
18
14
9
3
25
4
4
6
3
640
-------
E.6 ANALYSIS OF REPORTED SPILL CAUSES
The causes tabulated from the data were divided into the following six categories.
1. Unknown - data did not reveal the cause of the event.
2. Equipment Failure - event was a result of hardware failure.
3. Operator/Maintenance Error - event was caused by an equipment
operator or maintenance personnel.
4. Engineering Error - events caused by faulty or improper design,
application, or layout of the equipment.
5. Natural Causes - events attributed to environmental conditions.
6. Third Party - outside sources.
Table E-59 shows the number of spill events per system for each cause category. Equip-
ment failure represented the largest percentage (81.1 percent) of spill events for all
systems. Of the 3709 spill events for the Gathering/Distribution System attributable to
equipment failure, 2511 (67.7 percent) were caused by corrosion. Causes such as burst,
hole, and leaking, any of which could be a result of corrosion, accounted for 715 events.
Of the 408 third party events, 254 (62.3 percent) resulted from road machinery. In the
Gathering/Distribution System, equipment failure represented 83.9 percent and third
party 9.2 percent. Of the 3993 events for the Production System, 3138 (78.6 percent)
were reported as equipment failure. The most frequent cause was leaking, with 766
(24.4 percent). The combination of corrosion, hole, and burst accounted for 669 (21.3
percent). A large percentage of leaking, hole, and burst causes may have been the result
of corrosion.
E-59
-------
Table E-59. Spill Events by Cause Category and System
w
d>
o
Cause Category
Unknown
Equipment Failure
Operator/Maintenance
Error
Engineering Error
Natural Causes
Third Party
Code
01-04
10-39-A1
40-55
60-64
70-83
90-99
TOTAL
Drilling
System
10
10
6
2
9
0
37
%of
System
27.03
27.03
16.22
5.40
24.32
100.0
Production
System
261
3138
293
12
161
128
3993
%of
System
6.50
78.67
7.30
0.30
4.03
3.20
100.0
Gathering/
Distribution
System
194
3709
71
2
39
408
4423
%of
System
4.39
83.86
1.60
0.05
0.88
9.22
100.0
Totals
465
6857
370
16
209
536
8453
%of
Totals
5.50
81.12
4.38
0.19
2.47
6.34
100.0
-------
APPENDIX F
FAILURE MODES AND EFFECTS ANALYSIS (FMEA)
-------
TABLE OF CONTENTS
Appendix F - Failure Modes and Effects Analysis (FMEA) F-l
F. 1 Introductory Summary F-l
F.2 FMEA Methodology and Selection Criteria F-l
F. 3 Fault Tree Analysis Approach F-2
F.4 System Level FTA F-6
F.5 Drilling System FTA F-9
F.6 Production System FTA F-19
F.7 Gathering/Distribution System FTA F-21
F.8 References F-21
F-ii
-------
LIST OF ILLUSTRATIONS
Figure
F-l System Level Fault Tree Diagram for the Various Crude Oil
Systems F-7/F-8
F-2 Fault Tree Diagram for the Development of a Kick F-ll
F-3 Fault Tree Diagram for Nondetection of a Kick F-12
F-4 Fault Tree Diagram for Inadequate Well Killing Control F-13/F-14
F-5 Fault Tree Diagram for the Gathering Subsystem F-23/F-24
F-6 Fault Tree Diagram for the Treater Subsystem F-25/F-26
F-7 Fault Tree Diagram for the Local Storage Subsystem F-27/F-28
F-8 Fault Tree Diagram for the Separation Subsystem F-29/F-30
F-9 Fault Tree Diagram for the Safety Subsystem F-31/F-32
LIST OF TABLES
Table
F-l Definitions of Symbols Used in Fault Tree Diagrams F-4
F-2 Blowout Preventer and Associated Hydraulic Closing Equip-
ment FMEA F-15/F-16
F-3 Activity Performed and Type of Flow Occurring During
Blowouts F-l 7
F-4 Operational Function Performed at Time of Blowout on 40 Wells
Versus Location F-18
F-5 Type of Flow During Blowouts on 38 Wells Versus Location. . « F-18
F-6 Leaks Detected on Initial Working Pressure Tests of 1000 Ram-
Type Blowout Preventer Stacks and Manifolding After Field
Installation F-18
F-iii
-------
APPENDIX F
FAILURE MODES AND EFFECTS ANALYSIS (FMEA)
F.I INTRODUCTORY SUMMARY
These analyses are important to the spill prevention program described in this report
since they provide an analytical framework to cover any specific facility and to allow
consistent comparative analysis. They draw upon the configuration information obtained
during the field surveys (see Appendix A) and the oil spill data tabulated in Appendix D
and analyzed in Appendix E and Volume I . The importance of FMEA to this study, in
addition to aiding the development of the basic systems description in Appendix B, is in
the derivation of spill prevention guidelines presented in Volume I . This appendix is
included to substantiate the spill prevention guidelines of Volume I, and to provide a
theoretical basis for stimulating new applications of these powerful methods to the pre-
vention of oil spills.
F.2 FMEA METHODOLOGY AND SELECTION CRITERIA
In this study, failure is defined to be a spillage of crude oil or condensate. The principal
objective of FMEA is to identify all failure modes of a system and, through analysis,
determine which modes are significant causes of failure (as defined). Two basic approaches
may be used: the first, or classical approach, is an inductive process that starts at the
lowest level (part) of the system and evaluates the effect of each part failure mode on the
next and successively higher levels of the system until the effect on system performance
is established. The second, or hazard analysis approach, is a deductive process that
starts with defined hazards at the system level and examines possible failure conditions
at the next and progressively lower levels of the system until the failure modes that allow
the hazard to exist are determined. The latter approach is used in this study.
The term "hazard" is defined here as a condition (or state) which contributes to the
occurrence of a failure. For this study, the hazards to be analyzed are limited only to
those which contribute to oil or condensate spillage. Hazards which contribute
F-l
-------
to personnel injury or death, equipment or property damage, or loss of product are not
addressed by this study unless they also contribute to oil or condensate spillage.
The Hazards Analysis is performed using the methodology of Fault Tree Analysis (FTA).
Advantages of the FTA approach include the following:
The FTA approach specifically accommodates only those elements contributing
to the particular oil spill under study. Failures that do not contribute to an
oil spill are not included.
The documentation on parts, components, and equipments used in the
petroleum systems studied does not readily lend itself to an inductive analysis
from the lowest levels to the succeedingly higher levels.
The "top down" approach readily identifies human and externally induced
failure modes which can result in an oil spill.
In this study, the FTA has been developed to assist in establishing the cause and effect
relationship between system oil spills and lower system element failure modes. The
analyses have had significant value in identifying items which are potentially spill
vulnerable, an essential, preparatory step in deriving the spill prevention guidelines
presented in Volume I .
F. 3 FAULT TREE ANALYSIS APPROACH
A total FTA methodology may be approached through six basic steps. Steps 1 through 4
have been developed for immediate implementation. Steps 5 and 6 require additional
data elements and analysis before they can be implemented. Preliminary concepts of
these steps have been considered and the initial content of each step follows:
1. Step 1; Identify and define equipment associated with the facility (system)
being analyzed. Volume I presents a generalized configuration based on
functional categorization of the equipments. The specific equipment
identification will be derived from the technical data package.
F-2
-------
2. Step 2; Develop functional flow diagrams for the facility being analyzed,
with progressively detailed diagrams at lower tier levels. This will provide
an understanding of the functional operation of the facility and associated
subsystems. The diagrams presented in Appendix A are examples of sim-
plified functional flow diagrams of facilities visited. Similar, but more
detailed, diagrams will be included in, or could be constructed from, the
technical data package provided.
3. Step 3; Develop fault tree diagrams for potential occurrence of spill events
for each crude oil system addressed in the study through analysis of the
functional flow diagrams supplemented by analysis of specific equipment
and components in suppliers' catalogs. These diagrams are presented in
the following paragraphs. The symbols for understanding the fault tree
diagrams are defined in Table F-l. They are standard digital logic symbols
that relate the causative elements to the events of interest.
4. Step 4; Refine fault tree diagrams in accordance with additional causative
elements that result from analysis of the spill data in Appendix E.
5. Step 5; Develop equations describing the fault tree diagrams through applica-
tion of probability theory. The probabilistic equations required for the various
logic steps in the diagrams are presented in the following paragraphs.
The probability, P(A), that a specific hazard will occur as the result of
one or more causative malfunctions or fault events (B.) occurring
(EITHER-OR situation) is:
n
P(A) = 1 - 7T Q(B.)
where:
n
7T Q(B.) = Q(B1) x Q(B2) x ..... x Q(Bn>
i=l
F-3
-------
Table F-l. Definitions of Symbols Used in Fault Tree Diagrams
Logic Symbol
Definition
o
Output
Input
Output
Input
A
O
O
An event, usually a malfunction, that results from one or
a combination of other events and is describable in func-
tional terms. Examples are blowouts, kicks, and other
generally described occurrences.
A basic event, or lowest identifiable condition or fault.
Examples are pore pressures, valve cutout, or valve left
open.
EITHER-OR, a situation whereby an output will exist if
any or all of the input events are presented. An example is
a relay valve will fail if EITHER there is a valve stem seal
leak OR the valve spring is hung up OR both occur.
AND, the coexistence of all input events are required to
produce the output event.
Transfer symbol - connecting to a more detailed diagram.
CONDITIONAL that another event has occurred or that the
named circumstances exist at the time of the event of
interest. For example, a high level sensor failure can only
result in an overflow on the condition that another failure
has occurred.
The CONDITIONAL event of interest.
Specific activity involved.
F-4
-------
and P(A) is the probability of occurrence of the specific hazard event of
interest, Q(B.) is the probability that the causative malfunction or fault
(B.) will not occur and equals 1 - P(B.), P(B.) is the probability that
the causative malfunction or fault (B.) will occur, and n is the number of
fault conditions that contribute to a specific hazard.
The probability, P(A), that a specific hazard event will occur as the
result of all causative malfunctions or faults occurring (AND situation):
n
P(A) = 7T P(B.)
The probability that a hazard will occur upon the condition that another
stimulating event has occurred (CONDITIONAL situation):
P(A) = P(B.) P(A|B.)
The equation is read as follows:
The probability that event A will occur is equal to the probability
that the events B. will occur times the probability that event A
will occur on the condition that B. has already occurred.
6. Step 6; Determination of a Spillage Impact Factor (SIF) is desirable to
modify, or weight, the impact of the probability of malfunction which defines
how often a spill occurs (Step 5) by injecting consideration of the average
quantity of crude oil a specific failure can be expected to spill. Thereby,
a more complete estimate can be made with respect to the overall impact of
a specific failure. In this manner, comparisons can be derived that indicate
whether a particular component that fails frequently, but spills small amounts
of oil, has more or less impact than another component that fails less fre-
quently but spills more oil. Throughout this study this modifier will be called
a Spillage Impact Factor (SIF). To derive the SIF, the average quantity of oil
spillage for each component failure was determined. This value was modified
F-5
-------
by a multiplier based on the highest average spill component. The SIF scale
was therefore made to range from 1 to 1000.
Steps 1 through 4 had utility in deriving the spill prevention guidelines presented in
Volume II. Steps 5 and 6 have future utility for:
1. Ranking the overall spill impact of various malfunction events after multiply-
ing the SIF of the malfunction event of interest by the probability that the
malfunction will occur, i.e., a criticality ranking.
2. Comparing configurations at various levels to allow tradeoff considerations
to attain an optimum criticality-ranked configuration.
Achieving the benefits of ranking and tradeoff through use of Steps 5 and 6 will require:
1. Developing data to derive statistical failure distributions and calculate
numerical values of terms used by probability equations in Step 5.
2. Developing equations for using and calculating SIFs at various logic steps in
the fault tree diagrams.
F.4 SYSTEM LEVEL FTA
The system level fault tree diagram, Figure F-l, shows the ability of this analytical
method to address any system, and depicts the top tier for crude oil systems. It is a
generalized presentation relating any crude oil spillage event to one of the major func-
tional phases of crude oil processes. The system level diagram is readily expandable
to include product spillage from other system functions within the petroleum life cycle.
Detailed fault tree diagrams for system major functional phases in this study and the
phase description are presented in later paragraphs. Note that the Emergency Safety
Shutdown in Production and Gathering/Distribution Systems can contribute to a spill
only if an associated subsystem has previously failed. The Production subsystems
identified for more detailed FTA were chosen because they are more frequent contri-
butors to oil spillage, as indicated in Volume I . The resulting conclusions drawn from
these subsystems are translatable to the Gathering/Distribution System.
F-6
-------
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F.5 DRILLING SYSTEM FT A
The most significant oil spillage event that can occur during the drilling phase of the
crude oil process is a blowout. The fault tree diagrams for the components of a potential
blowout event are presented in Figures F-2 through F-4. A study of these diagrams and
the blowout event portion of the system level fault tree diagram (Figure F-l) identifies
the branches and, ultimately, the roots of the fault tree. These roots represent the
conditions, activities, and failure modes that, collectively or individually, are pre-
requisite to a blowout. The four main branches of causative conditions and activities
relative to a blowout are (1) the occurrence of a kick (i.e., the unexpected flow of
formation fluid into the well bore), (2) not detecting that the kick had occurred, (3)
improperly killing the well, or (4) an act of God phenomena preventing proper well con-
trol action from being taken. In other words, these categories address failure to dominate
reservoir pressure, failure to recognize that the domination of the reservoir pressure
had been lost, or failure to recapture domination over the reservoir pressure. Eventually,
as shown in Figures F-2 through F-4, the roots of the tree are reached; that is, the
detailed level is attained which allows consideration of improvement in activities and
equipments that may alleviate the potential of a blowout.
The ultimate roots in Figures F-l through F-4 indicate that causative events (such as
acts of God, weak formations, abnormal pressures, the formation characteristics con-
ducive to developing a kick) cannot be eliminated. However, their resulting effects can
be alleviated by careful planning, prudent operations, and adequate equipment. Areas
which are candidates for improvement include 16 geological/engineering elements, 21
operational elements, and 17 general equipment elements. Three of the geological/
engineering elements supply assistance through procedures and training to improve
operating personnel skills in maintaining pressure control. It becomes evident that
the human element presents a significant factor in blowout prevention.
Table F-2 presents a qualitative example of an FMEA performed on selected equipments.
The cause and effect relationships can be established at successively lower levels and
FMEAs performed at component and part levels. If appropriate data are obtained, FMEAs
F-9
-------
measurable in terms of probability of failure can be performed at system, subsystem,
equipment, component, and even part level. However, adequate quantities of appropriate
data will, at best, be difficult to obtain.
The data obtained did not contain sufficient information for the determination of blowout-
associated failure modes. As indicated in Table D-19, in Appendix D, of the 37 reported
crude oil spillage events that occurred during the drilling function, only eight were
identifiable as to cause. The time frame during which these blowouts occurred is esti-
mated to be several years. It is not known how many other blowouts occurred and were
not reported. However, this number could not be large. During recent years, drilling
rig activity has averaged over one thousand, and there are also several hundred work-
over rigs still active.
The 37 reported spillage events were not all associated with blowouts. Consequently, the
impact of the various failure modes shown in the FTA upon blowouts could not be quantified
from these data. However, useful information was obtained through a selective literature
review (References 1, 2, and 3), and assistance from a Petroleum Engineering Consultant
possessing considerable drilling expertise. Another publication (Reference 4) was of
particular value in assessing the relative contribution of various drilling operations to
the occurrence of blowouts. An abbreviated table from Reference 4, supplemented with
data obtained during the present study from eight additional blowouts, is presented in
Table F-3. These data permitted a tabulation (Table F-4) of activity being performed,
by location, at the time of blowout. This tabulation indicates that 92.5 percent of the
blowout events considered occurred during tripping or drilling. The same data also
permitted a tabulation (Table F-5) of the type of fluid involved in the blowout. As shown
by well location, gas flow accounted for more than half of the blowouts considered.
Limited information on the results of pressure testing of ram-type blowout preventers
was also obtained and is presented in Table F-6. As indicated by the initial tests in the
table, of the 1000 preventer stacks and manifolding that were pressure tested on initial
installation in the field, 194 leaks were detected at the five areas listed. Thus, maintain-
ing a pressure seal is a problem on blowout preventers even prior to withstanding the
F-10
-------
J L
DRILLING
IMPROPM
GEOLOGICAL/
ENGINEERING
ANALYSIS AND PLANS
1
1
IMPROPER
EXECUTION OF
PROGRAMS
f
DRILLING } |
X
1
EQUIPMENT
INDUCED
/-
L*
INADEQUATE
MUD PUMP AND
CONDITIONING
EQUIPMENT
REQUIREMENTS
Figure F-2. Fault Tree Diagram for the Development of a Kick
(Drilling and Completion Operations)
-------
NON-
DETECTION
OF KICK
L-
1
INADEQUATE
ENGINEERING
REQUIREMENTS
>
OPERATOR
ERROR
1
ACCESSARY
EQUIPMENT
MALFUNCTION
to
INSTRUMENTA-
TION AND
ALARM
REQUIREMENTS
KICK DETECTJON
TRAINING AND
POLICY
UNDETECTED
CIRCULATING
PRESS. DECR OR
PUMP SPEED I NCR
UNDETECTED
PIT GAIN
UNDETECTED
FLOW RATE
INCREASE
FLOW LINE
SENSOR
UNDETECTED
FLOWLINE MUD
WEIGHT
DECREASE
MUD
WEIGHER
UNDETECTED
DRILLING RATE
CHANGE OR
DRILLING BKEAK
Figure F-3.
Fault Tree Diagram for Nondetection of a Kick
(Drilling and Completion Operations)
-------
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DIGITALLY
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Table F-3. Activity Performed and Type of Flow Occurring During Blowouts
Location
Maracaibo
Ventura County, California
Kern County, California
Kern County, California
Kern County, California
Kern County, California
Kern County, California
Cook Inlet
Cook Inlet
Cook Inlet
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Off-shore Louisiana
Texas
Texas
Texas
Texas
Ector County, Texas
Andrews County, Texas
Crockett County, Texas
Mississippi
Louisiana
Louisiana
Louisiana
Louisiana
West Coast
West Coast
Wyoming
Duchesne County, Utah
Duchesne County, Utah
Alberta, Canada
Alberta, Canada
Well Type
Development
Development
Wildcat
Development
Development
Development
Wildcat
Wildcat
Wildcat
Exploratory
Development
Development
Development
Development
Wildcat
Extension
Development
Development
Wildcat
Extension
Extension
Wildcat
Development
Wildcat
Development
-
-
-
Wildcat
Development
Development
Development
Development
Development
Development
Wildcat
-
-
~
Type of Flow
Gas/Saltwater
Gas/Oil
Gas/Oil
Gas
Gas
Gas
Gas
Saltwater
Gas
Gas/Oil
Gas
Saltwater
Gas
Saltwater
Gas
Gas/Saltwater
Saltwater
Saltwater
Saltwater
Gas
Gas
Gas
Gas
Gas
Gas
Oil/Saltwater
Oil/Gas
Oil/Gas
Oil
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Oil
Oil
Operation at
Time of Incident
Coming out of Hole
Displacing Mud with
Oil
Coming out of Hole
Coming out of Hole
Coming out of Hole
Coming out of Hole
Circulating
Drilling
Circulating
Drilling
Drilling
Drilling
Drilling
Resumed Drilling
after Freeing Pipe
Drilling
Drilling
Drilling
Drilling
Shutdown
Drilling
Tripping
Coming out of Hole
Coming out of Hole
Drilling
Drilling
Going into Hole
Freeing Tubing
Tripping
Drilling
Coming out of Hole
Coming out of Hole
Circulating after Trip
Coming out of Hole
Coming out of Hole,
Circulating
Coming out of Hole
after DST
Going into Hole
Coming out of Hole
Drilling
DST
Drilling Blind
F-17
-------
Table F-4. Operational Function Performed at Time of
Blowout on 40 Wells Versus Location
Activity Performed
Drilling
Coming Out Of Hole
Going Into Hole
Circulating or Drilling
After Freeing Pipe
Other
Total
Offshore La.
9
1
10
s
"S
1
6
1
1
8
Louisiana
3
1
4
Texas
2
4
1
1
8
1
0
2
1
3
t-<
O
3
2
1
1
7
I
16
15
2
4
3
40
1
8
40.0
37.5
5.0
10.0
7.5
100.0
Table F-5. Type of Flow During Blowouts on 38 Wells Versus Location
Type of Flow
Oil
Gas
Saltwater
Combination
Total
i
£
o
s
4
5
1
10
m
O
8
6
2
8
*
W
^t
DO
3
4
4
(O
o>
5
3
8
0)
c^
s
3
1
1
1
3
S
0
3
1
1
5
i *
o
H
3
21
6
8
38
«
0
H.
o
7.9
55.3
15.8
21.0
100.0
Table F-6. Leaks Detected on Initial Working Pressure Tests of 1000 Ram-
Type Blowout Preventer Stacks and Manifolding After Field Installation
Area of Leak
Number Of Leaks
BOP Ram Connector Rods Seal
BOP Ram Seal
BOP Bonnet Or Doors
Manifold Valves
BOP/Spool Flanges
36
14
40
42
62
F-18
-------
severe environments during drilling operations and severe pressures during kick killing
operations. This severity is substantiated by three occurrences of cutting out of equip-
ment during the blowouts addressed in Table F-3.
Considering the potential seriousness of any blowout, each event and activity in the logic
diagrams is assumed to be of substantial importance. Of most importance, however,
are the events that allow early kick detection, since the earlier a kick is detected, the
better the chance of preventing the potential blowout event.
The failure causes for blowout during drilling operations are present during completion
operations. Therefore, to avoid duplication of effort, the completion operation has not
been subjected to FMEA in this study. Figures F-2 through F-4 and Table F-2 are
applicable for completion operations through exercise of judgment and elimination of
causes clearly limited only to drilling operations.
F. 6 PRODUCTION SYSTEM FTA
The Production System subsystem functions are configuration dependent; e.g., they are
dependent upon the number and types of separators, and the manner in which they are
piped into the system. It was determined through field survey trips and discussions
with various people in the petroleum industry that typical production configurations are
nonexistent. Therefore, the subsystem fault tree diagrams were derived by studying
one type of equipment used in each subsystem, determining root causes for oil spillage
from each equipment studied, and assigning the causes, with universal descriptors
where possible, to any other applicable equipment used in the subsystem. In this
manner, the diagram can be changed to describe the FTA of any equipment that may be
used in a particular subsystem by using selective judgment.
The subsystems addressed were chosen after the data analysis indicated that they were
the most frequent contributors to oil spillage. The well, wellhead, custody transfer,
and water disposal subsystems were excluded from FTA because they did not appear to
be principal sources of oil spillage. However, troublesome components in these sub-
systems, such as wellhead chokes and stuffing boxes, are addressed in Volume I . As
F-19
-------
a result of these considerations, the fault tree diagrams for the remaining subsystems
are presented in Figures F-5 through F-9.
Considering that the major equipment in the local storage, treater, and separation sub-
systems are containment vessels with various associated equipments, the indication of
oil spillage at these subsystems can be described as either overflow/overpressure or
leak. The root causes of the subsystem level effects of overflow/overpressure and leak
can be grouped into the general cause categories of either design-induced causes, equip-
ment malfunction causes, operating/maintenance (O/M) causes, or outside party/event
causes. Hereafter in this study, O/M causes are combined with outside party/event
causes to group all human operating and third party causes, actions of livestock, and
natural causes. Relative to the fault tree diagrams, overflow/overpressure is defined
as spillage from the vessel through existing connections other than those intended for oil
passage. Leak is defined as spillage through a breach of the vessel or associated equip-
ment shell, fitting, gasket, or other unintended breaks. Design-induced causes are those
that basically result from insufficient or inadequate considerations during planning and
development of the production process for the oil field or oil wells involved. O/M or
outside party/event causes result from O/M actions (or lack thereof), actions by third
parties, or natural causes (such as high wind, hurricanes, or lightning).
The gathering subsystem (Figure F-5) addresses flowlines and manifolds with associated
valving. Metering, chokes, pumps, and power are not included. Metering is generally
associated with the custody transfer subsystem, chokes with the wellhead subsystem
and pumps and power with the local storage subsystem.
The equipment used as the basis of the local storage subsystem (Figure F-6) was a heater
treater; however, with selective consideration, most of the structure is applicable to
chemical-electric and electric treaters, skimmers, and gun barrels, all of which are
defined as treater subsystem equipment, with minimal change to the diagram.
F-20
-------
The equipment used as the basis of the local storage subsystem (Figure F-7) are a
welded tank with pump, swingline assembly, valving, fire arrester, automatic float
gauge, and an equalization line to another tank. The same structure applies to a bolted
tank with the same associated equipment, to tanks with less associated equipment (by
selectively deleting various causes), or to sump tanks which are defined as local
storage equipment.
The separation subsystem (Figure F-8) is based on a separator; however, the same
diagram is applicable to scrubbers.
The safety shutdown subsystem (Figure F-9) addresses the potential causes of component
malfunction of a gas pressure-operated safety shutdown system. The system consists of
a surface-controlled subsurface safety valve, a surface safety valve actuator, a three-way
pressure relay valve, and a monitoring pilot with sensor. Appendix J provides additional
information on safety shutdown devices based on USGS inspection data of Gulf OCS facilities.
F.7 GATHERING/DISTRIBUTION SYSTEM FTA
The Gathering/Distribution System, consisting of pipeline, storage, gathering, pumping,
and emergency safety subsystems, was not addressed by a separate FTA. This decision
was made because data analysis showed that 73 percent of the Gathering/Distribution
System spills were attributed to pipe in the pipeline subsystem and 20 percent were
attributable to the gathering subsystem (see Table E-35, Appendix E). Consequently,
the FTA on the gathering subsystem in the Production System, Figure F-5, is translat-
able to address these major spill areas in the Gathering/Distribution System; the local
storage subsystem in the Production System, Figure F-7, is translatable to the storage
subsystem in the Gathering/Distribution System. As a result, duplicate effort and fault
tree diagrams have been avoided.
F.8 REFERENCES
1. W.C. Coins, "Blowout Prevention, Practical Drilling Technology, Volume 1,"
1969, Gulf Publishing Company.
2. BillRehm, "Pressure Control in Drilling," 1969, 1970, The Oil and Gas
Journal. The Petroleum Publishing Company.
F-21
-------
3. "Lessons in Rotary Drilling, September 1971, Unit III - Lesson 3, Blowout
Prevention (Revised),1' Petroleum Extension Service, The University of Texas
in cooperation with American Association of Oilwell Drilling Contractors.
4. John L. Kennedy, "Losing Control While Drilling: a 32-Well Look at Causes
and Results," pp 121-126, September 20, 1971, The Oil and Gas Journal.
F-22
-------
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APPENDIX G
CONSIDERATIONS OF HAZARDOUS ENVIRONMENT
ON PETROLEUM SYSTEMS
-------
TABLE OF CONTENTS
Appendix G - Considerations of Hazardous Natural Environment on Petroleum
Systems G-l
G. 1 Introductory Summary G-l
G. 2 Discussion of Individual Natural Hazards G-l
G. 2.1 Hurricanes G-3
G. 2.2 Earthquakes G-4
G. 2.3 Tsunamis G-21
G. 2.4 Waves and Currents G-22
G. 2.5 Ice G-24
G. 2. 6 Tornadoes G-25
G. 3 References G-25
Attachment 1 to Appendix G - Earthquake Damage to Petroleum Structures G-29
G-ii
-------
LIST OF ILLUSTRATIONS
Figure Page
G-l Geographic Distribution of Natural Hazards G-2
G-2 Illustrations of Wave Forces Acting on Petroleum Systems G-5
G-3 Primary Path of Major Hurricanes G-5
G-4 Seismic Zones of the United States G-6
G-5 Earthquake Damage to Petroleum Systems G-10
G-6 Illustrations of the Earthquake Ground Motion Hazard G-12
G-7 Observed Response Spectra, San Fernando Earthquake (1971) G-13
G-8 Locations of Major California Oil and Gas Fields in Relation to Active
Faults G-15
G-9 Seismic Zone Map, Alaska G-16
G-10 Estimated Response Spectra, Alaska Earthquake (1964) G-18
G-ll Generalized Structural Map of Alaska Showing Proposed Pipeline and
Major Oil and Gas Fields G-19
G-12 Generalized Oil and Gas Field Locations, Cook Inlet Area G-20
G-13 Schematic Current Flow Around a Pipe G-23
LIST OF TABLES
Table Page
G-l Reported Oil Spills Caused by Recent Hurricanes G-3
G-2 Earthquakes Which Have Caused $1 Million or More Damage in the
United States G-8
G-3 Expectation of Earthquakes in California (150,000 mi2) G-9
G-4 Percent Probability of Acceleration at a Location in California G-9
G-iii
-------
APPENDIX G
CONSIDERATIONS OF HAZARDOUS NATURAL ENVIRONMENT
ON PETROLEUM SYSTEMS
G. 1 INTRODUCTORY SUMMARY
The spill prevention program described in this report must consider the catastrophic
results of natural environmental hazards. Oil spillage may occur from several different
sources. In the United States, 200,000 miles of pipeline carry more than a billion tons
of oil and gas annually. The pipelines cross waterways and reservoirs and are subject
to cracks, punctures, corrosion, arid other causes of leakage. Offshore oil and gas
exploration and production, blowout of wells, and dumping of drilling muds and oil-soaked
wastes are significant potential oil spill sources. Other sources include unavoidable
accidents and actions of the hazardous natural environment, such as storms, ice, tsunamis,
and earthquakes. This appendix provides a guideline and basic information about environ-
mental hazards and their effect on petroleum systems.
Petroleum industry systems are exposed to many natural hazards (see Figure G-l). The
industry is especially affected by. hurricanes, earthquakes, and tsunamis because much
of its operations and systems are located along the Gulf and Pacific Coasts and in southern
Alaska. Because of the catastrophic nature of most natural hazards and the limited time
for which petroleum spill records have been kept, an accurate record of past oil spill in-
cidents caused by natural hazards is not available. Table G-l lists the spill record ob-
tained in this survey. Although this information is incomplete, the objective is to describe
the characteristics of various natural hazards and, based on available published data,
augment the spill record to the maximum extent possible. Each natural hazard will be
treated individually, and its emphasis will vary according to its state-of-knowledge.
G.2 DISCUSSION OF INDIVIDUAL NATURAL HAZARDS
The following paragraphs describe the characteristics of individual natural hazards and
the documented (and inferred) effects on petroleum systems.
G-l
-------
EARTHQUAKES
o MINOR
MODERATE
MAJOR
TORNADO DISASTERS
FREQUENT
^ OCCASIONAL
INFREQUENT
WINTER STORM DISASTERS
HURRICANE DISASTERS
TSUNAMI DISASTERS
Figure G-l. Geographic Distribution of Natural Hazards
-------
Table G-l. Reported Oil Spills Caused by Recent Hurricanes
Stor.ni
Camille
Camille
Camille
Camille
Camille
Camille
Celia
Celia
Fern
Fern
Edith
Edith
Edith
Edith
Date
August, 1969
August, 1969
August, 1969
August, 1969
August, 1969
August, 1969
August, 1970
August. 1970
September, 1971
September, 1971
September, 1971
September, 1971
September, 1971
September, 1971
Location of Spill
Plaquemines Par. , La.
Plaquemines Par. , La.
Plaquemines Par. , La.
Plaquemines Par. , La.
Plaquemines Par. , La.
Plaquemines Par. , La.
San Patricio Co. , Texas
San Patricio Co. , Texas
Refugio Co. , Texas
Plaquemines Par. , La.
San Patricio Co. , Texas
San Patricio Co. , Texas
St. Mary Par. , La.
St. Mary Par. , La.
Losses
(Undetermined)
1000-5000 bbls.
10, 000 bbls.
1000-5000 bbls.
5000-10,000 bbls.
10,000 bbls.
223, 183 bbls. *
$47,000**
100-240 bbls.
2. 6-10 bbls.
240-500 bbls.
240-500 bbls.
2. 6-10 bbls.
500-1000 bbls.
*Company reported crude oil burned in a fire caused by Hurricane Celia.
**Company reported that Hurricane Celia blew top off of tank, causing fire.
G.2.1 Hurricanes
Each year hurricanes threaten petroleum systems on the Gulf and Atlantic coasts. In
the Louisiana Gulf Coast area alone, approximately 1120 platforms and other structures,
3942 holes with 6415 oil and gas completions, and approximately 2700 miles of pipeline
serving 29 receiving onshore stations are exposed and vulnerable to the environmental
extremes generated by a hurricane (see Figure G-2). Although the petroleum industry
G-3
-------
has recognized thts problem and spent millions of dollars to attenuate the impact, poten-
tial oil spill problems continue to exist.
A typical design storm is one that is expected to occur about once every hundred years.
About 95 percent of the time the sea conditions are expected to be incapable of producing
a wave causing more than one fourth the design load. In the 1960s, four 100-year
frequency storms hit the Gulf Coast area causing widespread damage estimated at $500
million (World Oil, October 1969). Hurricanes Caria (1961), Hilda (1964), Betsy (1965),
and Camille (1969), and others (Figure G-3) will long be remembered. Hurricanes
Hilda and Betsy destroyed 22 offshore structures and severely damaged 10 others (Blum-
berg and Strader, 1969). Hurricane Camille, called by the United States Weather Bureau
the most powerful storm to strike the United States since 1890, battered the Mississippi
Gulf coast, but its damage was only about half as severe as that of Betsy. In every case,
the petroleum systems hit hardest were offshore platforms, barges, rigs, storage tanks,
and transmission facilities. However, through careful planning, every evacuation, and
shut-in of offshore facilities due to early warning systems, oil spills have been kept to
a minimum. Recent storms (e. g., Edith and Fern, 1971), have caused relatively little
oil industry damage and few spills. Celia, in 1970, was responsible for several oil
storage tank fires. The implementation of early warning systems, the development of
storm safety chokes, and the application of design knowledge gained from instrument
data on wind and wave forces have contributed to a reduced number of spills and less
damage from recent storms.
G.2.2 Earthquakes
An earthquake can alter the environment in a catastrophic manner. Every State is
vulnerable to and has felt the effects of earthquakes (see Figure G-4). Most of the
nation's seismic activity is centered along the Pacific Coast and in Nevada. The East
Coast, by contrast, is relatively inactive seismicly but has nevertheless experienced
noteworthy earthquake damage.
The San Francisco earthquake of April 18, 1906, which touched off fires that nearly
razed the city and took an estimated 700 lives, was the most catastrophic earthquake
G-4
-------
3
_
..-:
_;-
LU
i
-
CONSTRUCTION PERIOD
DRILLING PERIOD->4-
-PRODUCTION PERIOD-
TIME
,-SEVERE WINTER STORM
1 OR SMALL HURRICANE
-LARGE HURRICANE
TIME
Figure G-2. Illustrations of Wave Forces Acting on Petroleum Systems
AUDREY *
JUNE 1957 ° f BERTHA
ESTHER^// AU
SEPT. 1957 II
HILDA -^FLOSSY
OCT. 1969 SEPT. 1956
ELLA
SEPT. 1958
Figure G-3. Primary Path of Major Hurricanes
G-5
-------
Q
(Map released in 1969 by ESSA/USC & GS)
ZONED-NO DAMAGE
ZONE 1 -MINOR DAMAGE: DISTANT EARTHQUAKES MAY CAUSE DAMAGE
TO STRUCTURES WITH FUNDAMENTAL PERIODS GREATER THAN
1.0 SECONDS: CORRESPONDS TO INTENSITIES V AND VI OF THE
M. Mr SCALE.
ZONE 2 -MODERATE DAMAGE: CORRESPONDS TO INTENSITY VII AND HIGHER
OFTHEM.M.* SCALE
ZONE 3-MAJOR DAMAGE: CORRESPONDS TO INTENSITY VIII AND HIGHER
OF THEM. M.* SCALE
100 200 300 400 300
KILOMETERS
MODIFIED MERCALLI INTENSITY SCALE OF 1931 - A QUALITATIVE SCALE OF DAMAGE INTENSITY AT THE EARTH'S
SURFACE FOR EVALUATING REPORTED HUMAN OBSERVATIONS
Figure G-4. Seismic Zones of the United States
-------
yet recorded in the United States. In the east, the greatest shock was experienced in
Charleston, South Carolina, on August 31, 1886, resulting in 60 deaths and $23 million
in property damage. The San Fernando Valley, California, earthquake of February 9,
1971, killed 65 persons and caused property damage estimated at $500 million. Table
G-2 lists earthquakes which have caused $1 million or more damage in the United States.
The earthquake disaster potential in California is now at least 10 times greater than it
was at the time of the 1906 San Francisco earthquake (see Earthquake Engineering
Research, 1969). Table G-3 lists the expectation of earthquakes in California. It shows
that some 40 earthquakes having magnitudes between 6.25 and 6.75 on the Richter Scale
(including the magnitude of 6.4 assigned for the San Fernando 1971 earthquake) can be
expected to occur in any given 100-year period in California. The percent probability of
ground acceleration (a damage diagnostic) at a given location in California is given in
Table G-4.
From 1865, to 1965, 77 earthquakes occurred in or near California and caused damage
to California hydraulic systems. Forty cases of damage to petroleum structures were
also reported (see Department of Water Resources, State of California). Figure G-5,
which is keyed to Attachment 1 to this appendix, shows damage locations. Highlights of
three specific damage cases will be described below for emphasis.
The San Andreas fault zone ruptured over an observed distance of about 180 miles during
the great San Francisco quake (magnitude 8.3) of April 18, 1906. Gas pipe as far as 150
miles from the epicenter were ruptured. The roofs of six large oil tanks at a pumping
station located 156 miles from the epicenter collapsed, resulting in considerable oil spill-
age. An oil pipeline located some 120 miles from the epicenter was twisted, broken, and
pulled apart in more than 20 places (Lawson, 1908).
In July, 1952, the Kern County earthquake occurred in the southern San Joaquin Valley
with a magnitude of 7.7. Effects of this large shock included open fractures in the valley
floor, broken pipelines, oil spills caused by surface waves splashing oil from numerous
sumps throughout the area, collapse of oil and butane storage tanks, kinked tubing, and
collapsed casing. Extensive damage to the Paloma Cycling Plant, southwest of Bakers-
field, resulted from a combination of the earthquake, fire, and an explosion, and amounted
to an estimated $1. 8 million.
G-7
-------
Table G-2. Earthquakes Which Have Caused $1 Million or More Damage in the
United States. (Source: National Earthquake Information Center.)
Year
Locality
Damage
1886
1898
1906
1925
1933
1935
1940
1941
1944
1946
1949
1949
1951
1952
1954
1954
1955
1955
1957
1957
1959
1960
1961
1964
1965
1969
1971
Charleston, S. C. $23,000,000
Mare Island, California 1,400,000
San Francisco, California 24,000,000
Fire Loss 350,000,000
Santa Barbara, California 8,000,000
Long Beach, California 40,000,000
Helena, Montana 4,000,000
Imperial Valley, California 6,000,000
Torrance-Gardena, California 1,000,000
Cornwall, Canada-Massena, N. Y. 2,000,000
Hawaii (Tsunami damage "from
earthquake in Aleutians) 25,000,000
Puget Sound, Washington 25,000,000
Terminal Island, California
(oil wells only) 9,000, 000
Terminal Island, California
(oil wells only) 3,000,000
Kern County, California 60,000,000
Eureka-Arcata, California 2,100,000
Wilkes-Barre, Pennsylvania 1,000,000
Terminal Island, California
(oil wells only) 3,000,000
Oakland-Walnut Creek, California 1,000,000
Hawaii (Tsunami damage from
earthquake in Aleutians) 3,000,000
San Francisco, California 1,000,000
Hebgen Lake, Montana (damage to
timber and roads) 11,000,000
Hawaii and west coast of United
States (Tsunami damage from
earthquake off the cost of Chile) 25,500,000
Terminal Island, California
(oil wells only) 4,500,000
Alaska and west coast of United States
(Tsunami damage from earthquake
near Anchorage, Alaska; includes
earthquake damage in Alaska) 500,000,000
Puget Sound, Washington 12, 500,000
Santa Rosa, California 6,000,000
San Fernando, California 500,000,000
G-8
-------
Table G-3. Expectation of Earthquakes in California (150,000 mi )
(from Housner, 1970)
Magnitude
4.75 - 5.25
5.25 - 5.75
5.75 - 6.25
6.25 - 6.75
6.75 - 7.25
7.25 - 7.75
7.75 - 8.25
8.25 - 8.75
Number Per 100 Years
250
140
78
40
19
7.6
2.1
0.6
Table G-4. Percent Probability of Acceleration at a Location in
California (from Housner, 1970)
Acceleration
<%g)
5
10
15
20
25
30
35
In Period of Years
10
65
37
19
10
5
2.5
1.0
25
92
70
41
43
12
5.5
2.5
50
99
88
65
40
22
10
4.4
100
99
98
87
63
37
19
8.7
G-9
-------
_0_ R E G ON
000,
DAMAGE SITE AND CASE HISTORY NUMBER
TRINITY/ SHASTA
230. 237. 266k*250VM I*
Figure G-5. Earthquake Damage to Petroleum Systems
G-10
-------
The San Fernando earthquake of February 9, 1971, was extremely destructive in spite
of its moderate 6.4 magnitude. Accelerations in excess of 1 g were recorded in the
epicentral region. Oil and gas installations in the Los Angeles area escaped severe
damage (Moran, 1972). Pauley Petroleum's Newhall refinery, located about 10 miles
northwest of the epicenter of the quake, was forced to shut down temporarily because of
damage to storage tanks and pipelines. Other refineries in the Los Angeles area appar-
ently suffered only minor damage. Most producing oil fields in the area shut down
immediately after the earthquake and returned to production a few days later. Severe
damage was sustained by gas lines in a 4-square mile area in the northeast corner of
San Fernando Valley. Eight supply lines were sufficiently damaged to necessitate
removal from service.
During the San Fernando earthquake an unprecedented amount of strong ground motion
data was obtained. These data will enable significant engineering studies correlating
earthquake ground motion, petroleum system structural response, and damage to be
made for the first time. This work is now in progress.
Figure G-6 illustrates schematically the important elements of the earthquake ground
motion hazard to petroleum systems. The ground motion from an earthquake has a
complex relationship with the magnitude and focal depth of the energy release, the epi-
central distance along which the body (P and S) and surface (Rayleigh and Love) waves
travel, and the physical characteristics of the soil profile at the site of the petroleum
system of interest. The response spectrum (e.g., pseudorelative velocity or PSRV)
characterizes the spectral composition of the earthquake ground motion. Response
spectra have an additional value in that they can be related to structural response and
damage.
Figure G-7 illustrates representative 5-percent damped PSRV spectra derived from
strong motion accelerographs recording the San Fernando earthquake. These spectra
represent a distance range of about 85 miles and peak horizontal acceleration loads
ranging from 0. 01 to 1.2 g. Various petroleum fields are listed along the margin of
Figure G-7 relative to the response spectrum depicting the ground motion exposure
G-ll
-------
O
H
10
ELEMENT
SOURCE
TRANSMISSION PATH
RECORDING SITE
KEY VARIABLES
MAGNITUDE
FOCAL DEPTH
EPICENTRAL DISTANCE
ALLUVIAL THICKNESS
IMPEDANCE MISMATCH
BLDGF
RESPSTORY STORY
>7 STORIES
> 5TC
PERIOD
RESPONSE
SPECTRUM
RECORDING SITE
Figure G-6. Illustrations of the Earthquake Ground Motion Hazard
-------
u
SPECTRA OBSERVED FROM SAN FERNANDO EARTHQUAKE, 1971
100.0
- 10.0
..
.
.
0.01
0.1 1.0
PERIOD IN SECONDS
EPICENTRAL DISTANCES TO SELECTED
PETROLEUM INSTALLATIONS
Qr MILES
PLACERITA
NEWHALL
WAYSIDE CANYON
CASTAIC HILLS
BEVERLY HILLS
_ FILLMORE
SATICOY
WILMINGTON
BREAOLINDA
TEJON
WEST MONTALYO
- MOUNTAIN VIEW
EDISON
BUENA VISTA
SUMMERLAND OFFSHORE
- MIDWAY - SUNSET
MOUNT PASO
McKITTRICK
L MOLINO OFFSHORE
BELRIDGE
Figure G-7. Observed Response Spectra, San Fernando Earthquake (1971)
-------
they received. Figure G-8 depicts a map view of the major California petroleum fields
relative to the major fault systems (potential sources of future earthquakes) and the
epicenter of the San Fernando earthquake. An earthquake of magnitude 6.4 can reasonably
be expected to occur about once every 4 years in California and on practically any one of
the fault systems shown (Allen, 1972). Furthermore, many of the fault systems will
sustain larger magnitude quakes. The time interval between two successive magnitude
7 quakes anywhere on the San Andreas fault is estimated as 15 years and the recurrence
interval for two magnitude 8 quakes is 100 years (Wallace, 1970). A destructive earth-
quake, occurring nearer to California petroleum systems could have significant environ-
mental impact.
The entire Alaska region is in an active earthquake zone (see Figure G-9). The Alaskan
earthquake of March 27, 1964, with Richter magnitude 8. 5, is the most recent and pro-
found example of the havoc that an earthquake can cause in this region. The epicenter
was about 75 miles east of Anchorage. The quake occurred along a fault rupture about
400 miles in length, released about twice as much energy as the 1906 San Francisco
earthquake, and was felt over an area of almost 500,000 square miles. In addition,
some 7500 aftershocks occurred along a belt 480 miles long and 150 miles wide. Some
125 people died as a consequence of the earthquake and aftershock sequence, and total
estimated damage of about $500 million (recently updated) was sustained. Loss of life
and property would have been far greater if Alaska had been more densely populated.
Prior to the San Fernando 1971 earthquake, the Alaskan earthquake was the best docu-
mented and most thoroughly studied earthquake in history. Detailed engineering studies
of the damage were made (see Steinbrugge, 1967, for details). Among other facts, these
studies showed that oil storage tanks were vulnerable to earthquake forces. Seven oil
company tanks in Anchorage collapsed, with one releasing 750,000 gallons of aviation
fluid (Housner, 1970). Oil storage tanks at Valdez, Seward, Kodiak, and Whittier
ruptured and burned (National Academy of Sciences, 1969). Landslides broke gas distri-
bution lines in at least 120 places but only a single leak developed in the 95-mile line
that transmits natural gas from fields near Kenai to Anchorage (Eckel, 1967). Damage
G-14
-------
SAN FRANCISCO
EXPLANATION
GENERALIZED OUTLINE OF MAJOR
OIL AND GAS ACTIVITY
1. GASFIELDS(UNDIFFERENTIATED)
2. SAN JOAQUIN BASIN
3. CUYAMA VALLEY BASIN
4. SANTA MARIA BASIN
5. VENTURA BASIN
6. LOS ANGELES BASIN
RECENTLY ACTIVE FAULTS AND RELATIVE
MOVEMENT (PAST SEVERAL THOUSAND YRS.)
FAULTS AND ASSOC. FRACTURE AREAS WITH
MOVEMENT DURING HISTORICAL
EARTHQUAKES
INFERRED SUBMARINE FAULTS
MONTEREY
SAN LUIS OBISPO
-. SANTA YNE_Z,
SANTA BARBARA
S
Adapted liom data published by U.S.G.S.
Figure G-8. Locations of Major California Oil and Gas Fields
in Relation to Active Faults
G-15
-------
BARROW
SEISMIC PROBABILITY
ZONE
0
1
2
3
DAMAGE
NONE
MINOR
MODERATE
MAJOR
BERING SEA X
Figure G-9. Seismic Zone Map, Alaska
G-16
-------
to the 120-mile-long gas distribution system within Anchorage amounted to nearly $1
million. It is estimated that the approximately 5 minutes of shaking caused by the
earthquake in Anchorage aged the gas transmission lines by about 30 years.
No strong motion seismic instrument network was in operation in Alaska at the time of
the earthquake, therefore no records of the strong ground motion are available. Observers
in Anchorage have provided information suggesting that the maximum horizontal accelera-
tions in Anchorage were about 16 percent g and of very long duration (4 to 7 minutes,
according to Steinbrugge, 1970). Clough (1966) suggested that the Taft (1952) response
spectrum is representative (except for durations) of the ground motions sustained in
Anchorage. Figure G-10 shows the estimated 5-percent damped horizontal ground motion
response spectra for the Alaska earthquake at epicentral distances corresponding to
Valdez, Anchorage, Kenai, and Kodiak. Petroleum systems are listed in the right
margin of Figure G-10 relative to the response spectrum representing their estimated
ground motion exposures.
It is of some interest to relate the estimated Alaskan 1964 earthquake response spectra
to the petroleum systems at Cook Inlet and to the proposed Alyeska pipeline. Figures
G-ll and G-12, respectively, depict the proposed pipeline route superimposed on the
structural map of the State and the major oil and gas fields in the Cook Inlet area. The '
proposed 800-mile pipeline project will carry oil from Prudhoe Bay on the Arctic Ocean
to the port of Valdez on the Gulf of Alaska. The proposed pipeline crosses three major
mountain systems (Chugach, Alaska, and Brooks), over 350 streams and rivers, and
several areas known to be earthquake-prone.
The earthquake problems in California and Alaska are important considerations of potential
oil spills from offshore petroleum structures and systems. Ground motions caused by an
earthquake transmit motions to a structural system through its foundation. This acceler-
ated movement from an at-rest position causes the structural system to be loaded by
inertial forces which are a function of its flexibility, mass, and damping characteristics.
Offshore structures are typically constructed of large diameter tubes interconnected by
underwater bracing and held in position by piling driven into the bottom. Such structures,
G-17
-------
00
ESTIMATED RESPONSE SPECTRA
(SCALED FROMTAFT, CALIFORNIA EARTHQUAKE. 1952)
EPICENTRAL DISTANCES TO
SELECTED PETROLEUM INSTALLATIONS
Or MILES
PROPOSED PIPELINE TERMINAL
(VALDEZ)
SWANSON RIVER OIL
COOK INLET GAS
GRANITE POINT OIL
MGS OIL.KENAI GAS
TRADING BAY OIL
W. FORELAND GAS
PRUDHOE BAY
AND |
NORTH SLOPE ACTIVITY |
650 - 750 MILES
PERIOD IN SECONDS
Figure G-10. Estimated Response Spectra, Alaska Earthquake (1964)
-------
o
H^
to
KNOWN OR INFERRED FAULTS
THRUST FAULTS-SAWTEETH
ON UPPER PLATE
////////// SOUTH LIMIT OF NUMEROUS
THRUST FAULTS IN
N. ALASKA
OIL AND GAS FIELDS
EPICENTER, EARTHQUAKE MAR 27,
1964
_ i_, »-« PROPOSED ALYESKA PIPELINE
NOTE: GEOLOGY ADAPTED FROM
GRANTZ, 1966
APE SIMPSON OIL
^J
PT. BARROW GAS
RUDEHOE8AY OIL
ALDE2
'SWANSbTfTRfVER OIL
SEE FIGURE FOR
COOK INLET DETAIL
PACIFIC
B E R I
Figure G-ll. Generalized Structural Map of Alaska Showing Proposed Pipeline
and Major Oil and Gas Fields
-------
COOK INLET GAS FIELD
NtCHOLAI CREEK GAS FIELD / V
GRANITE POINT OIL FIELD
TRADING BAY OIL FIELD X''.''.''.''.''.'.'.''-'''
McARTHUR RIVER OIL FIELD
BIRCH HILL GAS FIELD
MIDDLE
GROUND
SHOAL
OIL
VW. FORELANDGAS FIELD (
RIVER OIL FIELD
BEAVER CREEK GAS FIELD
WEST FORK GAS FIELD
Figure G-12. Generalized Oil and Gas Field Locations, Cook Inlet Area
(See Figure G-ll for location)
G-20
-------
if standing in air and oscillating, would experience resonant strain amplitudes limited
only by structural damping. Offshore structures, however, are partially immersed in
water with foundation piles driven into saturated soil. As the submerged parts of a struc-
ture are forces to follow the earthquake motions, some water in the vicinity of the struc-
tural members will also move. This water, which associates itself with the structure
during acceleration, increases the virtual mass of the members and thus increases the
local inertia! loads. As a direct consequence of this added mass effect, the mode shapes
of a structure in water are changed and the natural frequencies of the structure are
lowered. Another difficult and poorly understood problem is the behavior of saturated
foundation soils and piling during an earthquake. Sea floor slides also represent potential
hazards to petroleum systems. The performance of petroleum structural systems under
strong earthquake loads has not yet been fully tested or studied. As a result, engineer-
ing data are insufficient to reduce uncertainty and to validate present design techniques
and theories.
G.2.3 Tsunamis
Tsunamis are destructive water waves with periods in the range of 5 to 60 minutes or
longer. They are created by a number of mechanisms (Wiegel, 1970). The Pacific
Ocean basin, a zone of high seismicity, is subject to more tsunamis than any other region.
These waves attain destructive proportions in the immediate vicinity of their origin and
travel across an ocean at speeds as great as 600 miles an hour and reaching heights of
50 feet or more by the time they reach shore.
Well-established early warning systems have been developed to signal the development
and occurrence of a tsunami. Many tsunamis have been measured and catalogued; however,
few have caused extensive spill damage to petroleum systems, primarily because of the
early warning systems.
One of the most devastating tsunamis was generated by theAlaskan earthquake of March
27, 1964, (Grantz, et al, 1964; Wilson and Torum, 1968). It caused major damage in
a number of Alaskan coastal towns. The tsunami propagated across the eastern Pacific
Ocean and subsequently caused damage estimated at $11 million at Cresent City,
G-21
-------
California (Griffin, et al, 1964). Oil storage tanks in Crescent City caught fire as a
consequence of the tsunami. The catastrophic nature of this natural hazard requires
continuing study to minimize potential future environmental impact.
Dr. William Pecora, formerly Director of U. S. Geological Survey and Undersecretary
of Interior, estimated that there are 50 billion barrels of oil (five times the minimum
estimate given for the North Slope) near and under the Gulf of Alaska in the Cordova area
(see article, Gulf of Alaska - Richer than the North Slope?, Oceanology, pp. 11-12,
February, 1972). Although these estimated figures are potential and no oil has actually
been discovered, there is a critical need to continue monitoring tsunamis and the result-
ant effects of petroleum systems in order to prepare an adequate data base for future use.
G.2.4 Waves and Currents
In the search for and the development of petroleum reserves, many new and difficult
engineering problems have been encountered. This is particularly true for Cook Inlet,
Alaska, a relatively large body of water approximately 170 miles long by 45 miles wide.
Cook Inlet has one of the largest tidal ranges in the world (from 20 to 30 feet) occasionally
even creating a "tidal bore." In addition, the tidal currents are relatively swift (4 to 7
knots). Storms frequently generate 10- to 15-foot waves and winds reach 80 miles per
hour. Air temperatures range from 80° F to -40° F. Water temperatures range from a
high of about 55° F to a low of 29° F. These environmental conditions significantly affect
the design and operation of petroleum systems (platforms, submarine pipelines, production
facilities, and tanker loading terminals) in Cook Inlet.
Currents of the magnitude experienced in upper Cook Inlet have had a particularly signifi-
cant effect on pipelines installed on the Inlet floor (Goepfert, 1969). The environmental
forces acting on a submerged pipeline are considerably different for buried and unburied
systems. It is generally acknowledged that the hazards encountered by a pipeline laid
across the bottom are much more serious than those encountered by a buried pipeline
(Ralston and Herbich, 1969). Burial of the pipeline generally affords the best protection
from the effects of waves and currents. However, burying pipelines is expensive and,
in some locations, difficult or impossible because of rocky bottom conditions or the
G-22
-------
presence of reefs. Even when burial is feasible, scour, flutter, and differential buoyancy
along sections of the pipeline often create severe mechanical problems.
Several pipeline failures have been experienced in Cook Inlet (Goepfert, 1969). These
appear to correlate with the peak tidal range period and to be the direct result of flutter.
Flutter occurs when the frequency of vortices shedding in the wake of a stationary body
in a moving current field approaches the natural frequency of the body. The shedding of
vortices must occur in a regular frequency on alternate sides of the body to establish
alternating forces which induce motion perpendicular to the current direction (see Figure
G-13). It is the alternating vertical force which causes flutter. As the frequency of the
alternating forces approaches the natural frequency of the suspended pipe segment,
deflections rapidly and violently reach destructive proportions.
DOES NOT CAUSE FLUTTER
CAUSES FLUTTER
Figure G-13. Schematic Current Flow Around a Pipe
Blumberg (1964 a, b, c, d, e, f) has reported numerous failures involving drilling,
production, and pipeline facilities in the Gulf Coast during the hurricanes of 1961, 1964,
and 1965. He reported that losses sustained off the Louisiana Coast along during 1964
G-23
-------
and 1965 exceeded $200 million. Significant ocean wave and current effects were noted
to extend to depths of at least 240 feet, a finding which has a bearing on the design of deep
water petroleum systems.
G.2. 5 Ice
The establishment and operation of petroleum systems in geographic areas susceptible
to ice and/or heavy winter storms presents a potential oil spill problem. Cook Inlet,
Alaska, is one example of an area subject to the hazardous ice environment. Petroleum
systems are exposed to three types of fresh water or salt water ice environment, all of
which are potentially hazardous:
1. The open ocean or coast where ice fields and bergs are encountered.
2. Tidal bays, inlets, or estuaries where ice may be in the form of bergs
or fields.
3. A harbor fed by a major fresh water source where ice may be formed locally
or fresh water ice may be discharged from a river in the form of fboes or ice
jams.
Offshore structures will not normally be subject to static ice forces of the type that can
develop in sheltered bodies of water because the action of waves and tides will usually
prevent large ice sheets from adhering directly to a petroleum system structure. It is
not uncommon, however, for ice to build up on a structural member in the tidal zone,
causing dangerous vertical forces such as uplift at high tide and dead load at low tide.
Floating ice moving with a wind or current will often be rafted into multiple thicknesses
as a result of impacts and wind-driven packing. Forces on maritime structures from
moving ice may act from directions other than those of the principal current directions.
Thus, a petroleum system structure must be designed to resist ice forces from all
directions. Moving ice sheets present a serious problem since they can cause forced
vibrations of the structure. These forced vibrations are a function of the ice thickness,
rate of loading and ice temperature (Peyton, 1968; Geminder, 1968; Matlock, et al,
1969). Dynamic forces resulting from ice force oscillations are transmitted through
G-24
-------
steel platform structures to derricks, booms, walkways, and other ancillary equipment
located on the platform. These structures are not damped by ice and water and thus may
oscillate at destructive amplitudes.
The extremes faced by petroleum systems in an environment subject to ice conditions
pose severe operational problems as well as potential environmental hazards. Additional
experience and data are needed to develop and ensure sound oil pollution control systems
for operations in this environment. Data from instrumented petroleum systems (such as
the Union Oil Company monopod platform in Cook Inlet) are needed to validate and improve
design techniques.
G.2.6 Tornadoes
Tornadoes occur principally in the central United States, from northern Texas to Wisconsin.
Approximately 650 tornadoes struck the United States in 1970. These storms strike
suddenly and cause widespread devastation in a somewhat unpredictable manner. The
Lubbock Storm of May 11, 1970, (Thompson et al, 1970) illustrates this type of natural
hazard. Within 1 hour, the storm killed 26 people, injured more than 2000, and damaged
or destroyed property to the extent of $135 million. It directly affected approximately
one-fourth of the city. Few, if any, oil spills have been directly attributable to tornadoes,
although the potential to cause damage to storage tanks is great.
G.3 REFERENCES
Allen, C. R., 1972, Seismological Investigations; National Conference on Earthquake
Engineering, Los Angeles, California, February 7-9, 1972.
Beal, C. H., 1915, The Earthquake at Los Alamos, Santa Barbara County, California,
January 11, 1915, Bulletin of the Seismological Society of America, Vol. 5,
No. 1, March 1915.
Blumberg, R., 1964a, Hurricane Winds, Waves, and Currents Test Marine Pipeline
Design; Part I, "Climate, Sun Spot Activity and Hurricane Path Probability,"
Pipeline Industry, Vol. 20, no. 6, pp. 42-45, June.
Blumberg, R., 1964b, Hurricane Winds, Waves, and Currents Test Marine Pipeline
Design; Part 2, "Carla Gave First Significant Data on a Major Hurricane in
18 years of Gulf of Mexico Oil and Gas Operations," Pipeline Industry, vol. 21,
no. 1, p. 70-74, July.
G-25
-------
Blumberg, R., 1964c, Hurricane Winds, Waves, and Currents Test Marine Pipeline
Design; Part 3, "Most Costly Damages Sustained by Off-shore Operators during
Hurricane Carla resulted from Movement or Failure of Underwater Pipelines,"
Pipeline Industry, vol. 21, no. 3, p. 34-39, August.
Blumberg, R., 1964d, Hurricane Winds, Waves, and Currents Test Marine Pipeline
Design; part 4, "Damage Reports of Pipeline and Related Facilities in Bay
Marchard, South Timbalier, South Pelto, Ship Shoal, Eugene Island, and
South Marsh Island Areas." Pipeline Industry, vol. 21, no. 3, p. 67-72,
September.
Blumberg, R., 1964e, Hurricane Winds, Waves, Currents Test Marine Pipeline
Design; Part 5; "Reports of Details on Carla's Effects...," Pipeline Industry.
vol. 21, no. 4, pp. 35-41, October.
Blumberg, R., 1964f, Hurricane Winds, Waves, and Currents Test Marine Pipeline
Design; Part 6; "Reports of Hilda...," Pipeline Industry, vol. 21, no. 5,
pp. 85-88, November.
Blumberg, R., and N. R. Strader H, 1969, Dynamic Analyses of Off-shore Structure;
Preprint, 1969, Off-shore Technology Conference, vol. 1, Paper no. OTC 1009.
Clough, R. W., and K. L. Bemuska, 1966, FHA Study of Seismic Design Criteria
for High-rise Buildings; U. S. Department of Housing Report HUD TS-3,
National Technical Information Service Report PB 202960, p. 3-13.
Department of Water Resources, State of California, Earthquake Damage to Hydraulic
Structures in California; Bulletin No 116-3, June 1967.
Earthquake Engineering Research, 1969; A report to the National Science Foundation,
prepared by the Committee on Earthquake Engineering Research, G. W. Housner,
Chairman, PB 188636.
Eckart, N. A., 1937, "Development of San Francisco's Water Supply to Care for
Emergencies;" Bulletin of the Seismological Society of America, vol. 27,
no. 3, July 1937.
Eckel, E. B., 1967, Effects of the Earthquake of March 27, 1964, on Air & Water
Transport, Communications, and Utilities Systems in South Central Alaska;
U. S. G.S. Professional Paper 545-B, U.S. Geological Survey, 1967.
Geminder, R., 1968, Ice Force Measurement, Proceedings of the Third Annual
Off-shore Exploration Conference, New Orleans, Louisiana.
Goepfert, B. L., 1969, An Engineering Challenge-Cook Inlet, Alaska; Preprint
1969 Off-shore Technology Conference, vol. 1, paper no. OTC 1048.
G-26
-------
Grantz, Arthur, G. Plafker, and Reuben Kachadoorian, 1964, Alaska's Good
Friday Earthquake, March 27, 1964; U. S. Geological Survey Circular 491.
Griffin, W., et. al., 1964, Crescent City's Dark Disaster; Crescent City, California.
Holden, Edward S., 1898, A Catalogue of Earthquakes on the Pacific Coast, 1769 to
1897; Smithsonian Miscellaneous Collections, No. 1087, Smithsonian Institution.
Housner, G. W., 1970, Strong Ground Motion; in Earthquake Engineering, Robert L.
Wiegel, Coord, ed., Prentice-Hall, Inc., Englewood Cliffs, N. J., Chapter 4.
Johnson, R. L., 1955, Earthquake Damage to Oilfields and to the Paloma Cycling
Plant in the San Joaquin Valley; Earthquakes in Kern County, California,
During 1952. California Division of Mines, Bulletin 171. San Francisco.
Lawson, A. C., et. al, 1908, The California Earthquake of April 18, 1906, Report
of the State Earthquakes Investigation Commission, Publication No. 87. (All
references in the cases are to volume 1 unless otherwise noted.) Carnegie
Institution of Washington.
Marliave, E. C., 1952, Report on Physical Effects of Arvin Earthquake of July 21, 1952,
California Division of Water Resources, Sacramento. August, 1952.
Matlock, H., William P. Dawkins, and John J. Panak, 1969, A Model for the Prediction
of Ice-Structure Interaction; Proceedings of the 1969 Off-shore Technology
Conference, Houston, Texas, vol. 1, pp. 687-694.
Moran, O., 1972, Private Communication Which is Based on a Preliminary Review of
the Joint NOAA/EERI Report of San Fernando Earthquake; Report is scheduled
for Publication in mid-1972.
National Academy of Sciences, 1969, Toward the Reduction of Earthquake Losses; The
Committee on the Alaska Earthquake, National Research Council, 1969.
Oil and Gas Journal, Oil Escapes Heavy Damage in California Quake; February 15, 1971,
p. 44.
Peyton, H. R., 1968, Designing for Sea Ice; Ocean Industry, vol. 3, no. 3, March,
pp. 40-44.
Ralston, D. O. and J. B. Herbich, 1969, The Effects of Waves and Currents on
Submerged Pipelines; Sea Grant Publication No. 301, Texas A & M University,
U. S. Department of Commerce PB 188106, March 1969.
G-27
-------
Steinbrugge, K. V., 1967, Building Damage in Anchorage; in the Prince Williams
Sound, Alaska, Earthquake of 1964, and Aftershocks; F. J. Wood, editor-in-
chief, vol. II, Part A, Engineering Seimology, C and GS Publication 10-3, 1967.
Steinbrugge, K. V., 1970, Earthquake Damage and Structural Performance in the
United States; in Earthquake Engineering, R. L. Wiegel, Coord, edit.,
Prentice-Hall, Inc., Englewood Cliffs, N. J., 1970.
Steinbrugge, K. V., and Moran, D. F., 1954, An Engineering Study of the Southern
California Earthquake of July 21, 1952, and Its Aftershocks; Bulletin of the
Seismological Society of America, vol. 44, no. 23, April 1954.
The Daily Press. "$10,000 Damage Done by Quake in Parkfield;" Paso Robles,
California, June 29, 1966.
Thompson, J. N. et. al, 1970, The Lubbock Storm of May 11, 1970; National Technical
Information Service PB 198377, National Academy of Sciences.
United States Coast and Geodetic Survey, Abstracts of Earthquake Reports for the
Pacific Coast and the Western Mountain Region; vols. 1-4, U. S. Government
Printing Office, Washington, D. C., 1929-1934.
United States Coast and Geodetic Survey, United States Earthquakes; U. S. Government
Printing Office, Washington, D. C., 1930.
University of California, Earthquake Scrapbook; Unpublished. Berkley, California.
Wallace, R. E., 1970, Earthquake Recurrence Intervals on the San Andreas Fault;
Geological Society of America Bulletin, vol. 81, no. 11, October, 1970.
Wiegel, R. L., 1970, Tsunamis; in Earthquake Engineering. R. L. Wiegel coordinating
editor, Prentiss-Hall, Inc., Englewood, New Jersey, 1970.
Wilson, B. W., and A. Torum, 1968, The Tsunami of the Alaskan Earthquake, 1964,
Engineering Evaluation, Technical Memorandum No. 25, U. S. Army Coastal
Engineering Research Center, p. 401.
Wood, Harry O., and Heck, N. H., 1966, Earthquake History of the United States,
Revised by R. A. Eppley, U. S. Department of Commerce, Environmental
Science Services Administration, Coast and Geodetic Survey, Washington.
World Oil, 1969, $100 Million Damage Caused by Gulf of Mexico Storm; October, 1969,
p. 119.
G-28
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ATTACHMENT 1 TO APPENDIX G
EARTHQUAKE DAMAGE TO PETROLEUM STRUCTURES
(Source: Department of Water Resources State of California)
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
230 San Francisco, San Santa Cruz Mtns Gas Pipes
Francisco County - October 8, 1865
50 miles from epicenter
"On the marshy lands in the vicinity of Howard and Seventh Streets,
lamp posts, water pipes, and gas pipes were broken and thrown
out of position." Holden, p. 66.
231 Gilroy, Santa Clara Monterey Bay Gas Mains
County - about 8 miles Region Earthquake
from epicenter April 24, 1890
"The gas mains were disjointed, and there was some other
damage." Townley and Allen, 1939, p. 81.
232 Santa Barbara, Santa Los Alamos Oil and Water
Barbara County, 10 mi earthquake Pipelines
from epicenter July 27, 1902
"On the property of the Western Union Oil Co., two tanks
containing 3000 barrels of oil each were destroyed. Pipes
for conducting oil and water were twisted and broken."
Townley and Allen, 1939, p. 117.
233 Briceland, Humboldt San Francisco Gas Pipes
County, 150 miles from earthquake
epicenter April 18, 1906
"The village suffered damage to the extent of $1500 due to
the breaking of chimneys, water and gas pipes, household
furniture, etc." Lawson, Vol. 1, p. 170.
G-29
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
234 Napa, Napa County San Francisco Gas Mains
33 miles from epi- earthquake
center April 18, 1906
"The damage to street gas mains at Napa was very slight, only
two leaks developing. The gas station was badly shaken up;
about 10 feet of the end wall of the brick building was thrown
down, falling on top of the boiler and breaking off the steam
pipes. The gas-holders were badly shaken up. Water was dis-
placed from the tanks, but only one guide wheel was shaken out
of place.ft Lawson, Vol. 1, p. 211.
235 Oakland, Alameda San Francisco Gas Mains
County - 34 miles earthquake
from epicenter April 18, 1906
"There were very few breaks in cast-iron gas mains. Two of
these were caused by impact of heavy debris falling from build-
ings and poles. One was on Washington Street, where heavy
blocks of sandstone fell from the third story and the roof, break-
ing the main 30 inches below the bituminous rock. Another was
at the corner of Fourteenth Street and Broadway, where a trans-
former fell from a pole, striking the center of a short car rail
and bending up both ends. A 3-inch cast iron main a short dis-
tance from this was broken at right angles. On the Twelfth
Street Dam, a cast iron pipe was broken and displaced over a
foot while the high pressure steel pipe paralleling it was prac-
tically undisturbed." Lawson, Vol. 1, p. 302.
236 Redwood City, San San Francisco Gas Tank
Mateo County - 47 miles earthquake
from the epicenter April 18, 1906
"A 20,000-foot gas-holder in a redwood tank above ground was
completely demolished by the earthquake. " Lawson, p. 254.
G-30
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Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
237 San Francisco, San San Francisco Gas Mains
Francisco County - earthquake
approximately 32 miles April 18, 1906
southeast of epicenter
"In solid ground there was very little trouble and very few
breaks. A number of the breaks noted ... as being on solid
ground were caused by the use of dynamite and other explosives,
employed in blowing down buildings.
"In the above sunken streets the city sewers, as well as other
conduits such as gas pipes, electric light conduits, etc., suffered
the same as the water pipes in that they were similarly ruptured
by the sinking and violent oscillations of the ground.
"During the three-month period from April 18 to July 18, 1906
300 breaks in the pipe system had been discovered and repaired,
276 of which were in or immediately adjoining the burnt district.
In the unburnt district, only 24 breaks have been found and
repaired." Eckart, pp. 194-195.
238 Sacramento, Sacramento San Francisco Gas Tank
County - 75 miles east earthquake
of epicenter April 18, 1906
"The damage at the gas plant was very slight. The gas holders
rocked to such an extent that considerable water was thrown out
of the tanks and the seals of the holder sections were partially
emptied, allowing gas to escape. " Lawson, p. 216.
239 Mendota, Fresno San Francisco Oil Tank
County - 156 miles earthquake
from epicenter April 18, 1906
"At an oil-pumping station 10 miles south of Mendota, there
were ten large tanks ... Of these, the roofs (unsubstantially
braced) of six caved in and much oil was thrown over the sides. "
Lawson, p. 318.
G-31
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
240 Salinas River, Monterey San Francisco Oil Pipeline
County - 120 miles from earthquake
epicenter April 18, 1906
"An oil pipe which crossed the bridge was twisted and buckled
at the south end of the bridge, and when this was repaired the
pipe was found to be shortened 7 feet. The pipeline extends from
the San Joaquin Valley to the Bay of Monterey. A few hundred
yards south of the bridge is a pumping station, at which point
some of the connections of the pipe were broken and displaced.
The direction of the shortening of the bridge span and the pipe
is roughly normal to the direction of the San Andreas Rift, on
the other side of the Gavilan Range. Mr. S. A. Guiberson,
superintendent of the line, reports that the pipe was broken in
about 20 places in the vicinity of the river, and that at some of
these breaks the pipe was pulled apart. " Lawson, Vol. 1, p. 296.
241 Harris, Santa Barbara Los Alamos Oil Pipeline
County - 15 miles from earthquake
epicenter January 11, 1915
"At Harris, the 8-inch pipeline of the Associated Oil Company
from the Santa Maria field to Gaviota was broken and about
1200 barrels of oil escaped. " Beal, March 1915, p. 19.
242 Santa Rita, Santa Los Alamos Oil Pipeline
Barbara County - 10 earthquake
miles from epicenter January 11, 1915
"The same pipe (as in Case 241 above) was broken in two places
near Santa Rita where the line runs southeast; in one of these
breaks the pipe was apparently pulled apart at the union, and the
southeast section pushed to the southwest and both sections
pushed past each other, so that when found one overlapped on the
other four or five inches. " Beal, March 1915, p. 19.
G-32
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
243 San Jacinto, Riverside San Jacinto Gas Mains
County - 3 miles from earthquake
epicenter April 21, 1918
"... within ten minutes the breaking of the gas mains made it
necessary to shut off the supply." UC, 1915, Vol. 1, p. 130.
244 Shandon and Antelope Cholame Valley Oil Pipelines
Valley, San Luis Obispo earthquake
and Kern Counties - 10 March 10, 1922
miles southeast of epi-
center
"... oil pipelines broken between Shandon and Antelope... "
Wood and Heck, 1951, p. 32.
245 Ventura, Ventura Point Arguello Oil Pipeline
County - 130 miles earthquake
from epicenter November 4, 1927
"In Ventura a pipeline was broken. " UC, 1915-1930, pp. 113-121.
246 Santa Fe Springs Whittier Oil Pipelines
Los Angeles County earthquake
15 miles from epicenter July 8, 1929
"Oil operators at Santa Fe Springs reported that two producing
oil wells in the eastern end of the field were stopped up by the
tremor. Several oil lines in the field were reported broken. "
UC, 1915-1930, pp. 170-176.
247 Signal Hill, Los Angeles Long Beach Oil Pipeline
County - 5 miles from earthquake
epicenter March 10, 1933
"Oil line broken. " USC&GS, 1933, p. 11.
248 San Pedro, Los Long Beach Gas Mains
Angeles County - 20 earthquake
miles from epicenter March 10, 1933
"Numerous leaks in gas lines." USC&GS, 1933, p. 12.
G-33
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
249 Laguna Beach, Orange Long Beach Gas Mains
County - 20 miles from earthquake
epicenter March 10, 1933
"Leaks in. ..gas mains." USC&GS, 1933, p. 12.
250 Berkeley, Alameda Berkeley Gas Pipes
County - 4 miles from earthquake
epicenter March 8, 1937
"A number of gas lines were pulled apart or snapped off in the
Cragmont Avenue and Keith Avenue section. In Berkeley and
El Cerrito... a store's window display of about $150 worth of
choice liquors was thrown through a large window " UC,
1934-1937, Clipping from Oakland Tribune. March 8, 1937.
251 Torrance-Gardena Torrance-Gardena Oil and Gas Pipes
area, Los Angeles earthquake and Oil Tanks
County - 2 miles from November 14, 1941
epicenter
"In the oil fields two tanks were demolished, two buckled badly,
and a 6-inch pipeline broke in four additional places after having
broken in one place during the October 21 earthquake. An 8-inch
natural gas pipeline burst. Fire was overted in all cases and
most of the oil was recovered. Ground cracks were found in
several cases near the broken oil line. " USC&GS, "U. S. Earth-
quakes, " 1941, p. 17.
252 Torrance-Gardena Torrance-Gardena Oil Pipeline
Los Angeles County - earthquake
0 miles from epicenter November 14, 1941
"The swaying east-west trembler... snapped oil and pipelines. In
one liquor store, 15 thousand dollars' worth of stock was thrown
to the cement floor and ruined." USC&GS, "U. S. Earthquakes, "
1941, p. 17.
G-34
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
253 San Jose, Santa Clara Mount Hamilton area Gas Main
County - 14 miles west earthquake
of epicenter October 25, 1943.
"... at San Jose...a.small gas main snapped in the Security
Building at First and San Fernando Streets." UC, 1943-48,
Clipping from San Francisco News, October 26, 1943.
254 Maricopa area, Kern Kern County Oil Pipelines
County - 2 to 4 miles earthquake
north of epicenter July 21, 1952
"Steel pipelines used on conveying petroleum were severed by land-
slides caused by the earthquake in the vicinity of Grapevine, near
Highway 99. Lateral displacement of alluvium in the area north of
Highway 166 caused breaks in other oil lines. Several breaks oc-
curred. .. (in an area about a mile north of Wheeler Bridge). Rup-
ture of lines appeared to take place at points of weakness, as all
breaks do not necessarily appear to have occurred in areas of par-
ticularly sharp movement. A cumulative compression and stretching
effect caused ruptures, especially where the lines curved. These
steel lines averaged five-sixteenths of an inch thick and ranged in
diameter from 6 to 10 inches. The line to one General Petroleum
pumping station, located about 7 miles west of Highway 99 on High-
way 166, bends gently to the north approximately 1-1/2 miles north
of the station. The pipe at the bend was separated 18 inches. One-
half mile to the north, a 4-foot section of an oil line curving gently
to the west was first buckled sharply to the west then straightened
out before breaking 6 feet further north. In the same vicinity, two
pipes on opposite sides of a road striking north-south suffered the
opposite kind of action. The line on the east side telescoped approx-
imately 36 inches, while that on the west side pulled apart approxi-
mately 55 inches. These lines were about 30 feet apart at points of
rupture..." Marliave, 1952, p. 10.
"The General Petroleum Corporation... Emidio Pipe Line Station was
probably the most severely shaken and pipe movements at this loca-
tion in excess of 5 inches were noted. The following is a summary
of pipeline breakage in the vicinity of Emidio Pipe Line Station,
with distance from Emidio:
G-35
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
254 (Cont'd)
1.375 miles east: Pulled apart, then telescoped.
1.4 miles east: Pulled apart, then telescoped.
6.75 miles west: Line pulled out of collar.
. 28 miles north: Line crinkled and ruptured.
. 72 miles north: Pulled apart.
. 76 miles north: Pulled apart, then telescoped.
1.04 miles north: Weld broke.
1.5 miles north: Pulled apart, then telescoped 42". "
Steinbrugge and Moran, 1954, p. 270.
255 Emidio, Kern County Kern County Oil Pipelines
3 miles from epicenter earthquake
July 21, 1952
"Severe damage to General Petroleum Corporation's pipelines.
Breaks occurred on 8- and 10-inch lines. One 10-inch pipe
telescoped 42 inches." USC&GS, "Abstracts," MSA-75, 1952,
p. 19.
256 Gorman, Los Angeles Kern County Gasoline Pipeline
County - 16 miles from earthquake
epicenter July 21, 1952
"... a 10-inch gasoline pipeline severed. Gasoline cascaded
down cliff." USC&GS, "Abstracts," MSA-75, 1952, p. 23.
257 Los Angeles, Los Kern County Gas Pipe
Angeles County - 80 earthquake
miles from epicenter July 21, 1952
"Sixty-eight earthquake-operated gas shutoff valves in schools of
the L. A. School District were operated. Hanging space heaters
broke gas lines in industrial installation. Excess flow valves
operated." USC&GS, "U.S. Earthquakes," 1956, p. 22.
G-36
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
258 Tajon Ranch, Kern Kern County Oil Tank
County - 10 to 15 miles earthquake
from epicenter July 21, 1952
"... one of a battery of three 1500-barrel (oil) tanks in the
Tajon Ranch area... collapsed... " Johnson, p. 222.
259 Bakersfield, Kern Kern County Butane Tanks
County - 14 miles from earthquake
epicenter July 21, 1952
"At Paloma Cycling Plant 16 miles southwest of Bakersfield, the
shock of the earthquake caused two of the large spherical butane
storage tanks to collapse, thereby rupturing lead-in lines and
releasing quantities of highly volatile material." Johnson, p. 222.
260 Newhall, Los Angeles Kern County Gas Pipeline
County - 45 miles from earthquake
epicenter July 21, 1952
"Press reported a 12-inch gas line broken near the city limits."
USC&GS, "U.S. Earthquakes," 1952, p. 22.
261 Emidio, Kern County - Wheeler Ridge Gas Pipelines
2 to 4 miles north of earthquake
epicenter January 12, 1954
"... Southern California Gas and Richfield Oil Company had...
pipeline damage... in this area. " Steinbrugge and Moran, 1954,
p. 270.
262 Ridge Route between Wheeler Ridge Gas Pipeline
Los Angeles and Taft - earthquake
25 miles from epicenter January 12, 1954
"... 12-inch gas pipeline broke. " USC&GS, 1954, p. 12.
G-37
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
263 Paloma Oil Field, Wheeler Ridge Oil Pipeline
Kern County - 16 miles earthquake
from epicenter January 12, 1954
".. .pipeline cracked at the Paloma oil field. " USC&GS, "U. S.
Earthquakes," 1954, p. 12.
264 Maricopa Flats Wheeler Ridge Gas Pipeline
Kern County - 15 miles earthquake
from epicenter January 12, 1954
"... gas pipelines damaged... " USC&GS, 1954, p. 12.
265 Eureka, Humbolt Eureka Gas Pipes
County - 12 miles earthquake
southwest of epicenter December 21, 1954
"The Eureka distribution system was broken in a number of places
including 16 gas pipeline breaks and 19 water pipeline breaks."
Steinbrugge and Moran, April 1957, pp. 138-139.
266 San Francisco, San Daly City Gas Pipes
Francisco County - 5 earthquake
miles from epicenter March 22, 1957
"... gas lines...broken." USC&GS, "U. S. Earthquakes," 1957,
p. 23,
267 San Bruno, San Mateo Daly City Gas Main
County - 5 miles from earthquake
epicenter March 22, 1957
"Gas main broke in Rollingwood tract... plumbing broken. "
USC&GS, "U.S. Earthquakes," 1957, p. 22.
G-38
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
268 Fort Rosecrans, Point Baja California Gas Main
Loma, San Diego County, earthquake
approximately 150 miles November 30, 1958
northeast of epicenter
"*.. Lt. Brown felt it at Fort Rosecrans and the next day discovered
a broken water main on the east hill-slope of the Point. There were
numerous deep, open ground cracks; a major crack parallel to the
contours passed through the site of the pipe break. The pipe ran
directly upslope. On December 5 an odor of gas was noted and he
found a 2-inch tension break in a gas line northeast of the water
line break. There are ground cracks in the vicinity of this break
also and one of them passed through the site of the break. It was
subsequently discovered that 2-1/2 million cubic feet of gas had
escaped, indicating that the break had been open for some days,
quite possibly since November 30. I toured the area of damage with
Lt. Brown and saw extensive tensipn cracking high on the hill slope
and small compression ridges along the asphalt roadway at the foot
of the slope. The cracks progress up the hillside and back down to
the roadway, enclosing an area of some acres located between
Ballast Point and the U. S. Navy Fuel Facility. Movement has con-
tinued since November 30, displacement on the water main now
amounting to 2 feet. The area is a dip-slope in Cretaceous shales
and sandstones; according to Moore (NEL Technical Report) the
dips in this area are 5 to 10 degrees, which is less than the slope
of the land surface just above the road. Up the hill from the crack-
ing is the National Cemetery which has recently been expanded and
where there is extensive watering of grass. This is an almost per-
fect example of dip-slope landsliding as has occurred recently in
the Los Angeles area. Lt. Brown's suggestion that the slide was
touched off by the November 30 shock is reasonable. However the
basic cause is instability of the slope, and the effects of the water-
ing in the cemetery should be investigated. It should be noted that
movement occurred before any heavy rains had occurred. I would
anticipate that the sliding will continue with the eventual result of
carrying out the road and dumping several acres of Point Loma
into the San Diego harbor channel entrance. " USC&GS, MSA-100,
1958, p. 23.
G-39
-------
Case No. Petroleum System
(See Figure G-5) Location Earthquake Damaged
269 Highway 46, (1) mile Parkfield Oil Pipeline
east of Cholame, San earthquake
Luis Obispo County June 27, 1966
within 35 miles of Intensity VII
epicenter
".. .broke a Union Oil Company pipeline along roadside." The
Daily Press. June 29, 1966.
G-40
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APPENDIX H
CORROSION OF PETROLEUM SYSTEMS EQUIPMENT
-------
TABLE OF CONTENTS
Appendix H - Corrosion of Petroleum Systems Equipment H-l
H. 1 Introductory Summary H-l
H.2 Fundamental Definitions and Corrosion Mechanisms H-2
H.2.1 Definitions H-2
H.2.2 Corrosion Mechanisms H-3
H. 3 Mitigation H-5
H.3.1 Substitution H-6
H.3.2 Environmental Modification H-6
H. 3.3 Separation H-7
H. 3.4 Cathodic Protection H-8
H.4 Corrosion Problem Areas of Crude Oil Systems H-14
H.4.1 Drilling Systems H-14
H.4.2 Production Systems H-17
H.4.3 Gathering/Distribution Systems H-19
H.5 References H-20
H-ii
-------
LIST OF ILLUSTRATIONS
Figure
H-l Corrosion Occurrence by Geographical Area H-4
H-2 Structural Corrosion Zones H-13
LIST OF TABLES
Table
H-l Sample Environmental Data Needed for Corrosion Protection
Design
H-15
H-iii
-------
APPENDIX H
CORROSION OF PETROLEUM SYSTEMS EQUIPMENT
H.1 INTRODUCTORY SUMMARY
Corrosion is one of the most important factors to be considered in the design and oper-
ation of petroleum systems. The useful life of oil and gas field equipment is often signi-
ficantly shortened as a result of corrosion. The cost of corrosion in petroleum systems
equipment is high in the United States. In 1950, this cost was estimated by Uhlig to be
$6 billion per year. This estimate was based on losses from corrosion, cost of main-
tenance, and cost of substituting more expensive corrosion-resistant materials for
ordinary grades of iron or steel. Chilingar and Beeson (1969) estimated that the total
cost of corrosion in the United States in 1965 was about $10 billion.
Corrosion of oil field equipment is not only costly but may lead directly or indirectly to
oil spills. Volume I has pointed out a number of priority and routine points of spill
vulnerability due to corrosion in Production and Gathering/Distribution (G/D) Systems.
External corrosion of pipeline and gathering subsystems was found to be the most exten-
sive cause of oil spillage from those systems. The Department of Transportation has
promulgated in the Federal Register (Title 49 Part 195) extensive regulations covering
corrosion control in main trunk liquid pipelines. Comparable requirements are not in
effect for gathering subsystems and production facility flow lines.
The basic principles of corrosion and its mitigation are relatively straightforward.
However, application of these principles to identify effective solutions to control corrosion
problems for a specific facility is complex and generally requires the services of a cor-
rosion engineer. Corrosion engineering is a specialized field requiring training and ex-
perience in electrochemistry and physical metallurgy. Individuals with professional
qualifications in petroleum engineering, earth science, or water chemistry are not neces-
sarily qualified as corrosion engineers. The National Association of Corrosion Engineers
(NACE) recognizes individuals with professional qualifications in the corrosion engineer-
ing field.
H-l
-------
This appendix supports the spill prevention guidelines of Volume I with a summary of
corrosion fundamentals applicable to the spill vulnerability points for crude oil systems.
Additional information can be obtained from the references given in Paragraph H. 5. De-
tailed questions regarding corrosion control for a specific spill prevention problem should
be referred to a corrosion engineer.
H.2 FUNDAMENTAL DEFINITIONS AND CORROSION MECHANISMS
H.2.1 Definitions
In general terms, corrosion (excluding mechanical erosion or abrasion) may be defined as
the destructive attack of a metal by a chemical or electrochemical reaction with its en-
vironment. The basic driving force for this reaction is the tendency of produced or pro-
cessed material, when placed in a natural environment, to return to its natural and more
nearly stable chemical state.
Corrosion of oil field equipment results primarily from an electrochemical reaction. The
reaction requires the following elements in order to proceed:
Anode - A conductor which is electrically positive relative to the
cathode
Cathode - A conductor which is electrically negative relative to the anode
Electrolyte - A conducting medium providing an electrical path between anode
and cathode
External - An electrical path between the anode and cathode other than
Electrical ., , ., . . . .
_ through the electrolyte.
Connection ^ J
When the circulation of electrical current of this reaction causes a discharge of electrons
from the anode into, the electrolyte, the anode may experience a depletion of material and
formation of insoluble compounds. This depletion, or eating away, of anode material is
corrosion. When it threatens the integrity of an oil field structure or vessel, a potential
for oil spillage exists. Corrosion mitigation is accomplished if any of these basic re-
action requirements are removed.
H-2
-------
H.2.2 Corrosion Mechanisms
Corrosion in petroleum system equipment can be classified into four main types:
1. Sweet Corrosion, which results from the presence of carbon dioxide (CO ) and
z
fatty acids in oil or gas wells. Oxygen (O ) and hydrogen sulfide (H S) need
£1 2
not be present. This type of corrosion is frequently encountered in southern
Louisiana, Texas, and California (see Figure H-l). Corrosion in sweet oil
or gas wells usually becomes serious after the wells have produced for several
years and the salt water production reaches 40 to 50 percent.
2. Sour Corrosion, which occurs in oil and gas wells that produce even small
amounts of H S. This type of corrosion occurs in the Permian Basin of West
Texas and New Mexico, the Arbuckle production in Kansas, and Smackover
production in East Texas, northern Louisiana, Mississippi, Alabama, and
Florida. Approximately 40 percent of the producing wells in the United States
are producing H S and thereby have the potential to become corrosive. Sulfide
£
corrosion, which depends on moisture, generally starts slowly and increases
with time, sometimes costing as much as $1100 per well per month to control
(National Association of Corrosion Engineers and American Petroleum Institute,
1958).
3. Oxygen Corrosion, which occurs wherever equipment is exposed to atmospheric
oxygen or oxygen dissolved in water. This type of corrosion occurs most
frequently in offshore platform installations and in shallow producing wells
where air is allowed to enter the annular space. Brine handling and injection
systems also may experience oxygen corrosion even though they are closed
systems. This can occur when component leakage or mixture with other water
which has been exposed to the atmosphere allows oxygen to enter the system.
The expansion of the offshore petroleum industry has resulted in high oxygen
corrosion costs and presents a great challenge to corrosion engineers. In
H-3
-------
a
I
|HOIL PRODUCTION
| | GAS PRODUCTION
fes=hPUR CRUDE CORROSION
11CONDENSATE CORROSION
[] SWEET OIL CORROSION
(Adapted (torn National Association of Coiiosion Engineers, 1958)
Figure H-l. Corrosion Occurrence by Geographical Area
-------
California's Santa Barbara Channel, exploratory wells have been drilled in
1200 feet of water. Offshore Louisiana operations have moved from 30- to
50-foot water depths into depths of 300 feet or more. Cook Inlet operations
require design for 100-foot water depths and unusually severe corrosion
conditions due to high tidal range, swift currents, and the resulting in-
creased exposure to dissolved O in the Inlet waters. Corrosion protection
&
for offshore platforms, required for the "splash zone" and underwater
surfaces as well as surfaces exposed to the atmosphere, can represent
10 percent of the platform total cost (Hanson and Hurst, 1969).
4. Galvanic and Electrochemical Corrosion, which results when electrical
currents between anode and cathode exist, as in soil. Sea water is probably
the most corrosive of all natural environments. Pipelines are necessarily
placed in soil and sea water and therefore are subject to galvanic corrosion.
There are a number of causes for these electrical currents. These include:
a. Differing composition of materials between anode and cathode
(bimetallic cell)
b. Different temperatures between anode and cathode (temperature cell)
c. Differences in homogeneity or concentration of the electrolyte
(concentration cell)
d. Stray currents (electrolytic cells) which flow or are induced from
other structures and power sources.
H.3 MITIGATION
Mitigation techniques for electrolytic corrosion may be grouped into four general methods.
They are:
! Substitute a more corrosion resistant anode material for the item experiencing
corrosion
2. Modify environmental parameters, including the corroding medium (or
electrolyte), to reduce their active support of corrosion
H-5
-------
3. Separate the equipment from its corrosive environment with a coating or
other electrical barrier
4. Apply cathodic protection to establish a benign reaction in place of the
undesired corroding reaction.
H. 3.1 Substitution
A number of metallic and nonmetallic materials have been used in place of ordinary
grade steels to provide corrosion protection of oil field equipment. These materials
include plastic, aluminum, and special grade (stainless) steels. Plastic has been used
for piping a number of fluids including gas. More recently, both plastic and aluminum
pipe have been found suitable for some crude oil gathering applications within limited
pipe size and line pressure. Stainless steel, and other corrosion resistant metals have
been used for a variety of applications including drill pipe, sucker rods, valves and
valve trim, fittings, and some piping and pressure vessels. Extensive use of stainless
steel and comparable corrosion resistant metals can be expensive and invites tradeoff
with other corrosion protection measures relative to the protection requirements.
Care must be exercised in the selection and use of different metals since it is possible to
cause corrosion through bimetallic galvanic cells when dissimilar metals are in direct
contact and exposed to the same electrolytic medium. By exception, if the amount
(surface area) of anodic (corrodable) metal is large compared to the available surface
area of the noble (cathodic and, thus, noncorrodable) metal, the rate of general corrosion
of the anode will normally be low and may be tolerable in some applications. For example,
a large steel (anodic) tank containing an electrically conductive fluid may experience negli-
gible corrosion by having a copper (cathodic) fitting. By contrast, a steel (anodic) valve
may experience severe corrosion when connected to a large copper (cathodic) vessel con-
taining an electrically conductive fluid. The copper should not experience corrosion in
either example.
H. 3.2 Environmental Modification
In general, modification will be either through application of suitable construction tech-
niques or the addition of a substance to the electrolyte. Construction could include
H-6
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support and drainage for a storage tank or underground pipeline. The electrolyte ad-
ditives may be chemical treatments, corrosion inhibitors, or bactericides. The chemical
treatments include use of oxygen scavengers, which reduce the amount of dissolved
oxygen; dehydrators, which reduce the amount of water in the fluids (applicable to fluids
with very low percent water); and alkaline substances which reduce the acidity of the
fluids. Inhibitors and passivators may be either organic or inorganic substances. They
function by forming a thin chemical film on the exposed metal parts which retards
corrosion of the metal wall. Inorganic inhibitors include some soluble chromate and
arsenic compounds. Organic inhibitors having different solubilities for oil and water may
be selected, depending on the application. Bactericides usually provide effective elimi-
nation of certain bacteria which present corrosion problems. Some bacteria contribute
to the formation of slime which can entrap dissolved oxygen at different concentrations
at the metal surface and create a corrosion-producing galvanic cell. Other bacteria
attack sulfate or sulfide compounds and produce H S.
Lt
All of these substances can be injected into producing wells, vessels, pipelines, down
hole annular spaces, drilling mud, and casing cement, as required, and be effective
against corrosion. Some of these substances are hazardous and require care in handling
to assure safety of personnel, livestock, other safety requirements, and protection of the
environment.
H.3.3 Separation
Separation normally takes the form of electrically isolating the anode, cathode, or
electrolyte. Electrical isolation may result from use of insulated fittings and flanges.
Applications include isolation of well casings, sections of coated pipe, tanks, production
surface equipment, and pipelines. Coatings of nonconducting material or other protec-
tive substances may be grouped into the four broad categories of paint, metal coating,
inorganic coatings, and organic coatings.
Paint provides protection of surface equipment from corrosion due to atmospheric oxygen.
It is usually applied in several coats over a carefully prepared and cleaned metal surface,
with a corrosion inhibiting primer coat. It is widely used for steel surface equipment and
structures (including offshore platforms) and above-ground pipelines.
H-7
-------
Metal coatings include galvanizing, cladding with noble metals like monel, and use of
stainless steel sheets. One significant application of monel cladding or use of stainless
steel sheets is for offshore platform supports in the tidal and splash zones. These sup-
ports would otherwise experience significant corrosion through intermittent exposure to
atmospheric oxygen and aerated sea water. The relatively small surface area of cathodic
monel or stainless steel (compared to that of the anodic total platform structure) allows
negligible general corrosion of the platform from this bimetallic cell.
Inorganic coatings include oxide films, glass, and cement. Aluminum, although an active
metal in the electromotive series, rapidly forms an oxide film that is self-healing and
prevents further corrosion. Glass coatings are expensive, easily damaged and, thus,
not frequently used. Applications would include internal tubing surfaces, and walls of
pressure vessels. Portland cement is a very good coating since it is alkaline, tough,
and dense. It is frequently used over pipe with an organic coating to provide additional
protection and ballast for offshore pipelines and flowlines.
Organic coatings are the most frequently used for underground pipe. Major types include
coal tar and asphalt enamels, plastic tapes, extrusion coatings, thin film fusion bonded
coatings, and mastics.
H.3.4 Cathodic Protection
H.3.4.1 General
Cathodic protection is an electrical method for preventing corrosion. It is used on
metallic structures which are in electrolytes such as soil or water. It has had wide-
spread application on underground pipelines, and has been found to be effective on other
underground and underwater structures such as storage tanks, steel pilings, well casings,
and water treatment equipment. The method consists of installing electrodes into the
soil or water (electrolyte) in contact with the equipment to be protected, and providing an
external electrical connection (with or without electrical power) between the equipment
and the newly installed electrodes. The intent is to stop the corrosion reaction, which
used the equipment as the anode, by substituting a new and stronger reaction in which the
H-8
-------
installed electrodes are anodes (which may corrode without harming the equipment) and
uses the equipment to be protected as a cathode which will not corrode. Cathodic pro-
tection operates by passing direct current continuously from electrodes, which are in-
stalled in the electrolyte, to the structure to be protected. Corrosion is arrested when
the current is of sufficient magnitude and is properly distributed.
There are two basic methods of applying cathodic protection; the impressed current
method and the sacrificial anode method. The impressed current method uses anodes
which are energized by an external dc power source. In this type of cathodic protection
system, anodes are installed in the electrolyte and connected to the positive terminal of
the dc source. The structure which is to be protected is connected to the negative ter-
minal of that source. Because the power source is almost always a rectifier unit, this
type of system is often referred to as a rectifier type system. The sacrificial anode
method of protection makes use of galvanic anodes, made from such materials as zinc
or magnesium, which have a natural difference of potential with respect to the structure
to be protected. These anodes are connected directly to the structure, hi most cases,
the rectifier type system is designed to deliver relatively large currents from a limited
number of anodes. On the other hand, the sacrificial anode type system delivers re-
latively small currents from a large number of anodes.
Each method of applying cathodic protection has characteristics which make it more
applicable to a particular problem than the other. A comparison of those characteristics
is as follows:
Sacrificial Anode Method
Requires no external power
Fixed driving voltage
Limited current
Usually used where current
requirements are small
Usually used in lower resis-
tivity electrolytes
Impressed Current Method
External power required
Voltage can be varied
Current can be varied
Can be designed for almost any
current requirement
Can be used in almost any
resistivity environment
H-9
-------
In underground applications, In underground application,
interference with neighboring interference with neighboring
structures is usually negligible structures must be considered
Irrespective of the type of system used, current flows from the anode to the structure to
be protected. When current flows onto a structure from the surrounding electrolytes,
the potential is made more negative and cathodic protection is achieved when the change
in potential is sufficient to arrest corrosion.
There are many differences in the design of cathodic protection systems. These dif-
ferences result from the large variety of structures which are to be protected, and from
the large variety of environments in which those structures are located. It is, therefore,
necessary that each system be custom-designed for a given location. Rules-of-thumb
should be avoided unless it can be shown that such rules are directly applicable to a par-
ticular design situation. In order to design a cathodic protection system properly, field
measurements must be taken to determine the corrosion pattern and the current re-
quired for protection.
In order to prevent corrosion using cathodic protection, current must flow from the
electrolyte onto the structure at all locations. If a portion of the structure does not re-
ceive current, the normal corrosion activity on that structure will continue. If any of the
cathodic protection current picked up by the structure leaves that structure to flow back
into the electrolyte, corrosion will be accelerated at the location where the current leaves.
For example, an underground pipeline, in which mechanical joints are used, may be
electrically discontinuous. If a galvanic anode type system is used for protection, it
would be necessary to install an anode on each pipe length or to bond across each joint.
If one length of pipe is neglected, that length will receive no cathodic protection and the
normal corrosion activity will continue. When a rectifier type system is installed on a
pipeline, it is even more important that the line be electrically continuous. If there are
noncontinuous joints, it is possible for the cathodic protection current to leave the pipe
and flow around that joint. Similarly, if cathodic protection current is applied to one
structure in an area, it is possible for other structures in the neighborhood to be exposed
H-10
-------
to damage unless proper steps are taken. Measurements of potential are used to deter-
mine whether the possibility of such exposure to damage exists. Just as protection is
indicated when the potential of a structure is made more negative, exposure is indicated
when the potential of a structure is made less negative as the result of the application of
current.
New, cross-country pipelines are provided with a good, high resistivity coating applied
with techniques which leave little of the pipe surface exposed to the soil. However, a
coating, no matter how good or how well applied, is rarely if ever perfect, and pro-
tection afforded by the coating must be supplemented with cathodic protection to achieve
complete protection against corrosion. It has been noted that coated pipelines can develop
leaks within a shorter period of time than uncoated pipelines. This is true even though
the total metal loss on a coated pipe is appreciably less than on a bare pipe. Coating and
cathodic protection work well together. When a pipe is coated with the materials and
techniques currently available, a relatively small magnitude of current can provide
cathodic protection for many miles of pipe.
The problems presented in attempting to provide cathodic protection for bare pipelines
are more difficult than those on coated pipelines. A major difficulty is the need for a
much greater magnitude of current.
Because of the large currents required to provide complete protection for a length of
bare pipe, a technique known as "hot spot" protection is used. In this type of system,
a detailed survey of the pipeline is made during which potential measurements and soil
resistivity measurements are taken at very close intervals, sometimes as close as 10
feet apart but more often from 50 to 100 feet apart. Evaluation of these measurements
is made, the more corrosive areas are selected, and anodes are installed at those
corrosive areas or "hot spots." Generally, "hot spot" protection also requires a large
number of anodes.
H.3.4.2 Application to Design of Offshore Platforms
Good corrosion control for offshore production platforms begins with structural design,
H-ll
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and it is necessary to select the best possible structure-environment combination.
Basically, this involves the consideration of the following two groups of factors:
1. Factors Associated with the System Materials
Effective electrolyte potential of the metal
Overvoltage of hydrogen on the metal
Tendency of metal to form an insoluble protective film
Chemical and physical homogeneity of the metal surface.
2. Factors Associated with the Environment
Oxygen concentration
Acidity of solution
Natural concentration and distribution of electrolytes
Tendency of environment to deposit a protective film on metal surface
Rate of flow of solution against metal
Temperature
Static or cyclic stresses
Contact with dissimilar solutions
Contact between dissimilar metals.
Simple, continuous shapes should be used throughout the structural system. If possible,
all edges, holes, crevices, and internal corners which may be inaccessible to anti-
corrosion maintenance should be eliminated.
Marine environments are hostile. Three separate zones exist for which corrosion con-
trol must be planned, (Hanson and Hurst, 1969). See Figure H-2. Approximate corrosion
rates in the Gulf of Mexico for these three zones are:
Atmospheric zone - 5 to 10 mils (0.001-inch penetration = 1 mil) per year
Splash zone - up to 55 mils per year
Immersed zone - up to 25 mils per year.
H-12
-------
WATER LINE
MUD LINE
ATMOSPHERIC ZONE
5-10 MPY
SPLASH ZONE
55.MPY.
IMMERSED ZONE
25 MPY
Figure H-2. Structural Corrosion Zones
H-13
-------
Table H-l lists a number of factors which must be considered in implementing corrosion
protection design for offshore petroleum systems.
Atmospheric zones are normally protected by paint. The splash zone experiences the
most severe corrosion environment since it is intermittently exposed to atmospheric
oxygen and submerged in sea water. Erosion limits the effectiveness of many coatings
including paint; and the intermittent immersion in the electrolytic sea water limits the
effectiveness of cathodic protection. Protective measures have included use of monel
cladding and the use of stainless steel sheets. In addition, sizing of the platform supports
for structural design safety margins reduces the chance that the effects of corrosion
would be significant over the expected useful platform life. Immersed zones are usually
under cathodic protection. In many instances in the Gulf Coast and off California,
cathodic protection systems may use sacrificial anodes made from aluminum or magnesi-
um alloys. In other instances, including Cook Inlet, the severity of the corrosion en-
vironment requires the use of impressed current cathodic protection systems.
H. 4 CORROSION PROBLEM AREAS OF CRUDE OIL SYSTEMS
Problems are considered from two standpoints: those documented in the literature re-
viewed during the study but not necessarily resulting in oil spills; and those exhibited by
the spill data discussed in Appendix E.
H.4.1 Drilling Systems
In general, Drilling System equipment experiences fewer corrosion problems than Pro-
duction or G/D Systems. Problems which do occur include external corrosion of casing,
and combined corrosion and fatigue of drill pipe. Casing corrosion may be mitigated by
cathodic protection, paint or other coatings, and through use of electrical insulation.
However, cathodic protection of deep casings may present considerable difficulty. Drill
pipe corrosion may be mitigated by use of internal coatings, corrosion resistant steels,
and chemical inhibitors. In addition, corrosion inhibitors may be introduced into annular
spaces, casing setting cement, and the mud subsystem. When sour gas or sour crude is
anticipated, additional precautions may include use of an oil base mud (to minimize water
contact with H S) and trimming of the BOP stack for sour gas service. With the exception
H-14
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Table H-l. Sample Environmental Data Needed for Corrosion Protection Design
1. What are average, minimum, and maximum tidal fluctuations at site (feet)?
2. What are average, minimum, and maximum tidal currents at site (knots)?
3. What are average, minimum, and maximum water temperatures at surface (°F)?
4. Sea conditions:
Calm % total time per year
Low % total time per year
High % total time per year
5. Swell condition:
No swells % total time per year
Low % total time per year
High % total time per year
6. Maximum swells anticipated ft.
7. Maximum waves (storm) anticipated ft.
8. Any unusual reoccurring storm conditions? Describe.
9. Water depth at site ft.
10. Pile penetration below mud line:
Average ft.
Maximum ft.
Minimum ft.
11. Salinity (g./kg.)
A ve rage
Maximum_
Minimum
12. Water resistivity (ohm-cm.):
Average . % per year
Maximum . % per year
Minimum . % per year
13. Do drawings of structure show all underwater steel surfaces (grout lines, reach
rods, conductor pipes, etc.)? Knot, give details.
14. Are gathering, flare, or transmission pipe lines connected to structure or in
close proximity? Give details. Are pipe lines coated and/or cathodically pro-
tected? If so, give details.
H-15
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Table H-l. Sample Environmental Data Needed for Corrosion Protection Design
(Continued)
15. Is structure (below water line) to be painted? If so, give material and applica-
tion specification.
16. Are any special corrosion-resistant or high-strength alloys to be employed on
the submerged or tidal zone of the structure? If so, give details.
17. Will permanent, continuous ac power be available on structure? If so, advise:
volts, phase,
cycle, KVA available
18. Will cathodic protection electrical equipment be located in hazardous area
(requiring explosion-proof system) ?
19. Can electrical equipment be located within ventilated (or air conditioned) room
(permitting air cooled equipment) ?
20. What is the required life of the structure? years
21. Is it anticipated that any marine vessels will be moored at the structure for pro-
longed periods of time? If so, give details.
22. Will there be any operating equipment on the structure which might cause
continuous and extensive vibration?
23. Will there be any dc electrical equipment (other than cathodic protection) on
the structure?
24. Is any future extensive welding anticipated?
25. Is there any sewerage or industrial waste effluent discharged near or flowing to
the vicinity of the structure?
26. What is the water pH at the structure site?
Average
Maximum
Minimum
27. Are there any unusual wastes to be discharged overboard at the structure?
28. Is the structure to be located where fresh water intrusion is continuously or
periodically encountered (run-off, river discharge, etc.)?
29. Is heavy floating debris or ice anticipated? If so, give details.
30. In the general area of the structure is there any history of extensive submarine
organism growth? Plants, animal?
H-16
-------
of permanently installed down hole components, most drilling equipment is subject to
visual inspection for corrosion damage during tripping and in the period following rig-
down and prior to rig-up for the next drilling operation. The spill data for Drilling
Systems did not identify any corrosion problems contributing to crude oil spills or blow-
outs.
H.4.2 Production Systems
Corrosion problems in Production Systems have been extensively documented in the
technical literature. Down hole equipment is exposed to produced brine water and fre-
quently to either sour (H S) or sweet (CO ) agents capable of producing both generally
£ 2
and locally severe corrosion. Any dissolved O in the water also will greatly increase
ii
corrosion. Normally, produced brine contains little or no O0 unless it is exposed to the
£i
atmosphere at the Earth's surface or mixed with other similarly exposed water.
External corrosion of surface equipment occurs as a result of atmospheric O0. Internal
i
corrosion of separators and storage tanks also is experienced. Tank bottoms are subject
to external corrosion by soil action. In any of these equipment (especially those with low
fluid velocity) the accumulation of sludge, scale, or sediment in the lower regions of the
vessel frequently localizes and accelerates corrosion.
Water disposal subsystems frequently experience corrosion and present many difficulties
in mitigation. However, the study data indicated few oil spills resulting from cor-
rosion of these subsystems.
Custody transfer subsystems have occasionally exhibited corrosion attributed to use of
dissimilar metals in LACT unit installations. However, the spill data did not show this
to be a problem.
Pipe leaks in gathering subsystem flowline equipment is the largest single source of oil
spillage from Production Systems. For onshore applications, the predominant cause of
leaking is attributed to corrosion (70 percent external, 30 percent internal). External
corrosion of buried pipe may be controlled, in most cases, by the combined application
of coating and cathodic protection. Since cathodic protection is considerably more costly
H-17
-------
for uncoated pipe, a surface survey of the bare pipeline can be made to determine areas
where active corrosion is in progress. Cathodic protection may then be limited to those
areas to reduce overall cost. If cathodic protection is not used, but coating is applied,
corrosion may occur at holidays (voids or weaknesses) in the coating. Uncoated lines
in the section can be partially protected by use of insulated flanges and fittings. Other
mitigation methods include the use of aluminum pipe and the use of plastic pipe of limited
diameters and pressures. Internal corrosion mitigation may be accomplished with in-
ternal coatings, chemical inhibitors, and chemical treatment to reduce acidity and oxygen
content.
Oil spills have been attributed to leaking of onshore tank shells and bottoms. In many
instances the quantity of spill was substantial and secondary containment was inadequate
(see Appendix E). External shell corrosion may be controlled by painting if the metallic
surface can be cleaned and a corrosion resistant primer coating is used. Internal shell
corrosion may be controlled by paint or other selected coatings, including metal coatings,
inhibitors, or other chemical treatment to control acidity or water in the stored fluids.
In addition, cathodic protection may be possible by suspending the system's anodes inside
the tank shell given that the stored liquids are sufficiently electrolytic to support current
flow.
Tank bottom internal corrosion may be mitigated by coating, treatment of the stored
liquids as previously mentioned, and cleaning to remove sludge and sediment capable of
entrapping corrosive agents at local points on the bottom.
Tank bottom external corrosion may be controlled by coating, cathodic protection, and a
foundation designed for maximum drainage of ground water away from the tank. If the
tank bottom is coated, cathodic protection should also be used to prevent locally severe
corrosion at points where there are holidays in the coating. Otherwise, the corrosion
current, which generally would corrode the entire unprotected bottom at a slow rate, may
concentrate at any breaks in the coating and cause perforation at a much higher rate than
if the bottom were not coated. A good coating, however, greatly reduces the current
requirements for a complementary cathodic protection system.
H-18
-------
Oil spills in safety subsystems have been attributed to high liquid level sensor failures
in offshore storage tanks and sump systems, and in onshore storage tanks, separators, and
treaters. In general, mitigation measures for tank shell internal corrosion should be
applicable to protect the level sensors, which are mounted internally and exposed to the
vessel liquids and the atmosphere. In addition, sensors selected for these applications
should be designed for corrosion service.
Fire tubes in onshore heater treaters in treater subsystems have been responsible for
some reported leaks and, thereby, oil spills. Normally, these tubes are internally
fired and placed in the vessel so that the external surface is in direct contact with and
exchanges heat energy to the produced liquids. As a result, the fire tubes experience a
severe corrosion environment on both internal and external surfaces. No corrosion
mitigation measures have been identified as applicable to fire tubes. Since they are re-
latively inexpensive and removable, frequent inspection and replacement, as required,
may be a practical approach to prevent oil spillage. Inspection frequency could be based
on corrosivity, throughput and pressure of produced fluids or of the fuel used, proximity
of the facility to waterways or other local factors, and whether the facility is continuously
manned, and has adequate provisions for safety shut-in and secondary containment.
H.4.3. Gathering/Distribution Systems
Corrosion problems in G/D Systems have received extensive attention. Crude oil pipe-
lines and gathering lines (with BS&W held to 1 percent) experience internal and external
corrosion due to O_ and H S. Buried pipelines also experience external galvanic cor-
2 &
rosion in the soil environment. Mitigation measures include coatings, cathodic pro-
tection, and electrical insulation for external corrosion; and inhibitors, chemical treat-
ment, and coating for internal corrosion.
Mitigation methods for storage subsystem corrosion are similar to those identified for
Production System local storage subsystems and the additional use of dehydration to
remove water from the stored fluids. No corrosion problems of significance were identi-
fied for pump stations.
H-19
-------
Pipeline and gathering subsystem pipe corrosion was, by a wide margin, the largest
single cause of oil spillage, with an indicated distribution of 80 percent external and 20
percent internal corrosion. Mitigation methods previously described for Production
System gathering subsystems are applicable except that the possibility of using plastic
pipe should be limited to gravity type gathering subsystems, or other low pressure
gathering functions with small diameter pipe. In addition, dehydration of transported
fluids may be considered.
Road crossing pipe, since they may be at a low point in the line section, and encased to
limit mechanical damage, present possible corrosion problems in addition to those of
pipelines in general. From the standpoint of gathering subsystem road crossing internal
corrosion, pipe radii and bends could be made sufficiently gradual to accommodate in-
ternal passage of scrapers or spheres (also called pigs or go-devils) for pipe internal
maintenance including removal of entrapped water. (This is already a DOT require-
ment for main trunk liquid pipelines.) From the standpoint of external corrosion, the
use of metallic external casings to protect the line passing under a roadway presents a
problem. If the line has electrical contact with the casing and any material in the annular
space is electrolytic, an active corrosion cell will result. Subject to State and local re-
gulation, consideration could be given to a road crossing which would not require an ex-
ternal casing to provide mechanical protection under the road. If a protective casing is
used, corrosion mitigation methods could include measures to ensure electric insula-
tion of the casing from the pipe. An additional measure would be to fill the annular
space with an electrically resistant and corrosion resistant material which could per-
manently displace any moisture.
H.5 REFERENCES
Case, L. C., 1970, Corrosion Causes, Prevention and Treatment, Chapter 5, Water
Problems in Oil Production, Petroleum Engineering Publishing Company.
Chilingar, G. V. and C. M. Beeson, 1969, Fundamentals of Corrosion, Chapter 8,
Surface Operations in Petroleum Production, American Elsevier Publishing Co.
H-20
-------
Doremus, G. L. and J. G. Davis, 1969, Modern Approach to Cathodic Protection of
Off-shore Pipelines, Pipeline Engineer, Vol 41, no. 11, p. 36-45.
Hanson, H. R. and D. C. Hurst, Corrosion Control Off-shore Platforms, Proceedings
of 1969 Off-shore Technology Conference, p. 437.
Lane, J. J., 1970, A New Look at Coatings, Pipeline Industry, Volume 32, No. 2,
pp 31-34.
National Association of Corrosion Engineers and American Petroleum Institute, 1958,
Corrosion of Oil and Gas Well Equipment, Book 2 of the Vocational Training Series.
NGAA, 1953, Condensate Well Corrosion, Natural Gas Association of America, Tulsa,
Oklahoma.
Ostroff, A. G., 1971, Understanding and Controlling Oil Field Corrosion, Modern
Fundamentals of Oil and Gas Production, Petroleum Engineering Publishing Company.
Parker, M. E., Corrosion and Its Control, Oil and Gas Journal
Uhlig, H. H., 1950, The Cost of Corrosion to the United States, Corrosion, v. 6, p. 29.
H-21
-------
APPENDIX I
REGULATION REVIEWS SUMMARY REPORTS
-------
TABLE OF CONTENTS
Appendix I - Regulation Reviews Summary Reports. 1-1
1.1 Introduction Summary 1-1
1.2 Regulation Reviews Summary Reports 1-2
I-ii
-------
LIST OF ILLUSTRATIONS
Figure
1-1 Regulation Review Summary Report Format 1-3
1-2 Organizational Structure for the National Oil and Hazardous
Substances Pollution Contingency Plan 1-12
1-3 Spill Reporting 1-13
I* »
-111
-------
APPENDIX I
REGULATION REVIEWS SUMMARY REPORTS
1.1 INTRODUCTION SUMMARY
The spill prevention program described in this report is intended to respond to existing
Federal legislation and proposed regulations. The regulations, statutes, and related
documents were gathered, reviewed, and summarized to identify the total program
interfaces with the oil spill prevention program. The reports most pertinent to the
provisions of Volume I are included in this appendix and consist of the following:
Federal Water Pollution Control Act of 1972
Title 3 - The President, Executive Order 11548, Delegating Functions
of the President Under the Federal Water Pollution Control Act, as
Amended, July 20, 1970
Reorganization Plan No. 3 of 1970
Memorandum of Understanding between the Environmental Protection
Agency and the Department of Transportation concerning the Definition
of Transportation-related and nontransportati on-related facilities as
used in Executive Order 11548, December 18, 1971
National Oil and Hazardous Substances Pollution Contingency Plan
Code of Federal Regulations, Title 33, Part 153 - Control of Pollution
by Oil and Hazardous Substances, Discharge Removal.
A number of State and Federal regulations, including the Refuse Act, also have been
reviewed to determine requirements and practices. These were not summarized since
they either were not pertinent or had been summarized in a prior EPA report.
This appendix is included to provide a quick summary of regulatory provisions of
significance to the spill prevention plan.
1-1
-------
1.2 REGULATION REVIEWS SUMMARY REPORTS
In preparing summary reports of documents that were found applicable, consideration
had to be given to their content. The contents of the summaries are limited to dis-
cussion of only those sections directly applicable to this program. The pertinent items
considered to be of interest are reflected in Figure 1-1. The remainder of this
appendix provides the Regulation Review Summary Reports for the regulations identified
in Paragraph F.I.
1-2
-------
1. TITLE - Title of the document reviewed
2. AGENCY - Name of the agency which issued the document
3. DATE - Effective Date
4. APPLICABILITY - A statement of the areas, items, or actions of interest to
which the document applies.
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - A statement which describes
the individual, office, or agency responsible for the administration and enforce-
ment of the provisions of the document. Also, a statement of the penalties
imposed for violation of the document's provisions.
6. HARDWARE REQUIREMENTS - A brief statement describing the system, equip-
ment, and/or component hardware requirements imposed by the document.
7. PROCEDURE REQUIREMENTS - A statement describing any procedural require-
ments imposed by the document as they pertain to inspection, operation, or main-
tenance.
8. DATA REPORTING REQUIREMENTS - A statement describing the requirement
for reporting and/or maintaining records of configurations, production, mainten-
ance, inspection, or failures (spills).
9. GENERAL COMMENTS - Any relevant comments not covered by the above.
Figure 1-1. Regulation Review Summary Report Format
1-3
-------
REGULATION REVIEW - SUMMARY REPORT
1. TITLE - Federal Water Pollution Control Act
2. AGENCY - Environmental Protection Agency
3. DATE - October 18, 1972
4. APPLICABILITY - ThisAct applies to all United States' water resources. How-
ever, Section 311 deals with control of pollution by oil and other hazardous
substances.
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - The Secretary of Interior
originally was responsible for administration of this Act. However, Section 311 of
this Act assigns most responsibility in the area of oil pollution to the President.
Subsection (b) (3) requires the President to issue regulations which define the
quantities of discharged oil which constitute a violation of this Act. Subsection (c)
authorizes the President to act to remove discharged oil from the environment and
directs that he prepare and publish a National Contingency Plan for removal of oil.
Items to be included in the Plan are described. Subsection (j) requires the
President to issue regulations regarding various aspects of oil pollution cleanup
and prevention while Subsection (1) authorizes the President to delegate the
administration to appropriate Federal activities.
Various subsections of Section 311 prescribe legal remedies and penalties for oil
pollution. Those violations and penalties of interest to this study are:
1-4
-------
VIOLATION
Failure to report oil discharges
Discharge of oil
Oil discharge from onshore or
offshore facilities
Failure or refusal to comply
with regulations
PENALTY
$10,000 fine and/or not more than 1
year imprisonment
Civil penalty of not more than $5,000
for each offense
Removal costs not to exceed $8, 000, 000
except in the case of willful negligence
or willful misconduct which results in a
liability for the full cost
Civil penalty of not more than $5,000
for each violation
6. HARDWARE REQUIREMENTS - Section 311 (j) (1) (C) authorizes issuance of
regulations establishing requirements for equipment to prevent discharges of
oil and hazardous substances from vessels and onshore and offshore facilities.
7. PROCEDURE REQUIREMENTS - Section 311 (j) (1) (C) authorizes issuance of
regulations establishing procedures and methods to prevent discharges of oil
and hazardous substances from vessels and onshore and offshore facilities.
8. NOTIFICATION REQUIREMENTS - Section 311 (b) (5) requires any person in
charge of a vessel or of an onshore or an offshore facility to notify the appro-
priate United States Government agency as soon as he has knowledge of discharge
of oil or hazardous substances.
9. GENERAL COMMENTS - This Act provides the basis for prevention and cleanup
of oil pollution through establishment of National, Regional, and Local Contingency
Plans and Regulations.
1-5
-------
REGULATION REVIEW - SUMMARY REPORT
1. TITLE - Title 3 - The President, Executive Order 11548 Delegating Functions
of the President Under the Federal Water Pollution Control Act, as Amended.
2. AGENCY - The President - Richard M. Nixon
3. DATE - July 20, 1970
4. APPLICABILITY - Same as Federal Water Pollution Control Act.
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - This Order delegates
functions of the President under the Federal Water Pollution Control Act to
others as follows:
Secretary of the Interior (and subsequently to the Administrator of the Environ-
mental Protection Agency by Reorganization Plan NoL 3 of 1970).
To carry out the provisions of Section 311, Subsection (b) (4) relating to
the determination of those quantities of oil the discharge of which, at such
times, locations, circumstances, and conditions, will be harmM. . . .
To carry out the provisions of Section 311, Subsection (e) to secure relief
through court action to abate actual or threatened discharges of harmful
quantities of oil.
To carry out the provisions of Section 311, Subsection (j) (1) (C) to
establish procedures, methods, and requirements for equipment to
prevent discharges of oil from nontransportation-related onshore and
offshore facilities.
Council on EnvironmentalQuality
To carry out the provisions of Section 311, Subsection (c) (2) providing
for the preparation, publication, revision, or amendment of a National
Contingency Plan for the removal of oil.
1-6
-------
Secretary of the Interior (Administrator of EPA) and Secretary of Transportation
Responsibility and authority to implement Section 306.2 of the National
Contingency Plan as follows: EPA shall furnish or provide the On Scene
Coordinators (OSCs) for inland navigable waters and their tributaries.
USCG shall furnish or provide for OSCs for the high seas, coastal, and
contiguous zone waters, and for Great Lakes coastal waters, ports, and
harbors.
To carry out the provisions of Section 311, Subsection (d) for coordination
and direction or removal or elimination of the threat of oil or hazardous
substance discharges.
Commandant of the Coast Guard
Shall issue regulations implementing his designation as the "appropriate
agency" for the purpose of receiving the notice of discharge of oil required
by Section 311, Subsection (b) (5).
6. HARDWARE REQUIREMENTS - Not applicable.
7. PROCEDURE REQUIREMENTS - Authority to issue regulations required to
implement the assigned administrative responsibilities is granted by Section 8
of the Executive Order.
8. DATA REPORTING REQUIREMENTS - The Coast Guard is authorized to
establish any Data Reporting Requirements necessary.
9. GENERAL COMMENTS - This Executive Order delegates Presidential
responsibilities and authorities authorized under the Federal Water Pollution
Control Act. It also refers to the Reorganization Plan No. 3 of 1970 and the
National Contingency Plan.
1-7
-------
REGULATION REVIEW - SUMMARY REPORT
1. TITLE - Reorganization Plan No. 3 of 1970
2. AGENCY - The President
3. DATE - July 9, 1970
4. APPLICABILITY - Same as the Federal Water Pollution Control Act
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - Not Applicable
6. HARDWARE REQUIREMENTS - Not Applicable
7. PROCEDURE REQUIREMENTS - Not Applicable
8. DATA REPORTING REQUIREMENTS - Not Applicable
9. GENERAL COMMENTS - This plan established the Environmental Protection
Agency and transferred to the Administrator of EPA all functions vested by law
in the Secretary of the Interior and the Department of Interior but in fact
administered by the Federal Water Quality Administration. All previous func-
tions assumed by the Secretary of the Interior in Reorganization Plan No. 2 of
1966 (80 Stat. 1608), and all functions vested in the Secretary of the Interior or
the Department of the Interior by the Federal Water Pollution Control Act or
by provisions of Law Amendatory or supplementary thereof were also transferred.
1-8
-------
REGULATION REVIEW - SUMMARY REPORT
1. TITLE - Memorandum of Understanding Between the Environmental Protection
Agency and the Department of Transportation Concerning the Definition of
Transportation Related and Nontransportation Related Facilities as Used in
Executive Order 11548.
2. AGENCY - Department of Transportation and Environmental Protection Agency.
3- DATE - December 18, 1971.
4. APPLICABILITY - Same as Federal Water Pollution Control Act.
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - This memorandum
defines the respective areas of responsibility for the Environmental Protection
Agency and the Department of Transportation as distinguished by the terms
Nontransportation-Related and Transportation-Related as used in Executive
Order No. 11548. It was noted that the DOT responsibilities were redelegated
to the Coast Guard.
6. HARDWARE REQUIREMENTS - Not applicable.
7. PROCEDURE REQUIREMENTS - Not applicable.
8. DATA REPORTING REQUIREMENTS - Not applicable.
9. GENERAL COMMENTS - This memorandum of agreement was prepared to more
clearly define the responsibilities and authorities of the two agencies.
1-9
-------
REGULATION REVIEW - SUMMARY REPORT
1. TITLE - National Oil and Hazardous Substances Pollution Contingency Plan.
2. AGENCY - Council on Environmental Quality.
3. DATE - 1973 (Not published at time of this report.)
4. APPLICABILITY - This Plan is effective for all United States navigable waters,
their tributaries, and adjoining shorelines. This includes inland rivers, Great
Lakes, coastal territorial waters, the contiguous zone, and high seas where
there exists a threat to United States waters, shoreface, or shelf-bottom.
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - This Plan describes the
administrative structure for responses to actual or potential pollution discharges
and defines responsibilities and authorities. The administrative elements of
particular interest to this study are as follows:
The Council on Environmental Quality is responsible for the preparation,
publication, revision, and amendment of the National Contingency Plan,
receiving its advice from the National Response Team.
The Environmental Protection Agency (EPA) chairs the National Response
Team. EPA also chairs the Regional Response Teams and provides the
On Scene Coordinator (OSC) for inland navigable waters and their tributaries.
The United States Coast Guard provides the vice-chairman for the National
Response Team. The United States Coast Guard also chairs the Regional
Response Teams and provides OSC for high-seas, coastal, and contiguous
zone waters, and for Great Lakes, coastal waters, ports, and harbors. In
addition, the USCG provides the headquarters site for the National Response
Center (NRG).
1-10
-------
The remaining organizational structure is described in Figure 1-2. Regional
Contingency Plans are maintained at the local District or Regional offices of
the USCG and EPA, as appropriate.
6. HARDWARE REQUIREMENTS - Not applicable.
7. PROCEDURE REQUIREMENTS - Not applicable.
8. DATA REPORTING REQUIREMENTS - The item of primary interest to this
program, which is contained in the National Contingency Plan, is the spill
data reporting requirements. The reporting requirements of this plan are
not definitive nor is there a form or format requirement. Details are left to
the discretion of the Regional or other lower tier plans. The reporting require-
ments are partially described in various parts of the Plan. Figure 1-3 illustrates
the reporting flow which is briefly described in the following paragraphs.
Discovery and notification of spills is subdivided into three categories: report
by discharger, deliberate discovery, and random discovery. In the case of
notification by discharger, the discharger is required to report to designated
Federal Agencies listed in Title 33, Part 153, Subpart B, Code of Federal
Regulations, promulgated by the Coast Guard. In the event of deliberate
discovery, the spill is reported directly to the Regional Response Center (RRC).
Random discoveries are reported to the nearest Coast Guard or EPA Office.
The initial report should be in accordance with the information and format as
described in the Regional Plans. The severity of the spill will determine the
reporting procedure. Regional Plans should specify the reporting procedures
for various areas and, based upon severity as determined by the nature and
quantity of material spilled, the location and resources adjacent to the area.
In general, all spills should be reported to the OSC and the RRC; medium spills
are reported by teletype to the RRC and NRG; while major or potential major
spills are reported to the RRC and NRC by telephone and teletype.
1-11
-------
COUNCIL ON ENVIRONMENTAL QUALITY
NATIONAL CONTINGENCY PLAN
NATIONAL COMMITTEE FOR THE
PREVENTION OF POLLUTION
OF THE SEAS BY OIL
LIASON
NATIONAL RESPONSE TEAM
EPA CHAIRMAN
USCG VICE-CHAIRMAN
(NO OPERATIONAL CONTROL OF OCS)
PRIMARY
FEDERAL
AGE NOES
ADVISORY
FEDERAL
AGE NOES
NATIONAL RESPONSE CENTER
USCG HQ., WASH., D. C.
REGIONAL RESPONSE TEAMS
REGIONAL CONTINGENCY PLANS
EPA AND USCG
REGIONAL RESPONSE CENTERS
(QUARTERS AS DESCRIBED IN
REGIONAL CONTINGENCY PLANS)
SUMEGIONAL, STATE,
LOCAL AND OTHER
RESPONSE TEAMS
Figure 1-2. Organizational Structure for the National Oil and
Hazardous Substances Pollution Contingency Plan
1-12
-------
DISCOVERY
AND
NOTIFICATION
Sf
AGENCY
TO M
NOTIFIED
COORDINATE
REPORTS WITH
FOLLOW-UP
REPORTS
REQUIRED
Figure 1-3. Spill Reporting
1-13
-------
The OSC, upon receipt of report of a spill, evaluates the report to determine
the validity of the report, what action is being taken, and what further action
is needed. The OSC is responsible for determining the following pertinent
information:
Nature and quantity of the material spilled
Source of the spill
Location, direction, and time of travel of the spilled material
Threat to human health, resources, and installations and the priorities
for protecting them
Person reporting the spill is taking appropriate action in accordance with
FWPCA, as amended.
Upon gathering the appropriate information, the OSC reports to the discharger,
State and local officials, and the RRC. As indicated, he recommends activation
of the RRT and NRT and provides periodic situation reports. His reports are
prepared in accordance with the Regional Contingency Plan. The RRTs and NRT
submit pollution reports twice each day. At the conclusion of the Federal
participation activity, the OSC prepares a final report for submission to the
RRT and NRT, whereupon the NRT prepares a final evaluation and makes
recommendations.
9. GENERAL COMMENTS - This document is primarily devoted to organizational
structure, authorities, and responsibilities for responses to spills of oil and
hazardous substances. The essential application of this source document to this
study is the establishment of reporting requirements.
1-14
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REGULATION REVIEW - SUMMARY REPORT
1. TITLE - Code of Federal Regulations Title 33, Part 153 - Control of Pollution
by Oil and Hazardous Substances, Discharge Removal.
2- AGENCY - United States Coast Guard.
3. DATE - Unknown.
4, APPLICABILITY - The navigable waters of the United States, adjoining shore-
lines, or the contiguous zone.
5. ADMINISTRATION AND ENFORCEMENT PROVISIONS - This regulation provides
for delegation of authority granted by the Federal Water Pollution Control Act
and the Water Quality Improvement Act of 1970. The delegations of authority
are as follows:
Secretary of Transportation
Commandant, U. S. Coast Guard
District Commanders, USCG
Any Coast Guard Commissioned, Warrant, and Petty Officer
These persons have delegated authority to enforce the provisions of Section 311
of the Federal Water Pollution Control Act.
6. HARDWARE REQUIREMENTS - Not applicable.
7. PROCEDURE REQUIREMENTS - Not applicable.
8. DATA REPORTING REQUIREMENTS - Subpart B, Notice of the Discharge of Oil,
provides for the reporting of oil discharges as required by the Federal Water
Pollution Control Act and the Water Quality Improvement Act of 1970. Any person
in charge of a vessel or an onshore or offshore facility, as soon as he has know-
ledge of any discharge of oil or hazardous substance from the vessel or facility
is required to give immediate notice by the most expeditious means available
1-15
-------
which includes the use, in order of priority, of telephone, radiotelephone, radio
telecommunication or other means of rapid communications. The report should
be given to any of the following persons:
Commanding Officer or Officer-in-Charge of any Coast Guard unit
in the vicinity.
The Commander of the Coast Guard District in which the discharge occurs.
The Federal Official designated by the Regional Contingency Plan as the
On Scene Coordinator (OSC).
Commandant, U.S. Coast Guard.
Regional Director of the Federal Water Quality Administration (FWQA).
A table of USCG Districts and FWQA regions is provided along with addresses
and telephone numbers.
9. GENERAL COMMENTS - None.
1-16
-------
APPENDIX J
SAFETY SHUTDOWN DEVICES
-------
TABLE OF CONTENTS
Appendix J - Safety Shutdown Devices J-l
J. 1 Introductory Summary J-l
J. 2 Functional Application and Description J-2
J. 2.1 Relationship to Safety Subsystems J-2
J.2.2 Safety Shutdown Subsystem Elements J-2
J. 3 High and Low Pressure Sensing Devices J-4
J. 4 Liquid Level Sensing Devices J-6
J. 5 Surface Safety Valves and Actuators J-6
J. 6 Velocity-Controlled Subsurface Safety Valves J-8
J. 7 Findings J-12
J-ii
-------
LIST OF ILLUSTRATIONS
Figure
J-l Safety Subsystem j-3
J-2 Partial Functional Flow Diagram of a Sample Safety Shutdown
Subsystem j-3
J-3 Estimated Reliability Function for Velocity-Controlled Subsurface
Safety Valves j-11
LIST OF TABLES
Table
J-l. Failure Rate Data for High/Low Pressure Sensors for Production
System Pressure Vessels J-5
J-2 Failure Rate Data for High/Low Pressure Sensors for Pipelines
and Flowlines J-5
J-3 Failure Rate Data for High/Low Liquid Level Sensors for Pressure
and Atmospheric Vessels J-7
J-4 Failure Rate Data for Surface Safety Valves J-7
J-5 Distribution of Velocity-Controlled Subsurface Safety Valve
Malfunctions and Removals by Month and Facility J-9
J-6 Distribution of Velocity-Controlled Subsurface Safety Valve
Malfunctions and Removals by Month and Valve Code J-9
J-7 Distribution of Facility Operation D Codes 1 and 4 Velocity-Controlled
Safety Valve Malfunctions (M) and Removals (R) by Elapsed Time
Since Last Removal J-10
J-8 Distribution of Facility Operation H Codes 1 and 4 Velocity-Controlled
Safety Valve Malfunctions (M) and Removals (R) by Elapsed Time
Since Last Removal J-10
J-9 Reliability Function for Velocity-Controlled Subsurface Safety Valves. J-11
J-iii
-------
APPENDIX J
SAFETY SHUTDOWN DEVICES
J. 1 INTRODUCTORY SUMMARY
The spill prevention program described in this report relies strongly on safety shutdown
devices in the development of spill prevention guidelines. The application of safety shut-
down devices, already commonly employed for pipelines and offshore operations, has
increased for all petroleum systems as a result of new regulations and attention aimed
at reducing petroleum system spillage. Safety shutdown devices primarily have been
applied to offshore Production and Gathering/Distribution Systems to protect against
personnel injury and facility damage in the event of an abnormal system operation or
condition. Additional applications have been made to avoid or reduce the size of oil
spills by total or partial shutdown of the system when spill conditions are detected.
Although the safety shutdown devices are responsible for preventing considerable oil
spillage, their advantage is partially offset by the fact that they also can malfunction and
allow a spill to occur. In particular, high liquid level sensing devices have been identified
in Volume I as a priority spill vulnerability point for a number of offshore production
subsystems. In general, the spill data of Appendix D lacked definitive failure descriptions
on safety shutdown device failures. As a result, additional information was sought.
It was determined that the USGS, through a recently initiated program of safety system
inspections, was developing comprehensive and detailed information which would be useful
to this study. Through the cooperation of the USGS, the study team was provided with an
opportunity to review these data. The findings clarified and substantiated the data of
Appendix D on safety subsystem spills. As a result, the findings contributed to the develop-
ment of the spill vulnerability points and spill prevention guidelines presented in Volume I ,
This appendix provides guidelines on failure rates and inspection requirements for safety
shutdown devices.
J-l
-------
Paragraph J. 2 presents the functional application and description of the safety shutdown
devices studied. Paragraphs J. 3 through J. 6 present the analyses of pressure sensors,
level sensors, surface safety valves, and subsurface safety valves, respectively. The
findings are summarized in Paragraph J. 7.
J. 2 FUNCTIONAL APPLICATION AND DESCRIPTION
J. 2.1 Relationship to Safety Subsystems
As described in Appendix B, the safety subsystems (see Figure J-l) protect facilities,
equipment, personnel, and wells by providing selective or overall shutdown when operating
conditions or parameters exceed previously established limits.
Figure J-l is applicable to both Production and Gathering/Distribution Systems except
for the subsurface safety valves which are used only in Production Systems. The elements
of the safety subsystem which are of interest in this appendix are those associated with
petroleum system shutdown. Those elements include subsurface safety valves and the
elements identified by the functional flow diagram of Figure J-2.
J. 2.2 Safety Shutdown Subsystem Elements to be Considered
Referring to Figure J-2, the elements of interest are further defined as follows:
1. Energy Source and Regulator - The types available use electrical, pneumatic, or
hydraulic energy. The function of the source is to supply the energy required
for surface and subsurface valve control, and for remote control from the
various sensing devices. However, since OCS operations employ pneumatic
systems predominantly, if not entirely, only pneumatic systems are considered.
2. Sensor and Signal Equipment - Sensors include those for detecting pressure,
fire, temperature, and explosive atmosphere liquid level. Of these, considera-
tion is given to high/low pressure sensors and liquid level sensors.
3. Signal Relay Switching Mechanism - This mechanism, also described as a three-
way block and bleed valve, acts as a relay and switch. It is activated by a
pressure signal in the sensor remote control line, and switches or bleeds
J-2
-------
Figure J-l. Safety Subsystem
ENERGY SOURCE
REGULATOR
SUPPLY LINE
SIGNAL RE LAY
SWITCHING
MECHANISM
CONTROL LINE
SENSOR
AND SIGNAL
EQUIPMENT
REMOTE CONTROL
LINE
TO OTHER PRESSURE
*" AND LEVEL SENSING
EQUIPMENT
PRODUCT LINE
SURFACE SAFETY
VALVE AND
ACTUATOR
Figure J-2. Partial Functional Flow Diagram of a Sample Safety Shutdown Subsystem
J-3
-------
pressure from the actuator of the surface safety valve. No data are given on
these mechanisms; consequently, they are not addressed.
4. Surface Safety Valve and Actuator - These valves usually are reverse-acting,
normally closed gate valves with a remote control capability. Although electri-
cal, pneumatic, or hydraulic actuators could be used, only pneumatic actuators
are identified from the data and considered.
The subsurface safety valves (Figure J-l) include those actuated by down-hole velocity
and those which are remotely controlled at the surface. Insufficient data exist concerning
use of the recently developed and installed surface-controlled valves. As a result, only
the velocity type valves are considered.
For all of the devices under consideration, the study is concerned with only those events
in which shutdown should, but does not, occur. Events of false shutdown are not addressed.
J. 3 HIGH AND LOW PRESSURE SENSING DEVICES
USGS data were examined for a group of production facilities selected from high production
fields in Lafayette District Number 2. The data were generated from December 1971
through June 1972. These data summarize the number of pressure sensor operations
during inspections and the number of required pressure resettings, considered as mal-
functions for this study, for a population of 1188 sensors. Data for sensors mounted on
pressure vessels and sensors installed on pipelines or flowlines are presented in Tables
J-l and J-2, respectively.
Pipeline/flowline pressure sensors generally receive their control energy from the pro-
duct line. Since the OCS vessel pressure sensors generally use control energy from
external sources, the data for the two types of sensors were segregated to permit recog-
nition of any resulting differences. By inspection of Tables J-l and J-2, reset rates of
130 and 150 reset actions per 1000 operations are observed. From an engineering stand-
point this difference is considered not to be significant, since each amounts to approximately
one reset for every six operations, or 6 months of operation, assuming monthly inspection
is required. OCS Order Number 8 established specific numerical limits for setting both
J-4
-------
Table J-l. Failure Rate Data for *«6~, * ^~~,
for Production System Pressure Vessels
General
Identification
Field
Location*
S.M.I.
S.M.I.
S.M.I.
E.I.
S.S.
S.S.
S.T.
S.T.
Facility
Operator
B
K
L
L
Q
R
G
H
Subtotals
Pressure Sensors (Pressure Vessels)
Number of Operations
Population
25
12
66
84
112
78
14
33
424
Hi
81
28
553
442
239
196
40
25
1604
Lo
57
28
552
442
217
190
40
25
1551
Sub
Totals
138
56
1105
884
456
386
80
50
3155
Number of Resets
Hi
16
4
59
5
93
42
1
3
223
Lo
13
-
44
4
71
53
-
2
187
Sub
Totals
29
4
103
9
164
95
1
5
410
Resets/1000
Operations
Hi
198
143
107
11
389
214
25
120
139
Lo
228
-
80
9
327
279
-
80
121
Sub
Totals
210
71
93
10
360
246
12
100
130
*S. M. I. - South Marsh Island
E.I. - Eugene Island
S.S. - Ship Shoal
S.T. - South Timbalier
Table J-2. Failure Rate Data for High/Low Pressure Sensors
for Pipelines and Flowlines
General
Identification
Field
Location*
S.M.I
S.M.I.
S.M.I.
E.I.
S.S.
S.S.
S.T.
S.T.
Facility
Operator
B
K
L
L
Q
R
G
H
Subtotals
Pressure Sensors (Pipelines and Flowlines)
Number of Operations
Population
57
8
150
96
175
175
17
86
764
Hi
138
33
1038
93
894
260
41
90
2587
Lo
138
33
1038
93
894
260
41
90
2587
Sub
Totals
276
66
2076
186
1788
520
82
180
5174
Number of Resets
Hi
39
5
70
2
185
69
-
15
385
Lo
42
-
79
1
176
73
1
17
389
Sub
Totals
81
5
149
3
361
142
1
32
774
Resets/1000
Operations
Hi
283
152
67
22
207
265
-
167
149
Lo
304
-
76
11
197
281
24
189
150
Sub
Totals
293
76
72
16
202
273
12
178
150
*S. M. I. - South Marsh Island
E.I. - Eugene Island
S.S. - Ship Shoal
S. T. - South Timbalier
J-5
-------
high and low pressure sensors on pressure vessels. This inspection program and fre-
quency appears to be effective since, according to the spill data in Appendix D, relatively
few spill events are attributed to pressure sensor malfunction or nonfunction.
J. 4 LIQUID LEVEL SENSING DEVICES
The USGS data, selected as described in Paragraph J. 3, summarize the number of liquid
level sensor operations during inspection and the number of required reset actions,
considered as malfunctions for this study, performed for a population of 276 sensors.
The data are presented in Table J-3, which indicates that a low rate of reset action was
performed, i. e., an average of six actions for each 1000 inspections performed. It is
noted, however, that the OCS orders do not specify any criteria for adjustment or reset
of liquid level sensors. These inspections appear to be relatively ineffective from the
standpoint of spill prevention since, according to the spill data of Appendix D, high liquid
level sensors represent one of the most frequently identified items responsible for spills
from offshore Production Systems. Consequently, it is concluded that specifying a maximum
level limit, with adequate consideration to the shut-in delay time, would prevent a number
of high level sensor-associated spill events.
J. 5 SURFACE SAFETY VALVES AND ACTUATORS
The USGS data, selected as described in Paragraph J. 3, summarize the number of surface
safety valve operations during inspections and the number of reset actions, considered as
malfunctions for this study, required for a population of 370 valves. The data are pre-
sented by Table J-4. According to the data, the average reset rate is low (an average of
18 for 1000 inspections performed). The combined effect of the relatively few resets
required and the relative lack of reported spills attributed to the surface safety valves
suggest that the inspection program for the devices has been effective. According to the
data, weekly inspections were performed; relaxation of this inspection frequency might
be considered.
J-6
-------
Table J-3. Failure Rate Data for High/Low Liquid Level Sensors
for Pressure and Atmospheric Vessels
General
Identification
Field
location*
S.M.I.
S.M.I.
S.M.I.
E.I.
S.S.
s.s.
S.T.
S.T.
Facility
Operator
B
K
L
L
Q
R
G
H
Sub-
Totals
Liquid Level Sensors
Number of Operations
Population
30
14
56
65
30
63
10
8
276
Hi
54
50
500
355
24
150
40
8
1181
Lo
40
50
493
296
27
46
28
4
984
Sub
Totals
94
100
993
651
51
196
68
12
2165
Number of Resets
Hi
4
-
5
-
1
-
-
-
10
Lo
-
-
2
-
1
-
-
-
3
Sub
Totals
4
-
7
-
2
-
-
-
13
Resets/1000
Operations
Hi
74
-
10
-
42
-
-
-
8
Lo
-
-
4
-
37
-
-
-
3
Sub
Totals
43
-
7
-
39
-
-
-
6
*S. M. I. - South Marsh Island
E.I. - Eugene Island
S. S. - Ship Shoal
S.T. - South Timbalier
Table J-4. Failure Rate Data for Surface Safety Valves
General Identification
Field
Location*
S.M.I.
S.M.I.
S.M.I.
E.I.
S.S.
S.S.
S.T.
S.T.
Facility
Operator
B
K
L
L
Q
R
G
H
Totals
Surface Safety Valve
Population
27
3
73
50
84
86
8
39
370
Number of
Operations
653
101
1498
810
430
488
127
228
4335
Number of Resets
12
6
20
26
2
9
1
1
77
Resets/1000 Operations
18
59
13
32
5
18
8
4
18
*S. M. I. - South Marsh Island
E.I. - Eugene Island
S.S. - Ship Shoal
S. T. - South Timbalier
J-7
-------
J. 6 VELOCITY-CONTROLLED SUBSURFACE SAFETY VALVES
USGS data on subsurface safety valve inspections from November 1971 through April 1972
were examined for a group of production facilities selected from seven high-volume
production fields.
The data were obtained from semiannual operator reports on subsurface safety valve (SSV)
movements for 127 well completions. The combined data included 317 SSV movements
identified as "removals"which resulted in the detection of 71 malfunctions. These data
are distributed by field and by valve type (expressed as a numerical code to avoid identifi-
cation of manufacturers) as shown in Tables J-5 and J-6, respectively. In this discussion,
only removals are considered. Manfunction is defined for this study as any condition
requiring replacement of parts other than safety valve packing material and includes not
only worn parts, but parts replaced as a result of changed well conditions. Thus, failures
are charged even if the valve itself is operable but requires a different bean size or pressure
setting to restore proper function.
Table J-5 shows the facility operations D and H had the greatest number of subsurface
safety valve malfunctions. Table J-6 shows that subsurface safety valve codes 1 and 4
presented the most significant contribution to the data, since they represented over 80
percent of the movements and 90 percent of the malfunctions in these data.
As a result, Tables J-7 and J-8 were developed to present code 1 and code 4 subsurface
safety valve data from facility operations D and H in terms of the elapsed time (in months)
since last valve removal (opportunity to inspect). It is observed from these tables that,
of 179 total removals, only 34 (less than 20 percent) occurred over 3 months from the last
removal. Out of 35 total failures, 15 (43 percent) of the failures occurred during the same
period. The data in Tables J-7 and J-8 were used to develop the reliability function shown
in Table J-9. This function takes into account that many removals are for reasons other
than subsurface safety valve inspection or maintenance. The valves of cumulative proba-
bility of survival shown in Table J-9 are plotted in Figure J-3 and an approximate curve
of the reliability function drawn to interpret the points. The reliability function of Figure
J-3 indicates that a subsurface safety valve removed 3 months after its last inspection
J-8
-------
Table J-5. Distribution of Velocity-Controlled Subsurface
Safety Valve Malfunctions and Removals by Month and Facility
Facility
Operator
L
D
H
G
K
E
J
Total
Month
Nov.
'R
2
6
16
3
4
4
5
40
M
1
1
2
2
-
-
1
7
Dec.
R
1
8
20
4
4
1
2
40
M
-
1
1
-
-
--
-
2
Jan.
R
4
3
29
6
2
-
3
47
M
-
2
4
1
-
-
-
7
Feb.
R
8
18
16
12
5
2
2
63
M:
1
12
5
3
-
2
-
23
Mar.
R
9
17
22
2
7
7
4
68
M
4
3
4
-
1
3
1
16
Apr.
R"
8
9
24
1
11
3
3
59
M
4
3
2
-
3
2
2
16
Total
R/M
32/10
61/22
127/18
28/6
33/4
17/7
19/4
317/71
Malfunctions peri
1000 Removals
312
361
142
214
121
412
210
224
R = Removal
M = Malfunction
Table J-6. Distribution of Velocity-Controlled Subsurface
Safety Valve Malfunctions and Removals by Month and Valve Code
Subsurface
Valve
Code
1
2
3
4
5
6
7
8
9
10
11
12
Total
Population
53
1
1
49
1
2
1
6
10
1
1
2
127
Month
Nov.
R
10
-
-
20
-
1
1
4
3
1
-
40
M
2
-
-
4
-
-
-
1
-
_
-
7
Dec.
R
16
-
-
18
-
-
1
1
4
_
-
40
M
1
-
-
1
-
-
-
-
-
_
-
2
Jan.
R
20
-
-
22
1
-
-
2
2
_
-
47
M
4
-
-
3
-
-
-
-
-
_
-
7
Feb.
R
27
-
-
30
1
-
-
-
3
1
1
63
M
12
-
-
11
-
-
-
-
-
_
-
23
Mar.
R
26
1
1
25
-
4
-
4
5
-
2
68
M
8
-
-
7
-
-
-
-
1
_
-
16
Apr,
R
30
-
-
17
-
-
-
1
10
-
1
59
' M
7
-
-
5
-
-
-
1
3
-
-
16
Total
129/34
'!/-
l/-
132/31
2/-
5/-
2/-
12/2
27/4
l/-
l/-
4/-
317/71
Malfunctions per
1000 Removals
264
-
-
235
-
-
-
167
370
-
224
R
M
Removal
Malfunction
J-9
-------
Table J-7. Distribution of Facility Operation D Codes 1 and 4 Velocity-Controlled
Safety Valve Malfunctions (M) and Removals (R) by Elapsed Time Since Last Removal
Subsurface
Valve
Code
Code 1
Code 4
Time Since Last Removal (Months)
1
R/M
25/4
10/0
2
R/M
6/1
3/1
3
R/M
2/0
1/0
4
R/M
7/5
6/4
5
R/M
0/0
4/2
6
R/M
0/0
0/0
Total
R/M
40/10
24/7
Table J-8. Distribution of Facility Operation H Codes 1 and 4 Velocity-Controlled
Safety Valve Malfimctions (M) and Removals (R) by Elapsed Time Since Last Removal
Subsurface
Valve
Code
Code 1
Code 4
Time Since Last Removal (Months)
1
R/M
27/6
52/3
2
R/M
4/0
5/3
3
R/M
7/1
3/1
4
R/M
6/2
8/2
5
R/M
0/0
I/O
6
R/M
2/0
0/0
Total
R/M
46/9
69/9
J-10
-------
Table J-9. Reliability Function for Velocity-Controlled Subsurface Safety Valves
Time Interval
Since Last
Removal
(in Months)
0-1
1-2
2-3
3-4
4-5
5-6
Totals
Number of SSVs
Downhole at
Start of Time
Interval
179
65
47
34
7
2
334
Number of Removals
Condition
Good
101
13
11
14
3
2
144
Condition
Discrepant
13
5
2
13
2
0
35
No Inspection
Required
65
47
34
7
2
0
155
Probability of Survival
Interval
.93
.92
.62
.71
1.00
1.00
Cumulative
.93
.86
.82
.51
.36
.36
NOTE :
DATA SOURCE: TABLE J-9
i
12345
ELAPSED TIME SINCE LAST REMOVAL (MONTHS)
Figure J-3. Estimated Reliability Function for Velocity-Controlled
Subsurface Safety Valves
J-ll
-------
would have an estimated probability of 0. 73 of being found in working condition and not to
need repair or replacement parts. This estimated probability drops to 0.26 when the
length of time since last removal is extended to 6 months, the current inspection require-
ment. A change of inspection frequency from 6 to 3 months could reduce to approximately
one-third the expected number of discrepant subsurface safety valves downhole based on
the 6-month inspection interval. From the data in Tables J-7 and J-8, approximately
80 percent of the subsurface safety valves are removed, regardless of reason, within
3 months of the last inspection opportunity. Thus, the preceding reduction in discrepant
valves would require an apparent 20 percent increase of inspection burden. An increase
in subsurface safety valve inspection frequency (possibly in selected areas) should be
considered.
J. 7 FINDINGS
In general, the study of USGS data on safety shutdown devices:
1. Clarified the safety device failures addressed in Volume I
2. Provided gross average failure rates for the safety shutdown devices
addressed in this appendix
3. Substantiated the spill prevention guidelines for safety shutdown devices
presented in Volume I
The following specific findings result from the analysis:
1. The frequency of inspection of pressure sensors is reasonable and effective.
2. The low failure rate exhibited by inspections of the high level sensors,
considering that these sensors are priority spill vulnerability points
addressed in Volume I, is indicative that a maximum high level limit
setting should be required and inspected as it is with pressure sensors.
3. The inspection frequency on surface safety valves should be considered
for possible relaxation.
J-12
-------
4. The inspection frequency of the velocity-controlled subsurface safety
valves should be considered for possible increase from the present
semiannual requirement to a quarterly requirement.
J-13
-------
APPENDIX K
DATA CODE BOOK
-------
TABLE OF CONTENTS
Foreword K-3
Data System Description K-4
Data Codes K-7
Field 1- 4 Spill Report Serial Numbers K-8
Field 5 Associated Failures Code K-9
Field 11-12 Data Source Code K-10
Field 14-15 State Code K-ll
Field 17-30 Location Code K-12
Field 17-30 Alaska Location Code K-13
Field 17-30 California Location Code K-14
Field 17-19 California Oil and Gas Districts K-15
Field 21-30 California Location Code K-17
Field 17-30 Colorado Location Code K-18
Field 17-30 Louisiana Location Code K-19
Field 17-30 Mississippi Location Code K-22
Field 17-30 New Mexico Location Code K-23
Field 17-30 Oklahoma Location Code K-24
Field 17-30 Texas Location Code K-26
Field 17-30 Alberta Location Code K-32
Field 32 Shore Code K-34
Field 33 Lease Code K-35
Field 35-40 Spill Data Code K-36
Field 43-44 Activity Code K-37
Field 46 Product Spilled Code K-38
Field 48-49 Quantity Spilled Code K-39
Field 51-52 Quantity Unrecovered Code K-39
Field 54 Spill Duration Code K-40
K-l
-------
TABLE OF CONTENTS (Cont.)
Field 56
Field 58-59
Field 61-65
Field 66
Field 67
Field 69
Field 71
Field 73
Field 75
Field 77-78
Field 80
Multiple Failures Code K-41
Cause Code K-42
System Code K-45
Pipe Diameter Code K-52
Installation Date Code K-53
Equipment Protection Code K-54
Repair Action Code K-55
Spill Control Method Code K-56
Spill Cleanup Method Code K-57
Cost Code K-58
Violation Code K-59
K-2
-------
FOREWORD
This Data Code Book has been developed by the Reliability and Effectiveness
Assurance Department of Computer Sciences Corporation for use on the Petroleum
Systems Reliability Analysis Program which is being conducted for the Environmental
Protection Agency. Due to the volume of oil spill data that has been accumulated, it
has become necessary to translate the data into a format amenable to machine pro-
cessing. The codes contained within this Data Code Book were adopted to allow the
data (relative to a single oil spill report) to be entered on a standard 80-column IBM
card. A specialized data coding sheet was developed to simplify the coding effort.
Once coded, the data can be evaluated utilizing Automatic Data Processing techniques.
K-3
-------
DATA SYSTEM DESCRIPTION
This Data Code Book forms a key element in the data system established for the
Petroleum Systems Reliability Analysis Program. To provide an understanding of the
use of this book and its importance within the system, a brief description of the data
system is provided here and illustrated in Figure 1.
As oil spills occur within the various jurisdictions of Federal, state, and local
government agencies, reports are generated which provide information regarding the
circumstances of the spills. These reports are accumulated in various locations
throughout the country. Upon receipt at CSC, each spill report is given a unique serial
number for filing purposes. Then, using the codes provided herein, the data contained
within the spill report are coded onto special coding sheets. (See Figure 2.) After the
code sheets have been completed, the original spill reports are filed in serial number
order. The information on the code sheets is entered on punched cards. The code
sheets are filed and the punched cards forwarded to the Computer Facility. The infor-
mation on the punched cards is entered into the Computer File, which is stored on
magnetic discs. The punched cards are filed in spill report serial number order. The
Computer Disc File provides ready access to all available spill report data through
automatic data processing techniques.
K-4
-------
SPILL
REPORT
DATA RELATIVE TO OIL SPILLS
ARE RECEIVED FROM VARIOUS
SOURCES AND ENTERED INTO THE
PROGRAM'S DATA SYSTEM
ASSIGN
SERIAL
NUMBER
1 r
/CODE
DATA
/
FILE
ORIGINAL
SPILL
REPORTS
CODE
SHEETS
KEYPUNCH /
FILE
CODE
SHEETS
^-~1.
PUNCHED
CARDS
UPDATE
COMPUTER
FILE
I FILE
PUNCHED
CARDS
L
\
fMAGN ETIcY-__(
I DISC f* j
DATA NOW AVAILABLE FOR
AUTOMATIC DATA PROCESSING
Figure 1. Oil Spill Data Flow Diagram
K-5
-------
SHEET NO..
DATE
LOCATION CODING
DlfTMlCT
COUNTY
COOC
LEAH NAME
OtOOHAmiCAL CQOftp
orrtHomt ILOCKNO
CITY NAMI
RIV(R, LAKE. IAV
1 t
II
il mwi m
1
g|
ilt
I I
i .
! I 1 I
I t I I
. I
I . 1 . 1 I
I t I I
I 1
, . I ,
I I I
I t I I
I I
I 1
III
I I
I I
i I
I . . I I I I .
III
i i I
10
. I
. I
. 1
I i
I i
1 ,
14
I I I ., I 1 I I 1 I I
13
JS.
. I
, I .... I
. 1
I I
I . .
, I .
. I
19
. I .
. I
. I
ZO
I i
i I
I I
21
I I
I .
i I
I i
I I ... I .
r.l
24
-i I i
25
i I
I I
I!
I I I
Figure 2. Special Purpose
Coding Sheet
-------
DATA CODES
The requirement to enter a large quantity of data on a single, 80-column
punched card dictated that short alphanumeric codes be utilized. The various data
items to be recorded on the punched cards were reviewed and a system of codes
devised. These codes, the fields (columns) in which they are to be used, the data
item they represent, and a brief discussion of their utility are provided in the follow-
ing paragraphs and tables.
The field numbers (in numerical sequence) and code titles are shown at the top
right corner of each page to facilitate the use of this code book.
K-7
-------
FIELD 1-4
SPILL REPORT SERIAL NUMBERS
Each oil spill event is assigned a unique serial number to identify it for record
and reference purposes. This serial number is written on each document which
reports the details of an oil spill in Field 1-4 of the code sheet. The serial numbers
range from 0001 to 9999, each entry being right justified and zero filled; that is, fill-
ing the field. Blocks of serial numbers were initially assigned for coding purposes
(gaps intentional) as follows:
Serial Number
0001-5373
6000-6125
6126-6986
7000-7425
7426-8185
8186-8247
8248-8482
8483-8596
8600-8802
9000-9769
Data Source
Texas RR Commission
EPA Headquarters - OHM File
DOT/FRRC
U. S. Geological Survey
Louisiana Conservation Commission
EPA Anchorage, Alaska
Alberta
U. S. Geological Survey
Mississippi
California, New Mexico, Oklahoma
and Colorado
K-8
-------
FIELD 5
ASSOCIATED FAILURES CODE
Some oil spills involve simultaneous or sequential failures which contribute to
that single event. In order to indicate all failures associated with a single oil spill
event, a separate coded card is prepared for each failure. On each of these cards the
serial number of the spill event is repeated and a code is added in Field 5. All common
data is then repeated on each card with only the codes associated with the failed item,
cause, et cetera being different. On cards for spill events caused by only one failure,
Field 5 is left blank.
Code
0
I
2
Meaning
First Failure
Second Failure
Third Failure
Ninth Failure (or more)
K-9
-------
FIELD 11-12
DATA SOURCE CODE
Reports of oil spill events are derived from a number of sources. The data
source code identifies the origin of the documentation which provides the information
on the oil spill event. The data source code assignments are:
Code Data Source
01 EPA Headquarters - OHM File
02 EPA Anchorage, Alaska
03 ALBERTA - Drilling and Production
Monthly Pollution Summaries
04 DOT/FRRC - Pipeline Carrier Accident
Reports
05 TEXAS RR Commission
06 U. S. Coast Guard
07 U. S. Geological Survey
08 ALASKA - Department of Conservation
09 LOUISIANA - Conservation Commission
10 CALIFORNIA F&G
11 CALIFORNIA WQCB
12 CALIFORNIA O&G Division
13 CALIFORNIA Long Beach
14 CALIFORNIA Western O&G
15 NEW MEXICO O&G
16 OKLAHOMA Corporation Commission
17 MISSISSIPPI
18 ALBERTA, Edmonton (Pipeline only)
19 COLORADO
20 ARKANSAS
K10
-------
FIELD 14-15
STATE CODE
Petroleum production and gathering/distribution is nationwide. In anticipation of
oil spill events being reported from any location, a code is assigned for each State of
the United States. Since data were also available from Alberta, Canada, a code was
assigned for that Province. The State Code is assigned in recognition of the variations
from one jurisdiction to another in policies, codes, rules, and practices relating to
the petroleum industry, including the regulation and control of oil spill events.
The code numbers are assigned to correspond to the States as follows:
Code State Code
01 ALABAMA 19
02 ALASKA 20
03 ARIZONA 21
04 ARKANSAS 22
05 CALIFORNIA 23
06 COLORADO 24
07 CONNECTICUT 25
08 DELAWARE 26
09 FLORIDA 27
10 GEORGIA 28
11 HAWAII 29
12 IDAHO 30
13 ILLINOIS 31
14 IOWA 32
15 INDIANA 33
16 KANSAS 34
17 KENTUCKY 35
18 LOUISIANA 36
State Code
MAINE 37
MASSACHUSETTS 38
MARYLAND 39
MICHIGAN 40
MINNESOTA 41
MISSISSIPPI 42
MISSOURI 43
MONTANA 44
NORTH CAROLINA 45
NORTH DAKOTA 46
NEBRASKA 47
NEVADA 48
NEW HAMPSHIRE 49
NEW JERSEY 50
NEW MEXICO 51
NEW YORK 52
OHIO
OKLAHOMA
State
OREGON
PENNSYLVANIA
RHODE ISLAND
SOUTH CAROLINA
SOUTH DAKOTA
TENNESSEE
TEXAS
UTAH
VIRGINIA
VERMONT
WASHINGTON
WISCONSIN
WEST VIRGINIA
WYOMING
ALBERTA, CANADA
NOT IDENTIFIABLE
K-ll
-------
FIELD 17-30
LOCATION CODE
Building upon the State location established in Field 14-15, further refinement
is needed to uniquely identify an oil spill event. Most oil-producing states have a
Commission or Conservation Board which regulates the industry; many have estab-
lished districts, county, oil field, or other geographical reference for administration
of petroleum production. Oil spiU events are reported in accordance with the location
reference imposed by State regulation. The code, therefore, provides unique location
identification of oil spills. Anticipating the major sources of data on oil spill events
and their location, codes have been assigned for Alaska, Alberta, California,
Colorado, Louisiana, New Mexico, Oklahoma, and Texas, including offshore areas,
where appropriate.
Certain data banks are on a national basis and some data does not include detailed
location information for all states. These sources, namely, EPA Headquarters,
DOT/FRRC, and USGS, cover 43 States. The coding for states not listed above
usually refers to the location by naming the county within the State where the oil
spill event occurred. Where location codes have been established, the applicable
events from the national data banks are coded in accordance with the local scheme.
Because of the unique nature of reporting data in each State, an explanation of
location coding immediately precedes the code list for each of the above States.
K-12
-------
FIELD 17-30
ALASKA LOCATION CODE
It appears fairly definite that no data on oil spill events would be obtained from
operations on the Alaskan North Slope, Prudhoe Bay. Hence, the appropriate code in
Field 17-18 is used to locate oil spill events to the Swanson River Field or to the
various fields in and near Cook Inlet.
Current petroleum production is concentrated in the Cook Inlet and surrounding
area.
Specific codes have not been included here so that proprietary rights are
protected, in accordance with previous agreements.
K-13
-------
FIELD 17-30
CALIFORNIA. LOCATION CODE
In California, the Oil and Gas Commission has divided the state into six oil and
gas districts. A three-digit number code is used to identify the district and county
within the district; these three digits occupy Field 17-19 on the coding sheet. Further
refinement of location is given by entries in Field 21-30; one of three generalized
categories is used in "placing" the spill, namely, in preferred order:
1. Oil Fields
2. Cities
3. Physiographic features (rivers, canyons) and generalized geographical-
geological areas (Los Angeles Basin, Hollywood Hills, etc.).
Unless the data bank names a specific oil field as the origin of the spill, city
codes are used, when possible, to locate the incidents. Therefore, the city codes
include spills at docks and wharfs and those of unknown origin (i. e., ran out of storm
drain) which were first observed on waters under the city's jurisdiction. When spill
locations are vague, generalized geographical descriptions are used.
The location code for Field 21-30, which covers the recorded events, follows
the listing of the codes for Field 17-19.
K-14
-------
FIELD 17-19
CALIFORNIA OIL AND GAS DISTRICTS
DISTRICT 1
DISTRICT 5
Code
101
102
103
104
105
106
County
Imperial
Los Angeles
Orange
Riverside
San Bernardino
San Diego
DISTRICT 2
Code
201
County
Ventura
DISTRICT 3
Code
301
302
303
304
305
306
County
Monterey
San Benito
San Luis Obispo
Santa Barbara
Santa Clara
Santa Cruz
DISTRICT 4
Code
401
402
403
County
Kern
Tulare
Inyo
Code
501
502
503
504
505
506
507
508
County
Fresno
Kings
Madera
Mariposa
Merced
Mono
Stanislaus
Toulumne
DISTRICT 6
Code
601
602
603
604
605
606
607
608
609
610
611
612
613
614
County
Alameda
Alpine
Amador
Bulte
Calaveras
Colusa
Contra Costa
Del Norte
El Dorado
Glenn
Humboldt
Lake
Las sen
Mar in
K-15
-------
DISTRICT 6 (Cont'd)
Code
615
616
617
618
619
620
621
622
623
624
625
626
627
628
629
630
631
632
633
634
County
Mendocino
Modoc
Napa
Nevada
Placer
Plumas
Sacramento
San Francisco
San Joaquin
San Mateo
Shasta
Sierra
Siskiyou
Solano
Sonoma
Sutter
Tehama
Trinity
Yolo
Yuba
FIELD 17-19
CALIFORNIA OIL AND GAS DISTRICTS
(Cont'd)
OFFSHORE AREAS
Code Name
Oil State Waters
012 Federal Waters
013 City Jurisdiction
Waters
K-16
-------
FIELD 21-30
CALIFORNIA LOCATION CODE
CODE
CARQUINEZ
HOLLYWDHLS
LABASIN
MADRONOCRK
MORROBAY
SALINASRIV
SNACLARARV
TERMINALIS
VENTURAAVE
WILEYCANYN
GENERALIZED GEOGRAPfflC LOCATION
Carquinez Straits, near San Francisco
Bollywoods Hills, north of Los Angeles
Unspecified locations within Los Angeles
Basin (Geologic Feature)
Madrono Creek, near Ventura
Morro Bay, near San Luis Obispo
Salinas River, near Salinas
Santa Clara River, near Castaic Junction
Terminal Island, Long Beach
Ventura Avenue, within northern suburbs
of Los Angeles
Wiley Canyon, near Newhall
K-17
-------
FIELD 17-30
COLORADO LOCATION CODE
The Oil and Gas Commission of Colorado has not divided the state into districts.
Since the data refers to counties, a three-digit number code is used for entry in Field
17-19. When given, geographical coordinates will be entered in Field 21-30.
Code
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
County
Adams
Alamosa
Arapahoe
Archuleta
Baca
Bent
Boulder
Chaff ee
Cheyenne
Clear Creek
Conejos
Costilla
Crowley
Custer
Delta
Denver
Dolores
Douglas
Eagle
Elbert
El Paso
Code
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
County
Fremont
Garfield
Gilpin
Grand
Gunnison
Hinsdale
Huerfano
Jackson
Jefferson
Kiowa
Kit Carson
Lake
La Plata
Larimer
Las Animas
Lincoln
Logan
Mesa
Mineral
Moffat
Monte zuma
Code
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
County
Montrose
Morgan
Otero
Ouray
Park
Phillips
Pitkin
Prowers
Pueblo
Rio Blanco
Rio Grande
Routt
Saguche
San Juan
San Miguel
Sedgwick
Summitt
Teller
Washington
Weld
Yuma
K-18
-------
FIELD 17-30
LOUISIANA LOCATION CODE
The Conservation Commission of Louisiana has divided the State into six districts.
All petroleum information, incident to petroleum production, is routed via an appro-
priate district office. Since a great deal of petroleum industry activity takes place off
the Louisiana coast, the Conservation Commission has assigned area names and block
numbers within a given area.
Three-digit number codes are used for each district, for parishes within districts,
and for each of the Louisiana offshore areas. Since all offshore oil spill events are
reported to the appropriate (nearest) onshore parish, only district and parish codes
are entered in Field 17-19. Further location refinement of an offshore spill event
is accomplished by entry of the three-digit offshore area code in Field 21-12, the
letters BLK in Field 24-26, and the one-, two- or three-digit block number in Field
28-30.
For onshore spill events, location is sufficiently pinpointed by entry of the oil
field name in the Field 21-30.
LOUISIANA PARISHES BY CONSERVATION DISTRICTS
SHREVEPORT DISTRICT SHREVEPORT DISTRICT (Cont'd)
Code Parish Code Parish
101 Bienville 111 Vernon (north)
102 Bossier 112 Webster
103 Caddo 113 Winn
104 Claiborne MONROE DISTRICT
105 DeSoto
Code Parish
106 Jackson
107 Lincoln 201 Avoyelles (north)
108 Natchitoches 202 Caldwell
109 Red River 203 Catahoula
110 Sabine 204 East Carroll
K-19
-------
FIELD 17-30
LOUISIANA LOCATION CODE
(Cont'd)
LOUISIANA PARISHES BY CONSERVATION DISTRICTS (Cont'd)
MONROE DISTRICT (Cont'd)
Code Parish
205 Franklin
206 Grant
207 La Salle
208 Madison
209 Morehouse
210 Ouachita
211 Rap ides (north)
212 Richland
213 Union
214 West Carroll
215 Concordia
216 Tennas
LAKE CHARLES DISTRICT
Code Parish
301 Allen
302 Beauregard
303 Calcasieu
304 Cameron
305 Jefferson Davis
306 Vernon (south)
LAFAYETTE DISTRICT
Code Parish
401 Acadia
402 Avoyelles (south)
403 Evangel ine
404 Iberia
405 Iberville (northwest)
406 Lafayette
407 Pointe Coupee
408 Rapides (south)
409 St. Landry
410 St. Mary
411 St. Martin (west)
412 Vermaiion
HOUMA DISTRICT
Code Parish
501 Ascension (south)
502 Assumption
503 Iberville (south)
504 Lafourche
505 St. Charles
506 St. James
507 St. John the Baptist
508 St. Martin (east)
509 Terrebonne
K-20
-------
FIELD 17-30
LOUISIANA LOCATION CODE
(Coat'd)
LOUISIANA PARISHES BY CONSERVATION DISTRICTS (Cont'd)
NEW ORLEANS DISTRICT LOUISIANA OFFSHORE AREAS (Cont'd)
Code Parish
601 Ascension (north)
602 East Baton Rouge
603 East Feliciana
604 Iberville (northwest)
605 Jefferson
606 Livingston
607 Orleans
608 Plaquemines
609 St. Bernard
610 St. Helena
611 St. Tammany
612 Tanygipachoa
613 Washington
614 West Baton Rouge
615 West Feliciana
LOUISIANA OFFSHORE AREAS
Code Name
Oil West Cameron
012 East Cameron
013 Vermilion
014 South Marshall Island
015 Rabbit Island Dome
016 Eugene Island
017 Ship Shoal
Code Name
018 Bay Marchand
019 South Timbalier
020 South Pelto
021 Grand Isle
022 West Delta
023 South Pass
024 Main Pass
025 Breton Sound
026 Chandeleur Sound
027 State Lease 340
K-21
-------
FIELD 17-30
MISSISSIPPI LOCATION CODE
The county name is the best information available for fixing the location of
oil spills in Mississippi. Hence, the code for Mississippi, entered in Fielf 17-30
on the coding sheet, is the county name. If the county name is not given, the name
of the oil field may be entered, if available.
K-22
-------
FIELD 17-30
NEW MEXICO LOCATION CODE
The New Mexico Oil Conservation Commission has divided the state into four
districts. A three-digit number code is used to identify location to counties by dis-
tricts. This code is entered hi Field 17-19. Oil spills are reported by geographical
coordinates, which are entered in Field 21-30 as a refinement of the location of the
event.
DISTRICT 1
DISTRICT 4
Code
101
102
103
104
Code
201
202
203
204
205
206
Code
301
302
303
304
County
Chaves
Curry
Lea
Roosevelt
DISTRICT 2
County
Chaves
De Boca
Dona Ava
Eddy
Lincoln
Otero
DISTRICT 3
County
McKinley
Rio Arriba
Sandoval
San Juan
Code
401
402
403
404
405
406
407
408
409
410
411
412
413
414
415
416
417
418
County
Bernalillo
Catron
Coif ax
Grant
Guadalupe
Harding
Hildalgo
Luna
Mora
Quary
San Miguel
Santa Fe
Sierra
Socorro
Taos
Torrance
Union
Volencia
K-23
-------
FIELD 17-30
OKLAHOMA LOCATION CODE
The Oil and Gas Conservation Division of the Oklahoma Corporation Commission
has divided the State into four districts and established a statewide geographical grid.
Oil spill events are located and reported in accordance with this grid. A three-digit
number code is used to fix location by district and county; this code fills Field 17-19
on the coding sheet. The geographical coordinates of the oil spill events are coded in
Field 21-30.
DISTRICT 1
Code
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
County
Adair
Cherokee
Craig
Creek
Delaware
Kay
Lincoln
Mayes
Muskogee
Noble
Nowata
Okfuskee
Okmulgee
Osage
Ottawa
Pawnee
Payne
Rogers
Tulsa
DISTRICT 1 (Cont'd)
Code
120
121
County
Wagoner
Washington
DISTRICT 2
Code
201
202
203
204
205
206
207
208
209
210
211
212
213
214
County
Alfalfa
Beaver
Blaine
Canadian
Cimarron
Custer
Dewey
Ellis
Garfield
Grant
Harper
Kingfisher
Logan
Major
K-24
-------
FIELD 17-30
OKLAHOMA LOCATION CODE
(Cont'd)
DISTRICT 2 (Cont'd)
DISTRICT 4
Code
215
216
217
218
219
Code
301
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
318
319
County
Oklahoma
Roger Mills
Texas
Woods
Woodward
DISTRICT 3
County
Beckham
Caddo
Carter
Cleveland
Comanche
Cotton
Garvin
Grady
Greer
Harmon
Jackson
Jefferson
Kiowa
Love
McClain
Murray
Stephens
Tillman
Washita
Code Ci
401 A1
402 B:
403 C
404 C'
405 H
406 H
407 J(
408 L
409 L
410 M
411 M
412 M
413 P
414 P'
415 P'
416 P
417 S<
418 Se
County
Choctow
Coal
Haskell
Hughes
Johnston
Latimer
Le Flore
McCurtain
Mclntosh
Marshall
Pittsburh
Pontotoc
Pottawatomie
Pushmataha
Seminole
Sequoyah
K-25
-------
FIELD 17-30
TEXAS LOCATION CODE
The Texas Railroad Commission, Oil and Gas Division, has divided the state
into 12 districts and has designated off-shore locations by name and block number.
A three-digit number code is used to locate the district and county. This code is
entered in Field 17 - 19 on the coding sheet. The pertinent oil field name is entered
in Field 20 - 30.
Crude oil activity off-shore Texas during the 1970-71 period was not sufficient
to study. Hence, no off-shore codes are provided.
DISTRICT 1
Code
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
County
DISTRICT 1 (Cont'd)
Code
County
Atacosca
Bandera
Bastrop
Bell
Bexer
Blanco
Burnet
Caldwell
Comal
Dummit
Edwards
Frio
Gillespie
Gonzales
Guadalupe
Hays
Kendall
Kerr
Kinney
120
121
122
123
124
125
126
127
128
129
130
131
132
133
201
202
203
La Salle
Llano
Mason
Maverick
Me Mullen
Medina
Milam
Real
Travis
Ulvalde
Val Verde
Williamson
Wilson
Zavala
DISTRICT 2
Bee
Calhoun
DeWitt
K-26
-------
DISTRICT 2 (Cont'd)
FIELD 17-30
TEXAS LOCATION CODE
(Cont'd)
DISTRICT 3 (Cont'd)
Code
204
205
206
207
208
209
210
Code
301
302
303
304
305
306
307
308
309
310
311
312
313
314
315
316
317
County
Goliad
Jackson
Karnes
Lavaca
Live Oak
Refugio
Victoria
DISTRICT 3
County
Austin
Brazoria
Brazos
Burleson
Chambers
Colorado
Fayette
Fort Bend
Galveston
Grimes
Hardin
Harris
Jasper
Jefferson
Lee
Liberty
Madison
Code
318
319
320
321
322
323
324
325
326
327
328
329
Code
401
402
403
404
405
406
407
408
409
410
411
412
County
Matagorda
Montgomery
Newton
Orange
Polk
San Jacinto
Trinity
Tyler
Walker
Waller
Washington
Wharton
DISTRICT 4
County
Aransas
Brooks
Cameron
Duval
Hidalgo
Jim Hogg
Jim Wells
Kenedy
Kleberg
Nueces
San Patricio
Starr
K-27
-------
DISTRICT 4 (Cont'd)
Code
County
FIELD 17-30
TEXAS LOCATION CODE
(Cont'd)
DISTRICT 5 (Cont'd)
Code
County
413
414
415
Code
501
502
503
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
Webb
Willacy
Zapata
DISTRICT 5
County
Bosque
Collin
Dallas
Delta
Ellis
Falls
Fannin
Freestone
Henderson
Hill
Hopkins
Hunt
Johnson
Kaufman
Lamaer
Leon
Limestone
Navarro
Me Lennan
Rains
Robertson
522
523
524
Code
601
602
603
604
605
606
607
608
609
610
611
612
613
614
615
616
617
618
619
620
621
Rockwell
Tarrant
Van Zandt
DISTRICT 6
County
Anderson
Angelina
Bowie
Camp
Cass
Cherokee
Franklin
Gregg
Harrison
Houston
Marion
Morris
Nacogdoches
Panola
Red River
Rusk
Sabine
San Augustine
Shelby
Smith
Titus
K-28
-------
DISTRICT 6 (Cont'd)
FIELD 17-30
TEXAS LOCATION CODE
DISTRICT 7 C °n
Code
622
623
701
702
703
704
705
706
707
708
709
710
711
m n
712
713
714
715
716
717
718
719
720
721
722
723
724
County
Upshur
Wood
DISTRICT 7
Brown
Callahan
Coleman
Comanche
Coryell
Eastland
Erath
Fisher
Hamilton
Haskell
Hood
Jones
Lampasas
Mills
Nolan
Palo Pinto
Parker
San Saba
Shakelford
Somervell
Stephens
Stonewall
Taylor
Throckmorton
Code
750
751
752
753
754
755
756
757
758
759
760
761
762
763
Code
801
802
803
804
805
806
807
808
809
810
County
Coke
Concho
Crockett
Irion
Kimble
McCulloch
Menard
Reagan
Runnels
Schleicher
Sutton
Terrell
Tom Green
Upton
DISTRICT 8
County
Andrews
Brewster
Crane
Culberson
Ector
El Paso
Glassock
Howard
Hudspeth
Jeff Davis
K-29
-------
DISTRICT 8 fCont'dl
FIELD 17-30
TEXAS LOCATION CODE
DISTRICT 8 A (Cont'd) (Cont'd>
Code
811
812
813
814
815
816
817
818
819
820
Code
850
851
852
853
854
855
856
857
858
859
860
861
862
863
County
Loving
Martin
Midland
Mitchell
Pecos
Presidio
Reeves
Sterling
Ward
Winkler
DISTRICT 8 A
County
Bailey
Bordon
Cochran
Cottle
Crosby
Dawson
Dickens
Floyd
Gaines
Garza
Hale
Hockley
Kent
King
Code
864
865
866
867
868
869
870
Code
901
902
903
904
905
906
907
908
909
910
911
912
913
914
915
County
Lamb
Lubbock
Lynn
Motley
Scurry
Terry
Yoakum
DISTRICT 9
County
Archer
Baylor
Clay
Cooke
Denton
Foard
Grayson
Hardenmn
Jack
Knox
Montague
Wichita
Wilbarger
Wise
Young
K-30
-------
DISTRICT 10
Code County
950 Armstrong
951 Briscoe
952 Carson
953 Castro
954 Childress
955 Collingsworth
956 Dallam
957 Deaf Smith
958 Donley
959 Gray
960 Hall
961 Hansford
962 Hartley
963 Hemphill
964 Hutchinson
965 Lipscomb
966 Moore
967 Ochiltree
968 Oldham
969 Farmer
970 Potter
971 Randall
972 Roberts
973 Sherman
974 Swisher
975 Wheeler
FIELD 17-30
TEXAS LOCATION CODE
(Cont'd)
K-31
-------
FIELD 17-30
ALBERTA LOCATION CODE
The Canadian Province of Alberta is divided into five areas. It is further
divided in the north/south direction by meridians 4, 5, and 6 and still further sub-
divided into an east/west and south/north grid. In addition, oil fields are named.
All oil spill events in Alberta are reported using this system to identify the location.
For coding purposes, a system has been devised to utilize the Canadian grid system.
The code consists of a six-digit code followed by the oil field name.
The first digit to be entered in Field 17 indicates the involved area of the five
major areas in ALBERTA, as determined by the Oil and Gas Conservation Board.
Code Area
1 Edmonton
2 Drayton Valley
3 Red Deer
4 Black Diamond
5 Medicine Hat
The remaining series of numbers are geographical coordinates, which are
measured from east to west and from south to north. The first coordinate number, to
be entered in Field 18, is one of the three digits, 4, 5, or 6, indicating that meridian to
the west of which the spill occurred; the 4th meridian coincides with the eastern lon-
gitude boundary of Alberta. The next two digits, to be entered in Field 19-20, indicate
the range to the west of the pertinent meridian (4, 5, or 6); these digits will be
between 01-30. The meridian and range numbers constitute a "longitude" measure.
The next digits (1, 2, or 3) indicates the township number measured from the southern
boundary of Alberta; this number provides a "latitude" measure of the location and
will be between 1-126.
K-32
-------
FIELD 17-30
ALBERTA LOCATION CODE
(Cont'd)
An example of coding an oil spill at Redwater follows:
Code Meaning
1 Edmonton Area
4 West of 4th Meridian
21 Range, Block 21 Measured West of 4th
Meridian
57 Township, Block 57 North of Southern
Boundary of Alberta
Hence, the code goes: 142157 REDWATR. The name of the field is abbreviated
to fit the remaining available spaces. The "name" shall be coded the same for all inci-
dents reported against that particular field.
K-33
-------
FIELD 32
SHORE CODE
A major division in the petroleum industry is represented by onshore versus off-
shore production. The governing laws and regulations are different in each case; fac-
tors such as the types of equipment and the configuration of wells, vary to a large degree.
Offshore is interpreted to mean the seaward areas outside the low tide mark of the
coasts of the United States. Onshore is interpreted to mean the land territory of the U. S.
inside the low tide mark and including lakes and rivers.
The shore code is as follows:
Code Definition
1 On-shore
2 Off-shore
K-34
-------
FIELD 33
LEASE CODE
Petroleum production is controlled under a variety of lease arrangements. It
is considered pertinent to the study to note under what type of lease the crude oil pro-
duction occurred. Accordingly, the following lease code is used:
Code Lease
1 Federal
2 State
3 Indian Land
4 Canadian
5 Private
6 Cannot Be Determined
7 Pipeline
K-35
-------
FIELD 35-40
SPILL DATE CODE
For each identified oil spill event it is necessary not only to locate where it
occurred but also to note the time of occurrence. It is considered that recording the
year, month, and day is adequate for the study. Sorting of data is facilitated by
ordering from left to right: (1) last two digits of the year, (2) two digits for the
month, and (3) two digits for the day of the month. Each entry shall completely
fill this data field using zeros as appropriate for the months and days having less
than two digits in normal representation.
The spill date code is to be entered in accordance with the following illustration:
35
36
Year
Y
Y
37
38
Month
M
M
39
40
Day
D
D
K-36
-------
FIELD 43-44
ACTIVITY CODE
The petroleum industry activities compiled in this study are divided into gathering/
distribution, production (each of which include some storage activity), and Drilling.
To support some analyses, it was considered appropriate to further subdivide these
activities as indicated by the following activity codes:
Code Activity
01 Normal Operation (Details unknown)
02 Normal Operation-Tended
03 Normal Operation-Untended
04 Normal Operation-Automatic
05 Preventive Maintenance
06 Unscheduled Repair/Maintenance
07 Test and Inspection
08 Installation
09 Wireline Operation
Xi Not Reported
12 Completion
13 Workover
14 Abandoned
15 Water Injection
K-37
-------
FIELD 46
PRODUCT SPILLED CODE
It may be desirable to evaluate events of interest, other than crude oil spills,
related to petroleum production. To verify that a particular oil spill event involves
crude oil and to distinguish the other products that may be coded in an event worthy
of note. The following product spilled code is provided:
Code Product Spilled
1 Crude Oil
2 Water
3 Gas
4 Refined Petroleum Products
5 LPG
6 Condensate
7 Other Hazardous Material
8 Not Specified
K-38
-------
FIELD 48-49
QUANTITY SPILLED CODE
FIELD 51-52
QUANTITY UNRECOVERED CODE
Spills are classified as minor (less than 100 gallons); moderate (100-10,000
gallons); or major (10,000 or more gallons). However, the quantity is usually
more closely estimated for most spill events and it is considered appropriate to
reflect this by subdividing these three major categories. Therefore, certain
ranges within each category have been adopted to refine the classification of data
as regards quantity spilled. In many spill events much oil is recovered, leaving
a quantity of unrecovered oil. A measure of the environmental impact is the quan-
tity of unrecovered oil. As a result, in addition to the quantity spilled, it was
decided to code the quantity unrecovered to provide that measure of environmental
impact.
The oil industry uses barrels as its unit of measure; therefore, this measure
was adopted as the unit of measure to be recorded by coding. One barrel equals 42
gallons.
The quantity code is used to report the spills and the unrecovered crude oil are:
Code Minor Spill (BBLS) Code Major Spill (BBLS)
01
02
0 -1.0
1.1 -2.5
Code Moderate Spill (BBLS)
13
14
15
2.6- 10
11 - 100
101 - 238
25 239 - 500
26 501 - 1,000
27 1,001 - 5,000
28 5,001 - 10,000
29 10,001 or more
Code
41 Not Reported
42 Cannot be Determined
(Data Ambiguous)
K-39
-------
FIELD 54
SPILL DURATION CODE
The spill duration code indicates the length of time, in hours, that the pollutant
was flowing into the environment. Lengthy spills detract from the satisfactory
operating time of the petroleum system, indicate maintainability problems, and
give an indication of the adequacy of inspection and monitoring practices. For
analysis of failures, the duration of the spill events is deemed important. Accordingly,
the following spill duration code is used:
Code Hours
1 0-6
2 7-12
3 13-18
4 19-24
5 25-48
6 49-72
7 73-96
8 Over 96
9 Not Reported
K-40
-------
FIELD 56
MULTIPLE FAILURES CODE
The reported cause of an oil spill event may be simple or compound. A sequence
of events may be involved in which several systems or equipments contribute to a
series of failures or there may have been only a single failure. When multiple failures
are reported for an oil spill event, multiple line entries are prepared containing
unique information for each failure. This code identifies each such record and is
related to the entry in Field 5.
The multiple failure code is:
Code Description
1 Multiple Failures
2 No Multiple Failures
3 Possible Multiple Failures But
Cannot Tell From Data
K-41
-------
FIELD 58-59
CAUSE CODE
Information of varying degrees of completeness is reported in connection with
oil spill events. From this information the cause may be assessed. A 2-digit code
system is used to record these causes. The code selected should reflect the cause
of the equipment or system failure and answer the question "How did it fail?", not
"What failed?" The code has been structured to reflect a variety of causes reported.
For example, it may have been reported that a person was responsible; in another
case that it was an environmental factor; or another, that the equipment was deficient
in some respect. The causes have been grouped in major categories, as listed below.
Code Major Cause
01-03 Unknown
04 Blowout
10-39 & Al Equipment Failure
40-55 Operator/Maintenance Error
90-99 Third Party
70-81 Natural Causes
60-64 Engineering Error
These categories have been further refined in the following lists. The
cause which most nearly reflects the primary cause stated in the spill report
should be selected and entered in Field 58-59.
K-42
-------
Code Cause
01 Unknown
02 No Malfunction
03 Not Reported
04 Blowout (Well Blew)
10 Equipment Failure
11 Binding
12 Broken
13 Burned
14 Burst/Ruptured/Split
15 Corroded
16 Corroded, Externally
17 Corroded, Internally
18 Cut, Flow
19 Cut, Sand
20 Defect, Material
21 Electrical Malfunction
22 Failure Opened
23 Failure Closed
24 Frozen & Burst
25 Hole
26 Leaking
27 Lost Instrument Gas
28 Manufacturer's Defect
29 Missing Hardware
30 Non Functioning
FIELD 58-59
CAUSE CODE
(Cont'd)
Code Cause
10 Equipment Failure
31 Overflowed
32 Overpressure
33 Parted, Line or Union
34 Plugged
35 Power Loss, Electrical
36 Sanded Up
37 Seized/Jammed
38 Vibration
39 Weld, Defective
Al Worn
40 Operator/Maintenance Error
41 Adjustment or Alignment,
Improper
42 Application, Wrong
43 Assembled, Improperly
44 Deactivated or Removed
(for Maintenance, Modifica-
tion, or Test)
45 Handling Damage
46 Installation, Improper
47 Left Closed
48 Left Open
49 Lubrication, Improper
50 Maintenance, Improper
51 Operation, Incorrect
K-43
-------
FIELD 58-59
CAUSE CODE
(Cotit'd)
Code
40
52
53
54
55
6/»
61
62
63
64
7JE)
71
72
73
74
75
76
77
78
79
8*
81
82
83
Cause
Operator/Maintenance Error
Pressure, Deficient
Pressure, Over
Safety Violation
Tools, Faulty or Improper
Engineering Error
Design
Application
Layout
Unstable Adjustment
Natural Causes
Earthquake
Fire
Flood
Rain
Ice Floes
Landslide
Lightning
Marine Growth
Temperature
Ice & Snow
Wind, High
Well Kicked
Well Flowed
Code Cause
90 Third Party
91 Boat Anchor
92 Collision
93 Farm Machinery
94 Foreign Object Damage
95 Live Stock
96 Road Machinery
97 Unknown
98 Valve Was Opened/ Closed
99 Vandalism
K-44
-------
FIELD 61-65
SYSTEM CODE
For this study, Crude Oil Systems are divided into three basic system group-
ings; Drilling, Gathering/Distribution, and Production. The latter two include a
storage function. Study of the functional configuration of each of these systems has
led to the designation of subsystems, equipment within subsystems, and generic com-
ponents that appear likely to be associated with anticipated equipment failures or
problems.
The system code is designed to report the system, subsystem, equipment, and
component involved in each oil spill event. It is desired that the failure involved in
each oil spill be identified to all of these levels. However, where this is not possible,
the failures should be identified to the full extent of information provided by the data
sources. The system code is a 5-digit code structured within Field 61-65 as follows:
61
S
.S
03
62
£
w
1
63
Qi
g
a
I
w
64 65
s
o
§
o
u
The codes for system, subsystem, and equipment are single digit, whereas the code
for components is two digits. Where information is lacking at a given level, the
particular code space shall be filled with a zero, or two zeros in the case of com-
ponents. The codes are listed in the following four lists; one each for Gathering/
Distribution, Drilling, and Production Systems (which includes structured subsystem
and equipment listings), and a fourth for components. The component codes replace
the last two zeros in the codes from the previous lists where components can be
identified.
K-45
-------
Code System/Subsystem/Equipment
10000 GATHERING/DISTRIBUTION
11000 Pipeline S/S
11100 Pipe
11200 Scraper Trap Equipment
11300 Pipe Supporting Structure
11400 Stream Crossing
11500 Road Crossing
12000 Storage S/S
12100 Tank
12200 Tank Fire Walls
12300 Tank Associated Equipment
12400 Power
13000 Pump Station S/S
13100 Pump
13200 Centrifugal Pump
13300 Reciprocating Pump
13400 Manifold
13500 Rotary Pump
13600 Steam Engines
13700 Gas Turbine
13800 Steam Turbine
13900 Internal Combustion Engine
13AOO Electric Motors
13BOO Pressure Controllers
13COO Metering Equipment
FIELD 61-65
SYSTEM CODE
(Cont'd)
Code System/Subsystem/Equipment
13DOO Valve
13EOO Valve Operating Equipment/
Controls
13FOO Electric Power and Control
13GOO Communication Equipment
13HOO Drainage System
13JOO Power
14100 Safety S/S
14100 Pressure Sensing
14200 Pressure Switching
14300 Flow and Guage Indicating
Equipment
14400 Temperature Recorders
14500 Power
1500 Gathering Pipelines S/S
15100 Gravity
15200 Suction
15300 Pressure
20000 DRILLING
21000 Well S/S
21100 Hole
21200 Casing String
21300 Casing Head
21400 Cement
K-46
-------
Code System/Subsystem/Equipment
20000 DRILLING (Cont'd)
22000 Prime Power S/S
22100 Engines
22200 Power Transfer
23000 Hoisting & Rotating S/S
23100 Derrick Platform
23200 Crown Block
23300 Traveling Block
23400 Draw Works
23500 Elevators
23600 Drilling Line
23700 Rotary Hook
23800 Rotary Table
23900 Floor Tools
24000 Mud S/S
24100 Mud Pit
24200 Suction Line
24300 Mud Pump
24400 Mud Line
24500 Stand Pipe
24600 Rotary Hose
24700 Mud Flow Line
24800 Shale Shaker
24900 Atmospheric Degas ser
24AOO Vacuum Degasser
FIELD 61-65
SYSTEM CODE
(Cont'd)
Code System/Subsystem/Equipment
24BOO Desander
24COO Desilter
24DOO Barite Recovery Unit
(Centrifuge)
24EOO Mud Mixing & Treating
24FOO Mud Monitoring Instruments
25000 Drilling String S/S
25100 Swivel
25200 Kelly
25300 Kelly Cock
25400 Drill Pipe
25500 Drill Collars
26000 Blow Out Preventer S/S
26100 Pipe Ram BOP
26200 Blind Ram BOP
26300 Annular (Bag Type) BOP
26400 Down Hole BOP
26500 Accumulator & Lines
(Closing Unit)
26600 Energy Supply
26700 Choke Manifold & Special
Kill Equipment
27000 Utility S/S
27100 Air
K-47
-------
Code System/Subsystem/Equipment
20000 DRILLING (Cont'd)
27000 Utility S/S
27200 Steam
27300 Electrical
27400 Water
30000 PRODUCTION
31000 Well S/S
31100 Bore
31200 Casing String
31300 Production Tubing
31400 Downhole Assembly
32000 Well Head S/S
32100 Casing Head Equipment
32200 Tubing Head Equipment
32300 Choke, Fixed
32400 Choke, Adjustable
32500 Rod Pump
32600 Hydraulic Lift
32700 Gas Lift
32800 Electrical Pump
32900 Power
33000 Gathering S/S
33100 Flow line Equipment
33200 Choke, Fixed
FIELD 61-65
SYSTEM CODE
(Cont'd)
Code System/Subsystem/Equipment
33000 Gathering S/S
33300 Choke, Adjustable
33400 Manifold
33500 Metering
33600 Pumps
33700 Automatic Control Equipment
33800 Power
3400 Separation S/S
34100 Separators, High Pressure
34200 Separators, High Controls
34300 Separators, Low Pressure
34400 Separators, Low Controls
34500 Scrubber
34600 Scrubber Controls
35000 Treater S/S
35100 Heater Treater
35200 Heater Treater Controls
35300 Chemical-Electrical Treater
35400 Chemical-Electric Controls
35500 Gun Barrel
35600 Skimmer (Settling)
35700 Free-Water Knockout
35800 Power
K-48
-------
Code System/Subsystem/Equipment
20000 PRODUCTION (Cont'd)
36000 Local Storage S/S
36100 Tanks
36200 Tank Associated Equipment
36300 Sump System
36400 Firewall
36500 Power
37000 Custody Transfer S/S
37100 Pumps
37200 Pump Controls
37300 Metering Equipment
37400 Manifold
37500 Sampling Equipment
37600 Prover Tank
37700 Power
38000 Safety Shutdown & Alarm S/S
38100 Energy Source
38200 Energy Source Distribution
Equipment
38300 Sensing or Detecting Equipment
38400 Monitoring and Alarm Panels
38500 Electrical Equipment
38600 Subsurface Safety Valve
38700 Surface Controlled Subsurface
Safety Valve
38800 High/Low Pressure Valve
FIELD 61-65
SYSTEM CODE
(Cont'd)
Code System/Subsystem/Equipment
39000 Water Disposal or Injection
S/S
39100 Power
39200 Precipitator
K-49
-------
FIELD 61-65
SYSTEM CODE
(Cont'd)
Code Component
01 Bell, Alarm
02 Bellows
03 Blowcase, Saltwater
04 Bourdon
05 Box, Stuffing
06 Cable
07 Choke Bean
08 Choke Body
09 Choke Target
10 Coil
11 Connector, Electrical
12 Coupling
13 Detector, Gas
14 Detector, Heat
15 Diaphragm
16 Disc, Rupture
17 Ells
18 Fasteners
19 Fittings
20 Flange
21 Float
22 Float (Gas-Oil)
23 Float (Oil-Water)
24 Foundation
25 Gasket
26 Gasket Ring
Code Component
27 Gauges
28 Gland, Packing
29 Glass, Sight
30 Header
31 Heater
32 Hopper
33 Hopper, Bin Storage
34 Hose
35 Jet
36 Joint, Blast
37 Lamp, Indicator
38 Linkage
39 Liner
40 Meters
41 Nipple
42 Nipple, Landing
43 O-rings
44 Packers
45 Pig
46 Pipe
47 Piston
48 Plug, Bull
49 Pump
50 Recorders
51 Rectifier
52 Regulator, Pressure
K-50
-------
Code Component
53 Relay, Electric
54 Relay, Pressure
55 Riser
56 Rods
57 Rod, Polished
58 Screen
59 Seals
60 Seam
61 Sensor, Level, High
62 Sensor, Level, Low
63 Sensor, Pressure, High
64 Sensor, Pressure, Low
65 Swage
66 Switches
67 Tank Shell
68 Tees
69 Threads
70 Tubing Hanger
71 Tubing, Instrument
72 Union
73 Union, Flange
74 Valve
75 Valve, Back Pressure
76 Valve, Ball
77 Valve, Blind
78 Valve, Body
FIELD 61-65
SYSTEM CODE
(Cont'd)
Code Component
79 Valve, By-Pass
80 Valve, Check, Reverse Flow
81 Valve, Control
82 Valve, Dump
83 Valve, Gate
84 Valve, Needle
85 Valve, Plug
86 Valve, Relief, Pressure
87 Valve, Trim
88 Vessel, Pressure
89 Welds
90 Wiring, Electrical
91 Motor
92 Fire-Tube
93 Controls
94 Vent
95 Test Tank
96 Oil Leg
97 Water Line/Leg
98 Fuel Supply Line/Leg
99 Strainer
K-51
-------
FIELD 66
PIPE DIAMETER CODE
The pipe diameter information is desired when an oil spill is attributed to piping.
Where the data permits, one of the following codes shall be entered to indicate the
diameter of the pipe involved:
Code Pipe Diameter
A Unknown
B Not Recorded
C 2" or less
D 2-1/2"
E 3"
F 4" or 4-1/2"
G 6"
H 8"
J 10"
K 12"
L 14" to 24"
M 26" to 40"
N 42" to 48"
K-52
-------
FIELD 67
INSTALLATION DATE CODE
The age of a petroleum system installation often has a large bearing on problems
due to corrosion, wear, or other time-related factors. In anticipation that installation
date information might be available regarding the various systems, a data code is
available. The age factor is of sufficient importance to warrant its inclusion for
each system oil spill event, where the data permits.
The following code is to be used to record the installation date:
Code Time Period
1 Before 1920
2 1920-1929
3 1930-1939
4 1940-1949
5 1950-1959
6 1960-1969
7 1970-1971
8 Unknown
9 Not Reported
K-53
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FIELD 69
EQUIPMENT PROTECTION CODE
The Equipment Protection Code provides for information regarding protective
coating of pipelines and cathodic protection as follows:
Code Description
1 Coated - Cathodic Protection
2 Coated - No Cathodic Protection
3 Not Coated - Cathodic Protection
4 Not Coated - No Cathodic Protection
5 Coated - Cathodic Protection Not Reported
6 Not Coated - Cathodic Protection Not Reported
7 Cathodic Protection - Coating Not Reported
8 No Cathodic Protection - Coating Not Reported
9 No Protection Information Reported
K-54
-------
FIELD 71
REPAIR ACTION CODE
The nature of the repair action instituted following a spill event serves to
indicate whether or not there was a replacement, repair, or adjustment at a sub-
system, equipment, or component level.
The repair action is listed as follows:
Code
1
2
3
4
5
6
7
8
9
Description
Replaced Subsystem
Replaced Equipment
Replaced Component
Repaired Equipment
Repaired Component
Adjusted
Not Reported
Repair Not Required
Removed From Service
K-55
-------
FIELD 73
SPILL CONTROL METHOD CODE
The Spill Control Method Code permits recording the type and amount of control
exercised in a particular case.
The following listing comprises the Spill Control Method Code:
Code Description
0 Controlled, But Method Not Reported
1 Dammed
2 Dug Pit
3 Booms
4 Air Barrier
5 Soaked Into Ground Or Trapped in Natural
Earth Depression
6 Dispersed Into Water
7 Contained Within Fire Walls
8 Retained Within System
9 Not Reported
A Killed Well/Shut In
K-56
-------
FIELD 75
SPILL CLEANUP METHOD CODE
Frequently used actions for cleanup of oil spills are represented in the designed
code. Regulations or laws often enforce some response. The speed of response or
a mixture of various methods are not covered by this code. The cleanup method,
when reported, together with the location and quantity spilled, improves the capa-
bility for data analysis.
The Spill Cleanup Method Codes are as follows:
Code Description
0 Cleaned Up, But Method Not Reported
1 Vacuum
2 Burned
3 Skimmers
4 Soaked Up With Straw
5 Soaked Up With Urethane Foam Chips
6 Covered With Sand or Dirt
7 Turned Soil Under
8 Not Required
9 Not Reported
K-57
-------
FIELD 77-78
COST CODE
An estimate of the cost of an oil spill is desired. By determining the cost
related to spills, a basis of comparison can be established to balance against the
cost of system improvements to prevent spills. To this end the cost code is used to
identify major categories of cost, both by type of cost and dollar amount, falling in
selected ranges.
The Cost Code consists of two positions. The first, Field 77, relates to the
dollar range. The second, Field 78, relates to the nature of the costs. The 0 code
in either position indicates "not reported. "
Numeric
Code (Field 77)
1 0-999
2 1,000- 4999
3 5,000 - 9999
4 10, 000 - 49999
5 50,000 or over
0 Not Reported
Alpha
Code (Field 78)
A Property Damage
B Cleanup
C Loss of Oil Spilled
D Loss of Oil Production
E Repair or Restoration
F A &B
G A & C
H B & C
J A &B & C
K B & C & E
0 Not Reported
K-58
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FIELD 80
VIOLATION CODE
Laws or regulations may be violated in connection with the occurrence of an
oil spill event. This code is provided to indicate where such violations are reported.
The data are desired to support analysis and recommendations regarding enforcement
of or change in regulations which will tend to eliminate or reduce pollution of the
environment as a result of oil spillage.
The Violation Code is as follows:
Code Violation
1 Yes
2 No
3 None Reported
K-59
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