-------
TABLE 55 (continued)
00
CO
Equipment
Defects Measured
Sensitivity0
(e) Magnetic Chlj)
{Installed on machinery
and periodically examined.)
1. Internal defects
in machinery
2. Bearing damage
(f) Oil Odor
finspector detects oil from
smell.)
1. Oil leaks
I. Small leaks
Advantages
OTHER METHODS
(s) Integrated Machinery Inspection7'
(h) Control ROOM Monitoring. Alara Shut-off
(') Uy-H^LST Infrared
(J) ih§!mLF»JM
(k) Hicrowave
(1) Filtered Particle
(HI) Sonic
I. Simple
2. Low cost
3. Comit-rctally
available
4. Some Incipient
failure detection
5. Reduces Machinery
maintenance costs
6. Continuous moni-
toring possible
1. Simple
2. Can be used in dark-
ness or in bad
weather
3. Particularly useful
In darkness at sea
Disadvantages
1. Subject to personnel error
2. Hinds may cause oil odor not
be detected
3. Not quantitative
to
Identifies Reference number.
Small spill < 2.000 gal (50 barrels); minor spill 10.000 gal (238 barrels); Medium spill 10.000 to 100.000; major spill > 100,000 gal.
GVery rough estimate of inspection costs for year for components that would typically be Inspected; low cost 0 - $20K; medium cost J20K
to $?OOK; high cost > )200K.
-------
Because most pipelines are buried, oil escaping in either small or large
quantities may not be observed, or, if observed, only small quantities or
traces may be visible. Also, in some types of soi-1, the oil may take a
particularly long time to surface. These migration effects52»5^»55»ss
occur because the soil between the line and surface absorbs and spreads
oil below the surface. Often this causes the distance between the dis-
covered leak and the actual leak location to be quite large. When pipe-
lines are installed in gravel bottoms or sandy bottoms, this can become
a particular problem.
Underwater lines have other significant problems with visual inspec-
tions. If a leak occurs underwater, the oil can be spread by currents.
Many leaks cannot be detected by visual observation. For example, a small
crack in the pipeline may allow seawater to seep inside undersea pipelines
which are located at depths at which external pressures are greater than
internal pressures. This water can cause excessive internal corrosion.
In the extreme case, a crack can grow undetected to a critical size, then
rupture and cause a major pollution incident.
These and other factors make it difficult to detect and locate a pipe-
line leak. Furthermore, numerous instances of careless losses from small
quantities of oil, such as from dumping crackcase oil, losses from domestic
fuel oil tanks, or spills from ships present difficulties in discriminating
between a pipeline leak and other oil spillage.
Methods that aid visual inspection are quite useful in improving the
ability of an inspector to detect and locate a leak. Aided inspections
might be an inspector walking the line with a hydrocarbon detector, an in-
spection plane eqippped with remote oil spill detectors or an inspector on
the deck of a ship or at a marine terminal viewing the water with an ultra-
violet light source or low-light TV monitor. Use of a hydrocarbon detector
while walking the lines in populated or hazardous areas appears particularly
advantageous for detecting small leaks, such as could occur from corrosion.
These small-volume corrosion leaks may take either a long time to surface
or may only surface trace amounts. Inspection with a hydrocarbon detector
may provide detection of a leak before it can cause any surface damage and
possibly before it can cause damage to underground water supplies.
5.3.2.2 Oil Spill Detectors On or Near the Water-
Oil spill detectors such as those in Table 47 might be used to supple-
ment visual inspection. These detectors are of low to medium cost and do
not interfere with pipeline operations. A few advantages of these devices
are that they are not subject to personnel error and most provide contin-
uous detection. Many oil companies are currently using oil spill detectors
(Table 47(c)) at supertanker terminals and at other marine terminals. How-
ever, most of these oil spill detectors are still under development or
evaluation and are not in common use.
184
-------
Two oil spill detectors appear to have a particularly good potential
of effectively minimizing oil pollution. One is the platform infrared
type (Table 47(c)) for use at marine terminals. This may be particularly
beneficial when a considerably amount of petroleum is transported. The
other is the bistatic, active, infrared type (Table 47(j)) for channels
and rivers.
5.3.2.3 Internal Fluid Variations During Oil Transfer--
Unusual fluid variations in a pipeline during transport can indicate
possible pipeline system leaks. A variety of methods that detect fluid
variations are available for leak detection and inspection of the pipe-
Tine system during normal operations when oil is transported. These are
given in Table 48 and include:
• Pressure deviation
• Volume comparison (differentials)
• Flow rate comparison (differentials)
• Flow rate deviations
• Over-and-short accounting (long-term)
• Mathematical modeling
• BS&W deviations
• Pressure difference with reference and threshold
• Fluid mass deviations
• Negative surge
• Inspection pig-passive ultrasonic
• Pressure fluctuations
• Production surveillance monitor-pressure fluctuations.
These methods normally cause only minimal interference with line operations
and most are of low to medium cost. All methods provide continuous sur-
veillance of the line except the passive ultrasonic pig and long-term over-
and-short. Most methods primarily detect major leaks or catastrophic
failures. They are used to trigger controls to quickly shut the system
down and thus minimize the volume of spillage. None of these methods, ex-
cept possibly mathematical modeling, can reliably detect small leaks (a
few barrels per hour) over a short period of time (hours). A few methods,
however, are capable of detecting small leak rates over long time periods.
The first five methods are commonly used for pipeline leak detection
by the U.S. oil industry. In general, modern supervisory control systems
are computer controlled and many provide continuous monitoring of pressure
deviation, volume comparison, flow rate comparison and flow rate devia-
tions. Hardwired meter flow comparators are often installed in areas where
the risk of pollution is high. They are particularly effective where more
185
-------
of these leak detection methods might be implemented. A leak detection
system, for example, might continuously monitor pressure drop and compare
flow rates and flow deviations between two points. If one or more measure-
ments exceed preset values, an alarm would be sounded and appropriate
valves and equipment would automatically be operated to shut down the sys-
tem. Normally, an excessive pressure drop combined with a flow rate in-
crease are strong indicators of a leak.
Varying operating conditions, fluids, transients, temperatures, line
pack and other factors cause changes in these pipeline system measurements
that often result in false indications of leakage and cause false alarms
and shudowns. In order to account for varying conditions and minimize
false alarms, three things are normally done. First, a variety of highly
accurate metering equipment (i.e., pressure transducers, flow meters,
temperature gauges, etc.) are installed. Then sophisticated computer pro-
gramming with various scanning rates, error bands, checking schemes and
displays are used in the monitoring systems. Finally, the system sensi-
tivity is decreased and setpoints raised to minimize false alarms. For
most lines, this results in decreases in sensitivity that precludes de-
tection of small or minor spills.
Short-term losses (one hour or less) of from 1 to 5 percent of through-
put are normally detectable with these types of continuous monitoring sys-
tems. For a throughput of 10,000 bblh, this corresponds to a leakage rate
detection of 100 to 500 bblh. Long-term (24 hours or more) detection of
losses ranging from 0.2 to 1 percent of throughput might be expected; this
corresponds to leakage rate detection of 20 to 50 bblh. Supplementary
methods such as mathematical computerized modeling, which accounts for many
varying operating conditions and fluid changes, might be adapted to an
existing supervisory control system to provide more sensitive (up to a fac-
tor of 10) leak detection. If implemented, small and minor spills might be
detected. Mathematical modeling is currently being developed and evaluated
by a number of companies. The method has been implemented on a few crude
lines.
Long-term over-and-short accounting is the most common means of pro-
viding an indication of a leak. It requires only conventional metering,
i.e., LACT and tank gauging, and standard accounting of receipt and de-
livery tickets and inventory of the lines and tanks. This existence of
leakage is normally suspected when a shortage exceeds about 0.1 percent
of long-term (weekly, monthly or yearly) throughput.
On large lines, gross barrels in and out, then net barrels in and out,
are looked at on the basis of total volume. The only difference between
net and gross is in the BS&W. A loss/gain is run on water as is done with
oil because BS&W is a mirror image, i.e., BS&W gain is an oil loss or
vice versa. BS&W can provide both leak detection and a check or gross
volume to identify volumetric errors. This leak detection method is par-
ticularly useful in underwater lines where external pressures are higher
than internal pressures and seepage of water can occur into the line
through a crack. The measurement is quite inaccurate (see Section 4.3.2.3),
and only large leaks are capable of detection.
186
-------
Pressure difference with reference and threshold is a recently patented
method. At this time there is insufficient information for proper evalua-
tion.
Detection of leaks by monitoring the deviation in mass at the line in-
put and output is attractive because pressure and temperature changes do
not affect the measurement. The method requires that density be measured
directly. Fluid mass measurement is currently carried out on mixtures of
light products, i.e., natural gas mixtures. In this application, the coef-
ficient of expansion of light products is not known, and this is the only
method that has been used to successfully measure these fluids.
Negative surge leak detection is used on a few pipelines. Leak detec-
tion accuracies (about 600 bblh) are not as good as other methods. How-
ever, the method is quite simple and it can provide an inexpensive check
or backup system for large leaks.
The ultrasonic inspection pig is propelled through the line by the
fluid flow. It detects a leak by sensing the acoustic energy generated
at the pipeline leak source. This energy is propagated via acoustic waves
from the pipe inner wall through the fluid to ultrasonic detectors in-
stalled in the pig. Leak location is determined from tape recordings of
both the time the leak is detected and distance the device travels. The
method is currently used in a few lines. Leak detection capabilities of a
few barrels per hour are claimed. Because of the high cost for a single
inspection of the line, it is used at infrequent intervals ranging from
six months to five years. This type of inspection pig has a number of
limitations. It is particularly difficult to apply the same unit on a
variety of lines because the leak detection sensitivity varies with the
type of line, and leak detection background noise often presents false
indications of leakage.
Experimental work currently is being carried out on the pressure fluc-
tuation method. The basic concept is to detect the fluctuations with an
array of pressure or acoustic sensors inserted in the line. The fluid
turbulence generated by a leak is propagated in the fluid along the line
and sensed by the detectors. The method is attractive because of its sim-
plicity and the wide transducer spacing. The method is also attractive
for detecting and locating the wave fluctuations in the line that are gen-
erated by impacts from outside forces.
The production surveillance monitor measures flow rates in the typi-
cal two-phase flow in production lines. The monitor has been proven in
field tests and has been implemented on a number of lines. When used in
a continuous monitoring system, it can provide indications of anomalous
changes or well problems such as pipe leaks or pump malfunctions.
187
-------
5.3.2.4 Detecting and Locating Leaked Oil On or a Short Distance from the
Pipeline--
Methods for detecting and locating leaked oil using sensors located on
or at a short distance from a pipeline are given in Table 49. These methods
differ from those in the previous two sections because oil need not travel
to the surface of the soil or water for detection and the methods poten-
tially provide accurate leak location. A number of these methods are new
or are in the feasibility or development stage.
The most promising of these types of continuous monitoring leak detec-
tion methods are:
• Passive acoustic array
• Shroud with electromagnetic pulsed coaxial cable
• Continuous thermistor
• Tape detection.
The passive acoustic array (see also Section 5.3.2.3) potentially is
capable of detecting and locating the following: (a) leaks to a few bar-
rels per hour; (b) internal pipeline defects that may result in leaks; and
(c) (most importantly) outside damage and pipeline ruptures. The other
three methods are capable of detecting leaks ranging from a few barrels
per hour to pipeline rupture. However, these three methods are not con-
sidered to be as effective as the acoustic array and are expected to be
more expensive. The double walled pipe is too costly to be considered
except on short sections of the line in sensitive areas. The oil-soluble
tubing method has been a failure on at least one pipeline. All of these
continuous monitoring methods would require retrofitting the line, except
possibly the passive acoustic array when used for outside damage detection
only (see Section 5.3.273).
Other methods in Table 49 can also be applied to the entire line but
are normally used on a periodic basis for: checking the integrity of the
line, locating leaks, or locating and verifying a suspected leak. The
nuclear tracer method appears to be most effective, but very costly, for
periodic checking of the line and locating leaks. It has been implemented
on a few lines, and high leak location accuracy is claimed. The hydrocarbon
probe is considered to be quite effective in detecting and locating small
leaks in undersea or underwater lines. Rods installed permanently on the
pipeline and used in conjunction with acoustic sensors are used by a few
pipeline companies to locate and verify a suspected leak. Nitrous oxide
injection is costly but has been shown to provide very accurate leak loca-
tion. These methods normally cause only limited interference with the line.
The remaining methods in Table 49 are limited to checking for suspected
leaks of only sample areas of the pipeline. Some would require excessive
costs for inspecting a complete line, while others are not considered prac-
tical for the entire line. Although useful in locating known or suspected
leaks, these methods are limited and not considered as practical means of
significantly reducing petroleum leakage.
188
-------
5.3.2.5 Periodic Pressure Tests—
The periodic pressure tests given in Table 50 provide checks of the
pipeline for leaks and/or checks for internal defects that may result in
a leak. These methods require either limited interference with pipeline
operations and/or retrofitting. Pressure tests primarily for detecting
leaks are:
• Pressure static
* Hydrostatic
• Pressure difference
• Dye tracing
• Seal leak detector-joint type
• External hydrostatic
• Seal leak detector-thermistor type.
Pressure static, hydrostatic and pressure difference are the only
methods that may be capable of effectively testing the complete line for
leaks. However, these methods require that the lines be shut down and
they do not locate the leaks. They are generally considered as pressure-
volume-temperature-time (PVTT) test methods. Although less sensitive,
the pressure static method can be carried out in a relatively short period
of time. The other two methods require that the line reach temperature
stabilization, which may take as much as three days. Also pressure static
does not have the oil spill risk3 problem that exists when petroleum is
left in the line, as is often done, for the other two methods. Simple
hydrostatic proof testing is widely used in the petroleum industry to both
test new lines and to check existing lines. For typical lines, the test
is carried out every two to five years. Leak sensitivity is about 0.5 BBLH;
this is about 10 to 100 times more sensitive than the methods discussed
previously. The pressure difference method has a demonstrated leak sensi-
tivity of about 0.05BBLH on foreign lines. Despite its superior leak sen-
sitivity, the high cost of the method has generally precluded its use in
the U.S.
Even better leak sensitivities are expected if the PVTT leak detec-
tion systems are supplemented by mathematical modeling of the line. Should
a leak be detected, methods such as described in Section 5.2.1.3 could be
used for leak location. Additionally, insertion of dyes during these tests
can be advantageous in providing leak location, particularly when residuals
from previous spills cause difficulty in detection. The remaining three
methods can be implemented advantageously in certain limited applications.
Methods requiring elevated pressures present a serious spill risk problem
when the line is filled with petroleum. If a line should fail under pres-
sure the petroleum would present a serious hazard particularly in high
risk locations such as urban areas or near water.
189
-------
Pressure test methods for detecting and locating internal defects in-
clude:
• Reflected pressure wave
• Acoustic resonance
• Passive acoustic array - acoustic emission.
The capability of checking lines for internal defects has been demon-
strated on petroleum pipelines for the pressure wave and acoustic resonance
methods. Both methods require that the pipeline be emptied and filled with
a gas. The acoustic resonance technique appears best suited for testing
inaccessible areas of a pipeline. These methods typically cause only lim-
ited interference with the line. A permanently installed passive acoustic
array is in the development stage, but has been shown to be effective for
detecting leaks and incipient failure during experimental tests on actual
lines. Internal defects, however, can only be detected when the line is
pressurized. The method typically requires close sensor spacing and is
considered a retrofit. However, in high-risk areas, the method might be
considered despite high retrofitting costs.
5.3.2.6 Corrosion Inspection-
External pipeline corrosion is the major cause of spills from older
pipelines (those installed before 1950). Since the 1940's, improved tech-
niques, such as pipeline coatings and cathodic protection systems, have
reduced the number of oil spill incidents from new lines to a level about
equal to internal corrosion. This can be seen in Table 25, which identi-
fies causes of spills in the United States. In contrast, leaks from pipe-
lines caused by defective seams and welds were similar for both the old
and new pipelines.
A large number of inspection and leak detection methods are available
to detect pipeline corrosion damage (wall thinning, cracks, etc.) that can
result in leaks. The main ones (see Table 51) are:
• Flow sampling (internal corrosion) - periodic
corrosion rate coupons
laboratory analysis of petroleum
miscellaneous trap monitoring (pig traps, strainers, etc.)
• Corrosion metering (internal corrosion) - continuous
corrosion rate probe
• Corrosion metering (external corrosion) and eathodic protec-
tion monitoring
potential measurements
continuity measurements
manufacturer recommendations
• Holiday detector (external corrosion) - periodic
• Visual inspection - periodic
190
-------
• Standard non-destructive inspection equipment
active ultrasonics
X-ray
gamma ray
magnetic particle
ultrasonic imaging
eddy current
penetrants
• Pipeline inspection pigs
magnetic flux
active ultrasonics
TV camera
stereo pair
eddy current
electromagnetic noncontact transducer (EMAT)
manned inspections using standard NDI methods
• Other
passive acoustic array-acoustic emission.
External corrosion metering and monitoring of the pipeline cathodic
protection is carried out on most United States pipelines (see DOT Regula-
tion Title 49, 195.2 and 195.4). This has been highly successful in re-
ducing corrosion damage and the leaks that result from corrosion. New
techniques, such as those using computerized modeling, can define the po-
tential profiles and the need for additional anode protection. Trend in-
dications of internal pipeline corrosion can be obtained using flow samp-
ling methods and corrosion rate probe.
Standard non-destructive inspection (NDI) equipment is commercially
available for measuring actual corrosion damage. Active ultrasonic NDI
equipment is highly accurate (better than 1 percent thickness to flaw
size resolution) and reliable, and is often used for corrosion measure-
ments. Costs of excavating for inspections or boring through the soil to
the pipeline to provide contact of ultrasonic sensors to the line are quite
high. Thus, this equipment is limited to inspections of only sample areas
of the pipeline. High costs prevents this type of equipment from being
considered as a practical way of significantly reducing pipeline petroleum
leakage.
Only pipeline inspection pigs, used periodically, appear to have the
potential of substantially reducing pipeline leaks caused by corrosion.
This equipment provides excellent incipient failure detection of corrosion
damage. The ultrasonic imaging inspection pig (see Table 53(g) and (o))
provides a 3-dimensional view of the inside of the pipeline wall. It po-
tentially can detect all pipeline corrosion damage and eliminate most leaks
caused by corrosion. The equipment has been successfully used on the Alyeska
pipeline. However, ultrasonic imaging inspection pigs have not been devel-
oped to the extent that a device can be propelled through the pipeline by
fluid flow; this development is necessary for practical application to most
petroleum pipelines. Magnetic flux type inspection pigs (see Table 53(a))
191
-------
are commercially available from AMF Tuboscope and Vetco. These devices
have been used for a number of years and are capable of detecting most
pipeline corrosion damage. TV camera inspection pigs and other devices
can be used to complement the magnetic flux inspection by providing vis-
ual inspection of areas where interpretation of anomalies is uncertain.
A corrosion maintenance program used in conjunction with inspections
and existing cathodic protection improves the effectiveness of corrosion
prevention. For example, chemical inhibitors used at frequent intervals
are effective in preventing internal corrosion.
5.3.2.7 Standard Non-Destructive Inspection—
A wide variety of standard non-destructive inspection equipment
(Table 52) are available to periodically detect most pipeline system
damage. Actual leakage, as well as internal and external damage that
can lead to a leak, can be detected. Methods that are particularly sen-
sitive to defects in petroleum pipeline systems and are in wide use in-
clude:
• Active ultrasonics
» X-ray
• Gamma ray
• Magnetic particle
• Ultrasonic imaging
•• Eddy current
• Penetrants.
This equipment is effective and practical for inspecting pipelines under
construction or above ground. Cost considerations make the equipment im-
practical for use on buried pipelines. Since most of the petroleum pipe-
lines in the United States are buried, the use of this equipment is very
limited. Thus, these methods are not considered viable solutions to sig-
nificantly reducing the incidents or volume of spills.
5.3.2.8 Inspection Pigs—
In addition to detecting petroleum pipeline corrosion damage that can
lead to leaks, inspection pigs detect other pipeline damage, such as defec-
tive pipeline seams, pipeline welds and pipeline leaks. Because of high
cost, inspection pigs normally are used to inspect the line at intervals
ranging from six months to five years. These devices have inspected over
100,000 miles of pipelines.
A variety of inspection pigs (Table 53) with different operating prin-
ciples are available for internal inspection of the pipeline. Inspection
pigs include magnetic flux, electromagnetic, kaliper, active ultrasonic
passive ultrasonic, TV camera, nuclear, eddy current, ultrasonic imaging
and infrared units. Most pigs are propelled through the pipeline by oil
192
-------
or other fluids flowing through the pipeline. A few types are
pushed through the pipeline. In large-diameter pipelines, internal inspect
tions can be carried out with inspectors. In this type of inspection,
equipment and inspectors are propelled through the pipelines by vehicles
ranging from a simple dolly manually pushed through the pipeline to a
powered, controlled-environment inspection chamber with instrumentation
trailer.
A pipeline cleaning pig, typically a brush type, and a dummy inspec-
tion pig are normally run through the pipeline prior to actually running
the instrumented inspection pigs. A pipeline should be inspected with a
pipeline inspection pig before the oil is initially transported to obtain
background information. Calibration blocks for some types of inspection
pigs are put on the pipeline to provide operational and sensitivity checks.
Tracking systems for inspection pigs (Table 53(p)) are used in case the
inspection pig gets stuck in the pipeline and for identifying defective
areas.
The inspection pigs that are effective for detecting corrosion damage
are also the most effective for detecting other internal pipeline damage.
Five types of inspection pigs appear to be particularly effective. They
are:
• Magnetic flux Table 53{a)
• Kali per Table 53(b)
• Active ultrasonics Table 53(c)
• Ultrasonic imaging Table 53(g)
• EMAT Table 53{h).
A low-cost active ultrasonic device for detecting wall thickness only
was recently under development by Harry Diamond Laboratories for inspection
of U.S. Navy pipelines. The ultrasonic imaging inspection pig is capable
of providing a 3-dimensional view of line defects. The device is not cur-
rently available for long lines or wide range of pipeline diameters.
The EMAT inspection pig is in the feasibility/experimental stage.
Test results indicate that it can detect longitudinal stress corrosion
cracks and non-localized regions of corrosion.
At this time only the magnetic flux and kali per inspection pigs are
available for widespread pipeline inspection. The magnetic flux inspec-
tion pig has been used to inspect over 50,000 miles of pipeline. However,
the device is insensitive to longitudinal stress corrosion cracks and to
non-localized regions of corrosion. The manufacturer claims this equip-
ment to be 95 percent reliable in detecting pipeline defects. An example
of the capability of the magnetic flux pig can be demonstrated by the re-
sults of an inspection carried out in a line (large-diameter 200-mile
crude line) visited by project personnel during this study. In this case,
the magnetic flux pig detected and located over 200 defects.
193
-------
5.3.2.9 Survey-Pipeline System Charting and Depth of Burial--
Typical .inspection methods for charting movements and measuring depth
of burial and erosion of pipeline system components are given in Table 54.
All methods except those in Table 54(h) are carried out periodically. None
of these methods interfere with pipeline system operations.
Excessive movements of pipelines can cause abnormal stresses that may
result in a leak. These movements are generally due to natural causes.
Periodic inspections of pipeline movements provides data to chart the move-
ment history of the line. This information can be used to determine whether
excessive stressing of the line might be occurring and would allow remedial
action to prevent damage. Methods (a) through (e) in Table 54 can provide
such inspection. Of these, the radar and sonar methods appear to be the
most effective and are low cost.
Maintaining pipeline depth of burial is extremely important in the pre-
vention of pipeline damage from outside sources, particularly for under-
water lines. Proper coverage of the pipeline minimizes damage that might
occur from anchor dragging, machinery impacts, etc. The sonar method with
penetrating and sub-bottom profiling is currently used on a number of under-
water lines to effectively perform these inspections. Low-cost systems are
commercially available. The radar method is one of several that can pro-
vide depth of burial inspections for onland pipelines.
In general, excessive scouring does not pose a great risk for most
underwater lines and other components of pipeline systems. But inspections
are necessary because of the disastrous effects, such as an offshore pump-
ing platform collapse. Periodic inspections by divers are normally suffi-
cient.
5.3.2.10 Miscellaneous Methods-
Inspection methods for petroleum pipeline systems that are not covered
by the first nine categories are included in Table 55. One of these
methods has the potential of significantly reducing oil pollution inci-
dents. The others are either already required by existing regulations and
are adequate, or have only very limited application.
The passive acoustic array has the potential of being the most effec-
tive of any leak detection and inspection method. It is intended to reduce
the number of incidents of damage by outside forces. This is done by de-
tecting acoustical sounds generated external to the line before the pipe-
line can be impacted and damaged by outside forces. The method can be
adapted into existing supervisory control systems or it can be implemented
as a separate system. Implementation would require either limited pipe-
line installation or retrofitting. The method is currently in the devel-
opment stage.2
Currently under development by NDE Technology, Inc.
194
-------
Inspections of pipeline conditions such as overpressures and excessive
shock load devices are essential to all pipeline systems. To be effective,
these inspections should be carried out frequently, and systems should in-
clude alarms with suitable shutdown and relief devices. The United States
has adequate regulations for these types of inspections.
A number of inspection methods such as given in (b), (e), and (h) of
Table 55 can be effective in preventing shutdowns or for providing warn-
ings of impending failures of various equipment. These methods may re-
duce maintenance costs, but are not effective in substantially reducing
the oil spill risk because most pipelines have redundant or axuiliary
equipment in the event of failure.
5.4 STATUS
5-4.1 Current Status of Leak Detection and Inspection Methods
The current status of the leak detection and inspection methods are
identified on page . Status is separated into the following five
phases:
• Required by U.S. regulation
• Common use
• State-of-the-art
• Developmental
• Feasibility.
5.4.2 Pipeline Regulations and Recommendations - U.S. and Foreign
Countries'
Liquid pipelines in the U.S. are regulated by two main agencies, the
Department of Transporation and the Department of the Interior. Other U.S.
Government agencies (some by delegation), such as the U.S. Coast Guard for
deepwater ports1", also regulate liquid lines. Many foreign countries such
as the United Kingdom, Switzerland, Italy, the Netherlands and West Germany
also regulate their liquid lines. In some areas, foreign regulations are
more stringent than those in the U.S. In addition to existing regulations,
trade organizations from private industry often recommend practices based
on recent developments in industry.
Existing liquid pipeline inspection and leak detection regulations
have been reviewed and recommendations made in a few recent studies. One
study (Reference 51, pp. 4-1 through 4-301) sponsored by DOT provided a
detailed review of regulations and industry recommendations of offshore
and on!and lines. Another study71 sponsored jointly by DOT, DOE and DOI,
reviewed inspection/testing/monitoring and regulations for offshore struc-
tures and liquid lines. Details of specific government agency jurisdic-
tions are included in these reports and this information will not be re-
peated here. A third study11* conducted for USCG and DOT provided recom-
mendations of inspection methods and procedures for deepwater ports. Both
195
-------
onland and offshore lines were included in the study. An overall review
of U.S. pipeline regulations is presented in Reference 1. The study iden-
tifies a number of significant problems and weaknesses in existing U.S.
pipeline safety programs. No new regulations are specifically identified
for the Alyeska pipeline, but there has been a substantial effort in mini-
mizing the risk of serious spills. Studies with recommendations have been
made and leak detection and inspection methods developed specifically for
the Alyeska line. At this time, no in-depth report of this effort is pub-
licly available.
U.S. regulations for liquid pipelines have helped to improve the ac-
cident record of the petroleum industry. These regulations are normally
presently in the following six areas and are listed on page 197. Only
two of these areas, operation and maintenance and pressure testing3 are
pertinent to this study. There are a number of reasons for emphasis in
these areas; a few will be discussed. First, the main objective of this
study is to recommend a viable and cost-effective spill prevention program
that would significantly reduce spill incidents and volume. It is expected
that this can be accomplished by implementing scheduled line inspections
and/or leak detection. Implementation of a program that includes methods
for the other four areas is not expected to significantly reduce spill
volume because of the following: (a) current regulations; (b) recommenda-
tions by various pertinent organizations; and (c) oil company programs are
already quite effective in preventing spills.
Spills normally occur after the line is designed, constructed and
pressure-tested; and spill frequency depends on factors such as pipeline
age. It is in this time frame that leak detection and inspection methods
might effectively be used to prevent spills and minimize spill volume,
and where a void exists with current practices in the U.S. Thus, existing
regulations and recommendations for leak detection and inspection that per-
tain primarily to operation and maintenance'3 are reviewed in the subsec-
tions that follow. For comparison purposes, existing regulations and
recommendations for gas lines are also included. Regulations of U.S. and
foreign countries, recommendations, and also maintenance practices for a
typical well-maintained pipeline are included in the subsections that
follow.
Liquid Lines
• U.S. Regulations - Liquid Lines
1. DOT CFR 195. - U.S. Regulation LIQUID LINES
49 CFR 195 - Part 195, Title 49 Code of Federal Regulations,
Minimum Federal Safety Standards for Liquid Pipelines, ap-
pearing in 34 F. R. 15473, October 4, 1969, with ammendments
up to and including Amdt. 195-14, Federal Register Vol 43,
No. 84, May 1, 1978.
aThere are no U.S. regulations for pressure testing in-service of existing
operational lines.
Other regulations, recommendations and review are provided in Appendix A
and in the referenced studies.
-------
AREAS OF LIQUID PIPELINE SYSTEMS UNDER U.S. GOVERNMENT REGULATIONS
vo
GUKRM.
Scope
Definitions
taller Incorporated by reference
Acceptable petroleuM coowidltles
transportation of certain comvantfes
transportation of convmdltles III pipelines constructed wltk ether I
steel pipe
Responsibility of carrier for coopllance with this part
ACCINNI WhimlNG
Scope
lelcphonlc notice of certain accidents
Accident reporting
Instructions lor preparing DOI I'ona /QOO-1
Changes In or addlllant t« accident retnrt
Carrier assistance In Investigation
Supplies of accident repurt 001 fora NKJO-I
Scope
Design temperature
Variations In pressure
Internal design pressure
Internal pressure
External loads
No-pipe
(bed pipe
Valves
fittings
Changes In direction: Provision fur Internal passage
fabricated branch connections
Closures
Flange connection
Station piping
lafcrlcated aMrafelles
nbnve ground tanks
tOHSIIIUCIIUI
Scope
Coieillance xlth speclflutlons or standards
Inspection-general
Kilcrlll Inspection
Melding of supports and braces
flpellne location
tending of pipe
Melding: General
Melding, niter Joints
Heldlnn: Seam offset
CUB1WCJIMI (Continued)
Heidi: Filler aKtal
Meiers: testing
Melding: Heather
Melding: Arc burns
Melds andxctdlng Inspection: Standards or acceptability
Melds: Repair of defects
Mel*: ftnnval of defects
Melds: Nondestructive testing and retention of testing records
Internal corrosion protection
titental coating
Cathodlc protection systeui
lest Ifads
Installation of pipe In a ditch
Cover ever burled plyeliM
Clearance betneen pipe and underground structures
lack HI line
«bo»» ground cotiionentt
Crossing of railroads and hlifhmys
Valve*: General
Valves: location
fwnjilng e««l|nient
NH>M ground tanks
Construction records
Scope
General re«|ulraiients
testing ol components
tot ncdlum
letting of tie-Ins
Hecords
Scope
General requirements
Naps and records
HatluMi operating pressure
CoMunlcatlons
line Barkers
Inspnctlon of rlghls-of-tiay and crossings niihr navlaable *»t«rs
Calhudlc protection
Ixleiual corroslim control
Internal corrosion control
Valve Mlntenance
flpellne repairs
flpe amvenont
Scraiwr and sphere facilities
Overpressure safety devices
rireflghtlng eoulpnmt
Storage vessels
Slg«
Security of facilities
i nr open flanes
-------
2. PCS #9 - U.S. Regulation LIQUID LINES
OCS Order No. 9 - Oil and Gas Pipelines, established by the
U.S. Department of the Interior, Geological Survey, Conser-
vation Division. Gulf of Mexico Area, October 30, 1970.
• U.S. Recommendations - Liquid Lines
3. API - U.S. Recommendations LIQUID LINES
API RP 1111, Recommended Practice for Design, Construction
Operation and Maintenance of Offshore Hydrocarbon Pipelines,
1st Edition, March 1976, prepared by the Transportation De-
partment of the American Petroleum Institute.
• Foreign Regulations - Liquid Lines
4. DnV - Foreign Regulations LIQUID LINES
DnV - Rules for the Design, Construction and Inspection of
Submarine Pipelines and Pipeline Risers, January 29, 1976,
prepared by Det Norske Veritas, Norway.
• Foreign Recommendations - Liquid Lines
5. IP - Foreign Recommendations LIQUID LINES
IP - "Supplement to IP Pipelines Code, Submarine Pipelines,"
Petroleum Pipelines Safety Code, published in 1974 with
Supplements, prepared by the Institute of Petroleum, Great
Britain.
• Well-Maintained and Inspected Pipelines - Liquid Lines
6. Practices by pipeline company A.
Gas Lines
• U.S. Regulations - Gas Lines
7. DOT CFR 192. - U.S. Regulation GAS LINES
49 CFR 192 - Part 192, Title 49, Code of Federal Regulations,
Minimum Federal Safety Standards for Gas Lines, appearing in
35 F.R. 13257, August 19, 1970, with amendments up to and
including Amdt. 192-27A, 41 F.R. 47252, October 28, 1976.
• DOT CFR 191. - U.S. Regulation GAS LINES
49 CFR 191 - Part 191, Title 49, Code of Federal Regulations,
Leak Reporting Requirements for Gas Lines, appearing in
35 F.R. 320, January 8, 1970. (Also referred to as DOT regu-
lation).
A list of legislation and regulations, standards technical require-
ments, codes of practice for design construction and operation of oil pipe-
lines in Western Europe is included in Appendix A-2.
198
-------
3.4.2.1 Visual and Visual Aided Line Observations for Leakage--
Liquid Lines
1. DOT (U.S. Regulation)
CFR 195.412 "(a) Each carrier shall, at intervals not exceeding
2 weeks inspect the surface condition on or
adjacent to each pipeline right-of-way.
(b) Except for offshore pipelines, each carrier
shall at intervals not exceeding five years,
inspect each crossing under a navigable water-
way to determine the condition of the crossing."
2. PCS #9 (PCS Order)
l.E "All pipelines should be maintained in good operating
condition and inspected monthly for indications of
leakage using aircraft, floating equipment on other,
methods."
3. API
701.5 "Each pipeline operator should maintain a periodic
pipeline patrol program to observe conditions along
the pipeline route affecting the pipeline's safe
operations."
4. DnV
9.3.1.1 "The frequency and extent of surveys shall depend upon
factors such as
- type of survey
- transportation of product
- pipeline route (traffic density, depth of burial)
- operation of pipeline systems
- conditions of pipeline/riser as installed
- degree of pipeline/riser exposure to potential
damage and/or deterioration caused by corrosion,
wear, etc.
9.3.1.2 A periodic survey is normally to be carried out annually
if not otherwise agreed upon in accordance with 9.3.1.1
above.
9.3.1.3 The time for annual surveys may, under normal circum-
stances, be selected with due regard to weather condi-
tions and operation of the pipeline (Frequency 12 ± 3
months).
9.3.1.4 The society may, upon request accept a continuous sur-
vey in lieu of regular periodical surveys. Each part
of the system is then to be controlled as frequently
as in the case of regular periodical surveys.
199
-------
9.3.1.5 The owner is to notify the society on occasions when
such parts of the pipeline system, which are not
normally assessible for survey, may be examined.
5. IP.
11.9 "It is recommended that long submarine pipelines be
inspected regularly by aerial patrol."
6. Pipeline Company A
Ground patrolling is intended to prevent any deteriora-
tions in the line resulting from:
• vegetation, vultivation and construction inside
the right-of-way.
• erosion phenomena (landslides, gullies formed by
running water, etc.)
• the carrying out of various forms of work imme-
diately near the right-of-way (drainage, irriga-
tion ditches, pipe or cable laying, road building.
• this patrolling is carried out by hired staff; each
line walker covers 12.4 miles which he inspects
twice a month and keep in touch with various people
who are likely to be aware of anomalies or incidents.
Ground patrolling is supplemented by special air patrol
which is carried out about twice a month with low-flying
aircraft.
Gas Lines
7. DOT (U.S. Regulation)
CFR 192.705(a) Each operator shall have a patrol program to
observe surface conditions on and adjacent to
the transmission line right-of-way for indica-
tions of leaks, construction activity, and
other factors affecting safety and operation.
(b) The frequency of patrols is determined by the
size of the line, the operating pressures, the
class location, terrain, weather, and other
relevant factors, but intervals between patrols
may not be longer than prescribed in the follow-
ing table:
200
-------
Maximum interval between patrols
At highway and At all other
Class location of line railroad crossings places
1,2... . ....0.6 months 1 year
3 „ 3 months 6 months
4 .do 3 months
(Note: Offshore is Class 1)
49 CFR 192.706 "(a) Each operator of a transmission line shall
provide for periodic leakage surveys of the
line in its operating and maintenance plan.
(b) Leakage surveys of a transmission line must
be conducted at intervals not exceeding 1
year. However, in the case of a transmission
line which transports gas in conformity with
§ 192.625 without an odor or odorant, leakage
surveys using leak detector equipment must be
conducted—
(1) In Class 3 locations, at intervals not
exceeding 6 months; and
(2) In Class 4 locations, at intervals not
exceeding 3 months."
U.S. regulations of line observations at least every two weeks are
justified. However, more frequent or more effective line observations de-
pending upon factors such as volume of product transported, age of pipe-
line might be justified for some lines. For example, in South Europe, air
patrolling is used, and a staff is employed to walk the lines.
5.4.2.2 Oil Spill Detectors on or Near the Water—
Liquid Lines
1. DOT (U.S. Regulation)
No Regulation
2. PCS
No OCS Order
3. API
Not Discussed
4. DnV
Not Discussed
5. IP.
Not Discussed
6. Pipelines Company A
Not Discussed.
201
-------
Gas Lines
NOT APPLICABLE
5.4.2.3 Leak Detection by Continuous or Periodic Monitoring of Internal
Fluid Flow Variations during Product Transfer—
Liguid Lines
1. DOT
No Regulation
2. PCS
No OCS Order
3. API
Not Discussed
4. DnV
DnV 9.2.2.3 "It may be required that the product flow at de-
livering and receiving stations along the pipe-
line is measured continuously or at regular in-
tervals for the purpose of leakage detection."
5. IP
Not Discussed
6. Pipeline Company A
• Any substantial leaks are detected by volume com-
parators in permanent operation. Communication
equipment provides a permanent comparison of the
oil flow rates recorded at relief stations and at
delivery terminals. If the difference in volumes
measured upstream and downstream from a given
point exceeds a certain threshold, a visual and
acoustic alarm is triggered.
Gas Lines
7. DOT (U.S. Regulation)
No Regulation
5.4.2.4 Leak Detection and Location of Leaked Oil on or at a Short Dis-
tance from Line—
1. DOT (U.S. Regulation)
No Regulation
2. PCS
No QCS Order
202
-------
3. API
Not Discussed
4. DnV
5. IP
6. Pipeline Company A
Metal rods, attached to the pipelines by brazing
at approximate intervals of 500 m (1,640.5 ft)
permit the localization of leaks monitoring of
the oil flow carried out systematically by means
of appropriate equipment.
5.4.2.5 Leak Detection by Periodic Pressure Testing of Existing Pipeline
Systems—
Liquid Lines
1. DOT (U.S. Regulations)
No regulations of in-service oil pipelines.
There are regulations (see CFR 195.3) for newly
constructed replaced or otherwise changed.
2. PCS
No OCS Order
3. API
Not Discussed
DnV
See Section 5.4.1.5
IP
4.
5.
IP 9.2
"When the pipeline is not in operation, it is re-
commended that it be shut down under pressure,
except on occasions when the shut-down has been
arranged to allow maintenance on the line and a
careful record made of the pressure during the
shut-down period.
If the pipeline crosses areas where there are
particular dangers of water pollution being
caused by any leakage, then a static pressure
test as described above should be arranged over
a period of 24 hours once per year."
203
-------
6. Pipeline Company A
Very small leaks, which have limited immediate
consequences but the effects of which may be
noticed for a substantial period, are detected by:
• differential pressure measurements between
various sections of the pipeline.
This inspection involves the periodic verification
that pipelines are leakproof, by means of hydro-
static tests on each of the sections located be-
tween block valves (located 12.4 to 15.5 miles
apart).
Gas Lines
7. DOT (U.S. Regulation)
49 CFT 192.743 Pressure limiting and regulating stations: test-
ing of relief devices -
"(a) If feasible, pressure relief devices (except
rupture discs) must be tested in place, at
intervals not exceeding 1 year, to determine
that they have enough capacity to limit the
pressure on the facilities to which they are
connected to the desired maximum pressure.
(b) If a test is not feasible, review and calcu-
lation of the required capacity of the re-
lieving device at each station must be made,
at intervals not exceeding one year, and
these required capacities compared.with the
rated or experimentally determined relieving
capacity of the device for the operating con-
ditions under which it works.
(c) If the relieving device is of insufficient
capacity, a new or additional device must be
installed to provide the additional capacity
required."
8. DOT (U.S. Regulation)
No Regulation
204
-------
5.4.2.6 Corrosion Inspection—
5.4.2.6.1 Corrosion Inspection and Maintenance - Atmospheric
Liquid Lines
1. DOT (U.S. Regulation)
49 CFR 195.416"(D) Each carrier shall, at intervals not exceeding
5 years, electrically inspect the bare pipe in
its pipeline system that is not cathodically
protected and must study leak records for that
pipe to determine if additional protection is
needed.
(e) Whenever any buried pipe is exposed for any
reason, the carrier shall examine the pipe
for evidence of external corrosion. If the
carrier finds that there is active corrosion,
that the surface of the pipe is generally
pitted, or that corrosion has caused a leak,
it shall investigate further to determine the
extend of the corrosion.
(f) Any pipe that is found to be generally corroded
so that the remaining wall thickness is less
than the minimum thickness required by the pipe
specification tolerances must either be re-
placed with coated pipe that meets the require-
ments of this part or, if the area is small,
must be repaired. However, the carrier need
not replace generally corroded pipe if the
operating pressure is reduced to be commensur-
ate with the limits on operating pressure
specified in this subpart, based on the actual
remaining wall thickness.
(g) If isolated corrosion pitting is found, the
carrier shall repair or replace the pipe un-
less—
(1) The diameter of the corrosion pits, as
measured at the surface of the pipe, is
less than the nominal wall thickness of
the pipe; and
(2) The remaining wall thickness at the bottom
of the pits is at least 70 percent of the
nominal wall thickness.
(h) Each carrier shall clean, coat with material
suitable for the prevention of atmospheric
corrosion, and, maintain this protection for,
each component in its pipeline system that is
exposed to the atmosphere."
205
-------
2. PCS
No OCS Order
3. API
API 801.3 "Carbon steel pipe, valves and fittings exposed to the
atmosphere should be protected with an external coat-
ing, when such protection is necessary."
4. DnV
Not Discussed
5. IP,
Not Discussed
6. Pipeline Company A
Not Discussed
Gas Lines
7. DOT (U.S. Regulation)
No Regulation
8. DVT (U.S. Regulation)
No Regulation
5.4.2.6.2 Internal Corrosion Control
Liquid Lines
1. DOT (U.S. Regulation)
49 CFR 195.418 "(a) No carrier may transport any commodity that
would corrode the pipe or other components
of its pipeline system, unless it has inves-
tigated the corrosive effect of the commodity
on the system and has taken adequate steps to
mitigate corrosion.
(b) If corrosion inhibitors are used to mitigate
internal corrosion the carrier shall use in-
hibitors in sufficient quantity to protect
the entire part of the system and shall also
use coupons or other monitoring equipment to
determine their effectiveness.
(c) The carrier shall, at intervals not exceeding
6 months, examine coupons or other types of
monitoring equipment to determine the effec-
tiveness of the inhibitors or the extent of
any corrosion.
206
-------
(d) Whenever any pipe is removed from the pipe-
line for any reason, the carrier must in-
spect the internal surface for evidence of
corrosion. If the pipe is generally corroded
such that the remaining wall thickness is
less than the minimum thickness required by
the pipe specification tolerances^ the car-
rier shall investigate adjacent pipe to de-
termine the extent of the corrosion. The
corroded pipe must be replaced with pipe
that meets the requirements of this part or,
based on the actual remaining wall thickness,
the operating pressure must be reduced to be
commensurate with the limits on operating
pressure specified in this subpart."
2. PCS
No OCS Order
3. API
API 803 "NANCE RP-01-75 should be used to determine the need
for design, installation and evaluation of the re-
sults of an internal corrosion mitigation program.
Where necessary, internal corrosion may be mitigated
by one or more of the following: pipeline scraping,
pigging, or sphering at regular intervals, dehydration,
inhibition, bactericides,- oxygen scavengers, and pipe-
line internal coating. The variables and severity of
each case will determine the preventive methods that
should be used. A monitoring program should be es-
tablished to evaluate the results of internal corrosion
mitigation systems."
4. DnV
DnV 6.6.1.1 "Internal protection is to be considered for pipe-
lines and risers which during installation or op-
eration may be subject to corrosion. Information
about the possibilities of internal corrosion is
to be submitted for evaluation. Treatment of the
product to be transported may be utilized as a
means of controlling corrosion, likewise pigging
at regulat intervals and corrosion monitoring."
5.
IP 8.1 "The operation of pipelines depends to a large extent
upon the nature of the fluids being handled, and each
operator should formulate a procedure for safe pipe-
line operation. Particular emphasis should be laid
upon the following:
(e) Prevention of internal corrosion."
207
-------
Pipeline Company A
Experience has shown that in the case of crude oil pipelines,
•internal corrosion is practically non-existant on account of
the products transported. However, as a precaution, "corrosion
detectors" are installed at 62.1 mile intervals and examined
once every year.
Gas Lines
7. DOT (U.S. Regulation)
49 CFR 192.475 "(a) After July 31, 1972, corrosive gas may not
be transported by pipeline, unless the cor-
rosive effect of the gas on the pipeline has
been investigated and steps have been taken
to minimize internal corrosion.
(b) Whenever any pipe is removed from a pipeline
for any reason, the internal surface must be
inspected for evidence of corrosion. If in-
ternal corrosion is found—
(1) The adjacent pipe must be investigated
to determine the extent of internal cor-
rosion;
(2) Replacement must be made to the extent
required by the applicable paragraphs
of § 192.485, § 192.487, or § 192.489;
and
(3) Steps must be taken to minimize the in-
ternal corrosion.
(c) Gas containing more than 0.1 grain of hydro-
gen sulfide per 100 standard cubic feet may
not be stored in pipe-type of bottle-type
holders."
49 CFR 192.77 "If corrosive gas is being transported, coupons
or other suitable means must be used to determine
the effectiveness of the steps taken to minimize
internal corrosion. After July 31, 1972, each
coupon or other means of monitoring internal cor-
rosion must be checked at intervals not exceeding
6 months."
8. DOT (U.S. Regulation)
No Regulation
208
-------
5.4.2.6.3 Cathodic Protection System-External
Liquid Lines
1. DOT (U.S. Regulation)
49 CFR 195.414 "(a) After March 31, 1973, no carrier may operate
a pipeline that has an external surface coat-
ing material, unless that pipeline is cathodi-
cally protected. This paragraph does not ap-
ply to tank farms and buried pumping station
piping.
(b) Each carrier shall electrically inspect each
bare pipeline before April 1, 1975, to deter-
mine any areas in which active corrosion is
taking place. The carrier may not increase
its established operating pressure on a sec-
tion of bare pipeline until the section has
been so electrically inspected. In any
areas where active corrosion is found, the
carrier shall provide cathodic protection.
Section 195.416 (f) and (g) applies to all
corroded pipe that is found.
(c) Each carrier shall electrically inspect all
tank farms and buried pumping station piping
before April 1, 1973, as to the need for
cathodic protection, and cathodic protection
shall be provided where necessary.
(d) Notwithstanding the deadline for compliance
in paragraphs (a), (b), and (c) of this sec-
tion, this section does not apply to offshore
pipelines located between a production facil-
ity and a carrier's trunk!ine reception point
until August 1, 1977."
49 CFR 195.416 External Corrosion Control-
"(a) Each carrier shall, at intervals not exceed-
ing 12 months, conduct tests on each under-
ground facility in its pipeline system that
is under cathodic protection to determine
whether the protection is adequate."
2. PCS
No DCS Order
3. API
API 804 "The cathodic protection system should be maintained in
accordance with the recommendation in NACF RP-06-75.
The effectiveness of the cathocis protection system
should be evaluated at least annually. Voltage and
current output of impressed current systems should be
209
-------
5.
verified and recorded at two-month intervals. Inter-
ference bonds, where failure would jeopardize pipeline
protection, should be checked for proper operation at
two-month intervals."
4. DnV
DnV 9.3.2.2 "Control of the performance of the cathodic pro-
tection system is required. The extent of such
testing may be reduced to scrutinizing of the
Owner's potential measurement reports. If found
necessary, potential measurements are to be con-
ducted at the discretion of the Surveyor and in
accordance with 8.8.3."
IP_
IP 8.1 "The operation of pipelines depends to a large extent
upon the nature of the fluids being handled, and each
operator should formulate a procedure for safe pipe-
line operation. Particular emphasis should be laid
upon the following: (f) Regular checking of the cath-
odic protection installation."
IP 7.5.4 Operation and Maintenance-
"Regular attention to current consumption figures at
each installation is essential. Adequate protection
depends almost entirely on maintaining the safety
level of pipe-to-soil potential along the whole route.
Pipe-to-soil measurements should be taken at least
annually or whenever an abnormal condition is indi-
cated. Highly corrosive areas should receive special
attention. In addition, the pipe-to-soil potential
of other structures crossing the pipeline route should
be checked for any adverse changes, whether or not
they are bonded into the cathodic protection system."
6. Pipeline Company A
The pipelines must be effectively protected against external
corrosion by means of:
• Passive protection provided by appropriate
coatings;
• Active protection provided by a cathodic pro-
tection system.
In order to verify the satisfactory operation of these units and
consequently the effectivensss of the cathodic protection, 250
"potential measuring points" have been installed, especially at
intersections with buried metal pipes and at large crossings.
The line is protected against corrosion by keeping it at a nega-
tive potential with respect to the soil. This negative potential
is maintained by means of a system including supply stations,
which are checked every month, and insulating joints located up
and downstream of the pumping stations, upstream of the delivery
points and the crossings of large rivers.
210
-------
Gas Lines
7. DOT (U.S. Regulation)
49 CFR 192.475 "(a) Each pipeline that is under cathodic protec-
tion must be tested at least once each calen-
dar year, but with intervals not exceeding
15 months, to determine whether the cathodic
protection meeting the requirements of
§ 192.463. However, if tests at those in-
tervals are impractical for separately pro-
tected service lines or short sections of
protected mains, not in excess of 100 feet,
these service lines and mains may be surveyed
on a sampling basis. At least 10 percent of
these protected structures, distributed over
the entire system, must be surveyed each
calendar year, with a different 10 percent
checked each subsequent year, so that the
entire system is tested in each 10-year period.
(b) At intervals not exceeding 2 months, each
cathodic protection rectifier or other im-
pressed current power source must be inspected
to ensure that it is operating.
(c) At intervals not exceeding 2 months, each re-
verse current switch, each diode, and each
interference bond whose failure would jeopar-
dize structure protection, must be electrically
checked for proper performance. Each other in-
terference bond must be checked at least once
each calendar year, but with intervals not ex-
ceeding 15 months.
(d) Each operator shall take prompt remedial ac-
tion to correct any deficiencies indicated by
the monitoring.
(e) After the initial evaluation required by para-
graphs (b) and (c) of §192.455 and paragraph
(b) of §192.457, each operator shall, at in-
tervals not exceeding 3 years, reevaluate its
unprotected pipelines and cathodically protect
them in accordance with this subpart in areas
in which active corrosion is found. The op-
erator shall determine the areas of active
corrosion by electrical survey, or where elec-
trical survey is impractical, by the study of
corrosion and leak history records, by leak
detection survey, or by other means."
8. DOT (U.S. Regulation)
No Regulation
211
-------
5.4.2.6.4 Chemical Monitoring
Liquid Line
1. DOT (U.S. Regulation)
No Regulation
2. PCS
No OCS Order
3. API
Not Discussed
4. DnV
DnV 9.2.2.2 "It may be required that the concentrations of
various chemical or physical components in the
product are measured and recorded at regular
intervals."
5. If.
Not Discussed
6. Pipeline Company A
Not Discussed
Gas Lines
7. DOT (U.S. Regulation)
No Regulation
8. DOT (U.S. Regulation)
No Regulation
5.4.2.7 Standard Non-Destructive Inspections to Check Integrity of Pipe-
line (Flaws, Cracks, Buckling, Dents and Other Potential Failure
Conditions) —
Liquid Lines
1. DOT (U.S. Regulation)
49 CFR 195.418 "(d) Whenever any pipe is removed from the pipe-
line for any reason, the carrier must in-
spect the internal surface for evidence of
corrosion. If the pipe is generally corroded
such that the remaining wall thickness is less
than the minimum thickness required by the
pipe specification tolerances, the carrier
shall investigate adjacent pipe to determine
the extent of the corrosion. The corroded
pipe must be replaced with pipe that meets
the requirements of this part or, based on
212
-------
the actual remaining wall thickness, the op-
erating pressure must be reduced to commen-
surate with the limits on operating pressure
specified in this subpart."
2. DCS
No DCS Order
3. API
Not Discussed
4. DnV
Not Discussed
5. IP.
IP 11.10 "Regular underwater inspection should be carried out
where there is risk of damage to the pipeline or where
scour conditions may occur."
6. Pipeline Company A
Not Discussed
Gas Lines
7. DOT (U.S. Regulation)
Not Discussed
8. DOT (U.S. Regulation)
Not Discussed
5.4.2.8 Inspection Pigs to Check the Integrity of Pipeline (Flaws, Cracks,
Buckling, Dents and Other Potential Failure Conditions)--
Liquid Lines
1. DOT (U.S. Regulation)
No Regulations
2. PCS
No OCS Orders
3. API
Not Discussed
4. DnV
DnV 9.3.2.3 "Inspection by gauging-pig (e.g., caliper-pig is
required for detection of buckles or dents in the
pipeline/riser."
213
-------
DnV 9.3.2.5 "Thickness measurements may be required where
there is reason to believe that the pipe wall
thickness is being reduced due to external/
internal corrosion or internal erosion (e.g.,
the effect of sand content in the transported
gas).
5. IP.
IP 11.10 "Regular underwater inspection should be carried out
where there is risk of damage to the pipeline or where
scour conditions may occur."
6. Pipeline Company A
Not Discussed
Gas Lines
1. DOT (U.S. Regulation)
No Regulations
8. DOT (U.S. Regulation)
No Regulations
5.4.2.9 Survey-Pipeline Systems Charting and Depth of Burial--
Liquid Lines
1. DOT (U.S. Regulation)
49 CFR 195.404 "(a), Each carrier shall maintain current maps and
records of its pipeline systems that include
at least the following information:
(1) Location and identification of all major
facilities.
(2) All crossings of public roads, railroads,
rivers, buried utilities, and foreign
pipelines.
(3) The maximum operating pressure of each
pipeline.
(4) The diameter, grade, type, and nominal
wall thickness of the pipe.
(b) Each carrier shall maintain daily operating
records that indicate the discharge pressures
at each pump station and any unusual opera-
tions of a facility. The carrier shall re-
tain these records for at least 3 years.
(c) Each carrier shall also maintain for the use-
ful life of that part of the pipeline system
to which they relate, records that include
the following:
214
-------
(1) The date, location, and description of
each repair made to its pipeline systems.
(2) A record of each inspection and each test
required by this subpart."
2. DCS
PCS #9, l.A "The operator shall be responsible for the installa-
tion of the following control devices on all oil
and gas pipelines connected to a platform includ-
ing pipelines which are not operated or owned by
the operator... The operator shall submit records
semi-annually showing the present status and past
history of each device, including dates and details
of inspection, testing, repairing, adjustment, and
reinstallation."
PCS #9. l.E "... records of these inspections including the
date, methods and results of each inspection shall
be maintained by the pipeline operator and sub-
mitted annually by April 1 ..."
3. API
API 703 "The following records should be maintained for opera-
tions and maintenance purposes:
} Material and construction specifications.
'b) Route maps and alignment sheets.
(c) Coating and cathodic protection specifications.
(d) Pressure test data.
[e) Non-destructive inspection data.
(f) Necessary operational data.
(g) Pipeline patrol records.
(h) Corrosion mitigation records recommended in 805.1.
(i) Leak and break records and failure investigation
records.
[j) Records of safety equipment inspection.
[k) Records of other inspections, such as external or
internal pipe conditions when line is cut or hot
tapped.
The records recommended in (e), (f), (g) and (j) should
be retained for at least one year. Other recommended
records should be retained for the life of the facility
unless states otherwise in this Recommended Practice."
4. DnV
DnV 9.2.3.2 "Files on Owner's inspection reports are to be
available in connection with surveys required by
the Society."
DnV 9.2.3.3 "The Society's requirements for maintenance and
repair will be based on information obtained from
periodical surveys and special surveys if appli-
cable."
215
-------
5. IP.
IP 11.10 "Regular underwater inspection should be carried out
where there is risk of damage to the pipeline or where
scour conditions may occur."
6. Pipeline Company A
Not Discussed
Gas Lines
7. DOT (U.S. Regulation)
49 CFR 192.709 "Each operator shall keep records covering each
leak discovered, repair made, transmission line
break, leakage survey, line patrol, and inspec-
tion, for as long as the segment of transmission
line involved remains in service."
8. DOT (U.S. Regulation)
No Regulation
5.4.2.10 Miscellaneous-Leak Detection and Prevention by Equipment Inspec-
tion—
Liquid Lines
1. DOT (U.S. Regulation)
No regulations for oil lines. There are line regulations for
liquefied gases as follows:
DOT CFR 195.428"(a) Except as provided in paragraph (b) of this
section, each carrier shall, at intervals
not exceeding 12 months, or 6 months in the
case of pipelines used to carry liquefied
gages, inspect and test each pressure limit-
ing device, relief valve, pressure regulator,
or other item of pressure control equipment
to determine that it is functioning properly,
is in good mechanical condition, and is ade-
quate from the standpoint of capacity and
reliability of operation for the service in
which it is used.
(b) In the case of relief valves on pressure stor-
age vessels containing liquefied gas, each
carrier shall test each valve at intervals
not exceeding 5 years."
2. PCS
No OCS Order
3. API
Comments on safety equipment on nonproduction platforms are
presented in 701.6.
216
-------
4. DnV
Not Discussed
5. IP
Not Discussed
6. Pipeline Company A
Block valves are housed inside a sealed casing in order to avoid
any contamination of the surrounding area.
A center is provided with data concerning the hydraulic condi-
tion of the pipelines and the position of each of the block-
valves, which can be shut by remote control for safety"reasons.
Gas Lines
7. DOT (U.S. Regulation)
49 CFR 192.706 "(a) Each operator of a transmission line shall
provide for periodic leakage surveys of the
line in its operating and maintenance plan.
(b) Leakage surveys of a transmission line must
be conducted at intervals not exceeding 1
year. However, in the case of a transmission
line which transports gas in conformity with
§192.625 without an odor or odorant, leakage
surveys using leak detector equipment must
be conducted:
(1) In Class 3 locations, at intervals not
exceeding 6 months; and
(2) In Class 4 locations, at intervals not
exceeding 3 months.
5.4.2.11 Miscellaneous-Safety Equipment and Pressure Limiting and Reliev-
ing Devices—
Liquid Lines
1. DOT (U.S. Regulation)
49 CFR 195.426 Scraper and Sphere Facilities-
"No carrier shall use a launcher or receiver
that is not equipped with a relief device capa-
ble of safely relieving pressure in the barrel
before insertion or removal of scrapers or
spheres. The carrier must use a suitable device
to indicate that pressure has been relieved in
the barrel or must provide a means to prevent
insertion or removal of scrapers or spheres if
pressure has not been relieved in the barrel."
217
-------
49 CFR 195.428 Overpressure Safety Devices-
"(a) Except as provided in paragraph (b) of
this section, each carrier shall, at
intervals not exceeding 12 months, or
6 months in the case of pipelines used
to carry liquefied gases, inspect and
test each pressure limiting device, re-
lief valve, pressure regulator, or other
item of pressure control equipment to de-
termine that it is functioning properly,
is in good mechanical condition, and is
adequate from the standpoint of capacity
and reliability of operation for the ser-
vice in which it is used.
(b) In the case of relief valves on pressure
storage vessels containing liquefied gas,
each carrier shall test each valve at in-
tervals not exceeding 5 years."
2. PCS
No OCS Order
3. API
API 701.6 Safety Equipment on Non-Production Platforms-
"Pressure limiting devices, relief valves, automatic shutdown
valves, and other safety devices, except check valves should be
subjected to periodic inspections at a maximum interval of six
months. The inspection should verify that the device is in good
mechanical condition and properly performs the safety function
for which it was installed.
4. DnV
DnV 9.3.2.6 "Pressure limiting devices, relief valves, auto-
matic shutdown valves and other safety devices
should be tested and inspected. The inspection
should verify that the device is in good mechan-
ical condition and properly performs the safety
function for which it was installed."
5. IP
IP 8.1(a) "Safety devices for protecting the pipeline from pres-
sures in excess of those for which it was designed."
IP 8.l(b) "Instruments to give warning and shut down pumps in
case of damage caused to the pipeline by Act of God
or third party activities.
6. Pipel.ine Company A
Each valve is housed inside a sealed casing in order to avoid
any contamination of the surrounding area.
218
-------
Gas Lines
7. DOT (U.S. Regulation)
49 CFR 192.731 Compressor Stations: Inspection and Testing of
Relief Devices:
(a) Except for rupture discs, each pressure re-
lieving device in a compressor station must
be inspected and tested in accordance with
§§192.739 and 192.743, and must be operated
periodically to determine that it opens at
the correct set pressure.
(b) Any defective or inadequate equipment found
must be promptly repaired or replaced.
(c) Each remote control shutdown device must be
inspected and tested, at intervals not to
exceed 1 year, to determine that it functions
properly."
49 CFR 192.737 Pipe-Type and Bottle-Type Holders: Plan for In-
spection and Testing-
"(c) The pressure control and pressure limiting
equipment must be inspected and tested
periodically to determine that it is in a
safe operating condition and has adequate
capacity."
49 CFR 192.739 Pressure Limiting and Regulating Stations: In-
spection and Testing-
"Each pressure limiting station, relief device
(except rupture discs), and pressure regulating
station and its equipment must be subjected, at
intervals not exceeding 1 year, to inspections
and tests to determine that it is:
a) In good mechanical condition;
b) Adequate from the standpoint of capacity
and reliability of operating for the ser-
vice in which it is employed;
(c) Set to function at the correct pressure;
and
(d) Properly installed and protected from dirt,
liquids, or other conditions that might pre-
vent proper operation."
49 CFR 192.743 Pressure Limiting and Regulating Stations: Test-
ing or Relief Devices-
"(a) If feasible, pressure relief devices (except
rupture discs) must be tested in place, at
intervals not exceeding 1 year, to determine
219
-------
that they have enough capacity to limit the
pressure on the facilities to which they
are connected to the desired maximum pres-
sure.
(b) If a test is not feasible, review and calcu-
lation of the required capacity of the reliev-
ing device at each station must be made, at
intervals not exceeding one year, and these
required capacities compared with the rated
or experimentally determined relieving capa-
city of the device for the operating condi-
tions under which it works.
(c) If the relieving device is of insufficient
capacity, a new or additional device must
be installed to provide the additional capa-
city required."
8. DOT (U.S. Regulation)
No Regulation
5.4.2.12 Pipe Maintenance
1. DOT (U.S. Regulation)
49 CFR 195.402 General Requirements-
"(b) No carrier may operate or maintain its pipe-
line systems at a level of safety lower than
required by this subpart and the procedures
it is required to establish under paragraph
(a) of this section.
(c) Whenever a carrier discovers any condition
that could adversely affect the safe opera-
tion of its pipeline system it shall correct
it within a reasonable time. However, if
the condition is of such a nature that it
presents an immediate hazard to persons or
property, the carrier may not operate the
affected part of the system until it has
corrected the unsafe condition."
49 CFR 195.422 Pipeline Repairs-
"(a) Each carrier shall, in repairing its pipeline
systems, insure that the repairs are made in
a safe manner and are made so as to prevent
damage to persons or property.
(b) No carrier may use any pipe, valve, or fitting,
for replacement in repairing pipeline facili-
ties, unless it is designed and constructed as
required by this part."
220
-------
2. PCS
No OCS 'Order
3. API
API 701.1 "Written starting, operating and shutdown procedures
for pipeline facilities should be established and the
operating company should take appropriate steps to
see that these procedures are followed. These pro-
cedures should outline preventive measures and system
checks as required to provide for the proper function-
ing of safety, control and alarm equipment."
4. DnV
DnV 9.1.2.1 "If it is found that the pipeline/riser in some
way does not meet the Rules, the Society will re-
quire improvements, new surveys, or other mea-
sures found necessary in order to retain the
Certificate of Approval, regardless of previous
approvals."
DnV 9.2.3.1 "The Owner should provide such running inspection
of the pipeline system as to initiate maintenance
work necessary to retain the built-in safety."
DnV 9.3.2.1 "Survey of exposed parts of the pipeline, i.e.,
not buried parts, is required to verify that no
unacceptable damages have occured to the pipe,
the corrosion protection system, or the weight
coating (anchoring system)."
5. IP.
IP 9.3 "It is not always necessary to empty and gasfree a
pipeline or to use water plugs in order to carry out
maintenance or repair work which involves cutting and
re-welding the line. These operations may be safely
performed provided that the right conditions have been
achieved."
6. Pipeline Company A
Not Discussed
Gas Lines
7. DOT (U.S. Regulation)
49 CFR 192.631 "(a) Each operator shall have a procedure or con-
tinuing surveillance of its facilities to
determine and take appropriate action con-
cerning changes in class location, failures,
leakage history, corrosion, substantial
changes in cathodic protection requirements,
and other unusual operating and maintenance
conditions.
221
-------
(b) If a segment of pipeline is determined to
be in unsatisfactory condition but no imme-
diate hazard exists, the operator shall ini-
tiate a program to recondition or phase out
the segment involved, or, of the segment can-
not be reconditioned or phased out, reduce
the maximum allowable operating pressure in
accordance with § 192.619 (a) and (b)."
8. DOT (U.S. Regulation)
Not Discussed
222
-------
SECTION 6
ANALYSIS OF THE RISK OF ACCIDENTAL OIL SPILLS
FROM PETROLEUM PIPELINE SYSTEMS
An analysis of the risk of accidental oil spills from petroleum pipe-
line systems is carried out in this section. Both the risk that oil can
spill from a system and environmental problems created by spillage are
examined. First, the seriousness of oil spills is discussed in Section 6.1.
Then the difficulties in assessing the risk of oil spills are reviewed in
Section 6.2. Approaches accounting for these difficulties are presented.
Finally, an analysis and assessment of the risk of oil spills was carried
out in Section 6.3.
Since the risk of oil spills and the potential for risk reduction
were both found to be much greater for line pipe than for any other pipe-
line system component, an in-depth analysis of the risk of oil spills from
line pipe was carried out in Section 6.3. An analysis was performed on a
reference line (typical line), and correction factors for variations from
the reference line were developed so that the spill risk (potential) could
be established for most lines. Simplified tables and figures were provided
to enable an operator to estimate the spill potential of his own line.
6.1 SERIOUSNESS OF OIL SPILLS
Petroleum pipeline systems and line pipe, in particular, present a
continuous potential for serious accidents and spills. Spills are ex-
pected to increase as the U.S. liquid pipeline system ages3. These are
the obvious conclusions when data from accidental spills (Section 4.5.2)
and individual accident reports are examined and oil spill risks evaluated
(Appendix D). This situation exists even though petroleum pipeline trans-
portation systems produce relatively few reported spills for the large
quantities of oil transported.
Accidental spills are a serious matter and are detrimental to both
the national interest and the oil and gas industries. The major problems
created by these spills are:
• Subject segments of the population to potential catastrophies.
• Cause significant environmental damage.
• Cause losses of large quantities of petroleum.
aAverage age of the U.S. liquid pipeline increases yearly.
223
-------
Responsibility for the spill problem rests with both the government and
operating companies, who must use the best means available to minimize the
frequency and volume of spills and the resultant spill damage.
Various sources contribute to serious accidents in the petroleum pipe-
line system. Some of the major ones include:
• Properties and characteristics of the petroleum itself create
serious hazards (even losses of small quantities, i.e., few
barrels, can cause serious damage in some situations).
• Large volumes of petroleum transported through the system
potentially can result in large volumes of petroleum spilled.
• Inadequacies and/or limitations in the spill prevention and
detection measures.
• Variety of causes and types of pipeline system failures.
The potential for serious accidents is magnified when pipeline systems
are located in or near high-risk areas. Some of these are:
• High population density
• Heavy industrial areas
• Commercial areas
• Underground water supplies
• Underground facilities
• Offshore.
Although petroleum pipeline systems are relatively safe, serious spills
can and do occur for a variety of reasons. For example, large volumes of
petroleum are transported using lines that are not under continuous surveil-
lance. This can result in large volumes of hazardous fluids (thousands of
barrels) being spilled before the spill is detected and the line shut down.
Since explosions from crude and petroleum lines have occurred hundreds of
feet from a break58, the possibility exists, primarily in populated areas
(urban, commercial, industrial), for exposure of large numbers of people
and large amounts of property to potential hazards. The serious problems
that exist can be emphasized by examining a few case histories. In the
city of Los Angeles, for example, a network exists of approximately 200
miles of pipelines owned by 32 oil companies. One line which runs beneath
a school ruptured and exploded in 1976 and eight persons were killed72. In
another case, a crude leak caused an explosion near a heavily traveled free-
way. Fortunately, this crude line did not cause leaks in the gas and pro-
duct transmission lines located a short distance away. Other serious prob-
lems such as damage to water supplies are also possible. A recent study1*6
indicates that serious spill hazards to undergound water supplies exist and
identifies numerous cases of damage to underground water sources. The hun-
dreds of serious spills that have occurred within the last ten years con-
clusively illustrates the potential for serious spills. •
224
-------
These types of serious spills are often considered as highly improba-
ble, but serious accidents often do not follow statistical probabilities.
The nuclear powerplant accident in Pennsylvania in early 1979 and the ex-
plosion of the almost empty crude oil tanker in -the Los Angeles Harbor in
1978 are dramatic examples of highly improbable accidents. In the ship
explosion, a number of fatalities occurred and windows were broken by the
blast pressure wave at distances up to ten miles. In the nuclear reactor
accident, segments of the community were evacuated as a precautionary mea-
sure.
Comparisons are often made, such as in Figure 48, of the relative
safety of pipeline systems to other modes of transportation. Such compari-
sons are often misleading. For example, the significance of comparing
auto fatalities with pipeline fatalities is questionable. At least 95
percent of the U.S. population routinely uses automobiles, and thus the
expected fatalities are high. However, only a small percentage of the
population use pipeline facilities or are in close proximity to lines.
A further examination of the auto fatalities actually reveals that gasoline
is the cargo most frequently responsible for highway deaths (about 10 per-
cent). This latter information acutually demonstrates the hazard potential
of petroleum spills. If one were to use other comparisons such as the po-
tential of a major catastrophe from a single accident, the results would
be less favorable for pipeline systems.
6.2 PROBLEMS IN ASSESSING THE OIL SPILL RISK
It is difficult to assess quantitatively the actual oil spill risk
from U.S. petroleum pipeline systems. There are a number of reasons for
this. The main reasons are:
• Oil spills can result in a variety of risks that must
properly be identified and categorized.
• No industry standards exist for comparing and evaluating
spill risks.
• Limited information is available on oil spill statistics.
• Limited information on the variations of the complex pipe-
line systems.
• Lack of suitable analysis scheme for variations of pipe-
line systems.
These major difficulties can be accounted for. Each will be discussed
separately in the subsections that follow.
6.2.1 Identification and Categorization
Oil spills can result in a variety of significant risks such as the
substantial loss of petroleum and serious problems external to the line.
These risks must be properly identified and categorized to insure suitable
analysis of the problem so that needed spill prevention and control can be
identified. To satisfy these objectives, risks have been separated into
the following two categories:
225
-------
MARINE
GENERAL AVIATION
1,324
AIR CARRIERS
124
GRADE CROSSING
910
PEDALCYCIES
(Bieyeias)
900
Numfacrj are preliminary
estimates.
Figure 48. Transportation accidents in 1975, National Transportation
Safety Board 1975.
226
-------
• Risks that oil will escape from the pipeline system by
accidental spillage.
• Risks external to the pipeline system after petroleum es-
capes from the line.
The first risk category deals primarily with the actual loss of petro-
leum from the line. The risk, in general, is independent of line location.
The specific risks of spill incidents and spill volume can be determined
from nationwide oil spillage statistics that are based on most lines. Also,
the spill reduction capabilities of the available inspection and leak de-
tection methods can be established for the line itself. These spill re-
duction capabilities are generally not dependent on line location.
The second category deals with additional risks, such as property
damage or injuries that exist external to the pipeline system. These
risks, in general, are dependent on line location. Hence, this category
enables one to identify the various additional risks that may be charac-
teristic of a particular location. High-risk areas, for example, can be
identified and the extent of risk determined; the need for more effective
spill prevention methods can be established and the increases in cost ef-
fectiveness of the various options can be determined.
6,2.2 Comparison and Evaluation
There are no industry standards for comparing and evaluating the risk
that oil will escape from the pipeline system and risks external to the
line by accidental spillage. However, a variety of suitable means do
exist for assessing this risk.
6.2.2.1 Discussion of Risk of Oil Escaping from Pipelines—
We have selected two means that are most meaningful and practical in
this study for comparing and evaluating the risk that oil will escape from
the pipeline system. These are often used in oil, gas, and other industries,
The first means is to determine the risk of oil spills based on two
criteria:
• Frequency or probability that a spill may occur;
• Quantity of oil spilled.
Both of these are important. For example, the severity of spill accidents
based on injuries and property damage correlates almost directly with quan-
tity spilled, Figure 49. The frequency of spills is of significance, par-
ticularly in areas of high risk; in many areas even a small spill can be
extremely hazardous.
The second means, and the most meaningful, is to provide a measure of
the relative risk that accounts for both the frequency and volume of spills.
This is done by assessing the product (barrels per year) of the expected
227
-------
Injuries
Fatalities
.20-1
o>
OJ
«J
o
4)
ft
01
-------
frequency and volume of significant spills (typically greater than 50 bar-
rels). Although both the frequency and spill size are important in the
evaluation of spills, the product of both parts is typically the most useful
in comparing the spill risks of pipeline systems.
In general, a large number of small spills over a period of time is
normally expected to result in damage equivalent to one large spill81.
Based on fatalities alone, however, this equivalence does not apply. Large
spills (in excess of 500 barrels) are responsible for most of the fatali-
ties. This is apparent from spill statistics presented in Figure 49.
Evaluation of the measure of relative risk based solely on the mean
spill size is useful but somewhat limited. Spills between pumping stations,
for example, are expected to occur either as"leaks (small to medium spill
size) or ruptures (major spill size). Hence, an evaluation of the measure
of relative risk based on all three spill sizes (mean, leak, rupture) is
essential for a realistic evaluation of spills. It is particularly useful
in the development of a practical spill prevention program.
6.2.2.2 Discussion of Risks External to Pipeline System-
Risks external to a pipeline system are also assessed. No industry
standards exist for comparing and evaluating the risk of oil spillage after
escaping from the pipeline system. Furthermore, an in-depth assessment of
this risk is beyond the scope of this study. However, in this study, risks
are assessed at a level sufficient for the selection of methods for a spill
prevention program. Hence, sources of risks are identified and risk factors
assigned (see Section 6.3.2.5). It should be noted that an assessment of
the risk external to the pipeline system is extremely important in the
selection of optimum methods for a spill prevention program for a particular
line.
6.2.3 Applicable Spill Statistics
Available U.S. spill statistics are not ideal, and in many instances
are severely deficient regarding the development of spill risks of various
pipeline systems. Various government agencies have undertaken to collect
and compile spill statistics in order to understand and control the spill
problem. However, this information is not oriented towards analyzing and
reducing oil spill risks. For example, numerous spills and spill sizes
are reportable, but other vital information such as the hole size in the
pipe, flow rate, and shutdown time is not reportable. Also, oil spills in
certain areas and from certain gathering lines are not reportable. These
kinds of limitations and exclusions in spills reportable to U.S. agencies,
combined with deficiencies and noncompliance in spill reporting by operat-
ing companies (see Section 4.5.2), present limits and constraints on oil
spill risk analysis.
Despite these limitations, analysis of available spill statistics in-
dicates that sufficient data are available for developing guidelines for a
spill prevention program. Risks, for example, can be established for the
major and significant factors affecting oil spillage.
229
-------
6.2.4 Applicable Information on the Variations of the Complex Pipeline
System
The substantial amount of information that exists on U.S. petroleum
transportation is not oriented to the details of the various complex pipe-
line systems. Instead, information deals primarily with demand and supply-
quantities imported, produced, transported, etc.
Only a limited amount of information exists that is suitable for com-
paring individual lines to the U.S. total. Information is available on an
individual basis from each company, but there is no industry tool for many
of the variations between lines. For example, information is not available
on total mileage and age of line pipe for variations such as:
• Depth of burial
• Soil conditions
• Construction
• Materials.
This constraint somewhat restricts the analysis. However, sufficient in-
formation is available or can be estimated for the significant variations
that are essential for development of guidelines for spill prevention.
This is done in Section 6.3 for variations (e.g., line pipe age) of spe-
cific pipeline systems and the U.S. total.
6.2.5 Analysis Scheme for the Variations of Pipeline Systems
Risk assessment of the pipeline systems in the U.S. today is compli-
cated by the significant variations between systems. Although these vari-
ations can be estimated, they must be accounted for when assessing the
risks of oil spills of individual lines or the U.S. total. They also must
be accounted for so that an operator can assess the spill potential of his
particular line. A number of variations are important such as:
• Age
• Geometry
• Usage
• System shutdown time
• Throughput
• Other.
In order to handle this problem, the following scheme is used in this
study. Risks of spills are first established for a typical section of line
called a reference line. Then correction factors are established to account
for significant differences between the reference pipeline system and most
other lines. With this information, the spill risks for most lines can be
assessed.
230
-------
The ability to assess the risks of individual lines is particularly
useful for new lines, those in high risk areas, or where a spill problem
exists. An assessment capability enables one to determine the need and
the extent of a spill prevention program. It also aids in evaluating the
practicality and cost-effectiveness of such programs and the locations
where implementation may provide the greatest benefits.
6.3 ANALYSIS AND ASSESSMENT OF THE RISK OF ACCIDENTAL SPILLS
This section presents a detailed analysis and assessment of accidental
spills. The risk of oil accidentally spilling from a system and the re-
sultant environmental hazards are examined.
The major components of the petroleum pipeline transportation system
are first studied in Section 6.3.1. System component(s) with the highest
incidence of failure are examined. The risk of spills from line pipe is
found to be much greater than from any other petroleum pipeline system
components. Correspondingly, the potential for reducing line pipe spills
was also found to be much greater. Based on these results, oil spill
risks for line pipe were analyzed further.
Risks based on the frequency and volume of spills and their product
(relative measure of risk) are examined in Section 6.3.2. These risks
are estimated quantitatively for a reference line (a typical section of
line). Qualitative estimates are made for the risk of spill damage ex-
ternal to the reference line.
Correction factors that account for significant variations between
line pipes are considered in Section 6.3.3. Values are determined for
both line variations and the environment external to the line.
By applying these corrections to the reference line, the spill poten-
tial for most lines can be estimated. This is done is Section 6.3.4 for
the combination of all U.S. lines and a typical pipeline system. Simpli-
fied tables and figures are presented to enable a line operator to esti-
mate the spill potential of his own line.
The information from this section is used to estimate oil spillage
and cost effectiveness in Sections 6.5 and 6.6. It is also used in Sec-
tion 7 for the development of guidelines for a spill prevention program.
6.3.1 System Component(s) with the Highest Potential for Frequent and
Serious Spill Incidents
The petroleum pipeline transportation system model (see Sections 4.1.3
and 4.2.2) has been divided into the following four major components:
• Production
• Pumping stations
• Line pipe
• Storage facilities.
231
-------
These components account for all accidental spill incidents. Each major
component has been subdivided into a number of main system components
(see Figure 4 and Table 7). Each is considered in the evaluation of com-
ponents with the highest potential for frequent and serious spill inci-
dents.
Spills in petroleum pipeline systems have occurred at most components.
This is evidenced, for example, by the spill summary presented in Table 33.
However, careful review of the oil spill statistics (such as those pre-
sented in Section 4.5.2.1.2) clearly show that most spillage (over 80 per-
cent of the incidents and volume of spills) occurs in line pipe. Of the
remaining spills, only two components—tank farms and pumping stations--
account for more than two percent of the spill incidents and volume. Tank
farm spills typically account for about 13 percent of the spill volume and
and only eight percent of the incidents. Most storage tanks are surrounded
by dikes to contain accidental spills from tanks. This has significantly
reduced petroleum leakage outside the facility and loss of oil (oil can be
recovered). The incidence of spills from pumping stations is about eight
percent, while the volume spilled is only about three percent of the total.
This small spill volume is expected because of the constant vigilance of the
operating personnel. This enables almost immediate shutdown of the line or
other mitigating measures should a spill occur.
Further reduction of the spill risk of system components other than
line pipe appears difficult to attain. Existing U.S. regulations and op-
erating company practices insure effective and frequent inspections of pump
stations and tank storage facilities.
Once a line becomes operational, only limited and generally ineffective
line pipe inspection and leak detection methods are required by U.S. regula-
tions. These are primarily biweekly visual inspections and inspection and
maintenance of cathodic protection systems. Additionally, practices by
individual operating companies vary greatly, but methods other than pressure
monitoring at pump stations are not generally used. Fortunately, a signifi-
cant potential for spill reduction does exist because of available leak de-
tection and inspection methods. For example, some companies are using
existing continuous monitoring methods (pressure, flow, volume comparison)
or developing and implementing advanced methods. These methods are gener-
ally useful for identifying large sized breaks or ruptures. Additionally,
inspection of line pipe for internal damage or defects is often done and
offers great potential for reducing the frequency of spills.
Analysis indicates that implementation of a scheduled maintenance pro-
gram for line pipe offers the potential for significantly reducing the risk
of oil spills. Thus, the main objective and effort in this study is esti-
mating the spill risks and reduction of risks from line pipe by implementing
scheduled inspections and/or leak detection.
232
-------
6.3.2 Oil Spill Risks from a Typical Section of Line Pipe (Reference
Line)
Risk values for spills from a typical section of line pipe are estab-
lished in this section. The following approach is used:
• Typical section of line is defined (assumptions for this refer-
ence line are shown in Table 56).
• Failure modes are identified (failure modes are grouped into
three main causes of failure: line pipe faults, outside
forces and other causes. The advantages of grouping failure
modes by cause will be evident in the analysis carried out in
later sections that deal with spill prevention. Data for
failure analysis are based on the work carried out in Section
4.5.2.1.3).
• Fault tree11* (see Section 4.2) is constructed based on fail-
ure data'(For convenience, symbols used in this fault tree
are shown and defined in Figure 50).
• Fault tree is evaluated based on the values of the frequency
and mean value of accidental spilTTI
• Measure of relative risk is evaluated (based on the product
of spill frequency and volume for leaks, rupture and average
spills).
• Potential severity of the spill or the risk external to the
escaping oil is evaluated^
6.3.2.1 Risks—Frequency of Spills FST—
The expected frequency of spills F$y is the summation of the frequency
of spills for each of the individual causes of failures. Individual fail-
ures which could result in spill incidents from the typical section of line
pipe are identified in the fault tree9 of Figure 51.
The three main causes of failure are identified in Figure 51. They
are:
Line pipe faults (56 percent spills)
- Defective pipe (17 percent spills)
- Corrosion (39 percent spills)
Outside forces (41 percent spills)
- Impacts (34 percent spills)
- Non-Impacts (7 percent spills)
Other (3 percent spills).
Percentages indicated were obtained from Table 19.
233
-------
TABLE 56. ASSUMPTIONS FOR TYPICAL SECTION
OF LINE PIPE (REFERENCE LINE)
Age:
Oi ameter:
Length:
Commodity:
Flow velocity:
Flow rate:
Operating pressure:
Material:
Construction:
Line elevation:
Corrosion control:
Pump station
shutdown time:
Mainline valve
closure time:
External environment:
25 years
10 inches
1 mile
Crude oil
7 feet per second
2500 barrels per hour
1000 psi
Steel pipe
Butt weld joints
Buried underground at 3 feet depth
Horizontal
Coated with a cathodic protection system
2 minutes
72 minutes
Low risk
- on!and
- sparsely populated
- not near water
234
-------
The rectangle identifies an event
that results from the combination
of fault events through the input
logic gate.
The diamond describes a fault event
that is considered basic in a given
fault tree. The possible causes of
the event are of insufficient conse-
quence or the necessary information
is unavailable.
The circle describes a basic
fault event that requires no
further development. Frequency
and mode of failure of items so
identified are derived from
empirical data.
i t i
AND gate describes the logical
operation whereby the coexistence
of all Input events is required
to produce the output event.
The triangles are used as transfer
symbols. A line from the apex of
the triangle indicates a transfer
in and a line from the side denotes
a transfer out.
OR gate defines the situation
whereby the output event will
exist if one or more of the
input events exists.
Figure 50. Symbolism for fault trees.
235
-------
ro
CO
HEM SHU VOLUHC
A"
1.1 IMKIVUA*
SPILLS f ROH TYPICAL
LINE SECTION
(1 Nue LENGTH)
STILL FWOWIICV
A ,
/ \ '«
1.1 > 10 ' SPIUSWM
IBKHIAI
cowtosion
UllUttS
()1> SPILLS
US VOL.)
- DEFECTIVE FIFE
IMPACT DAMAGE
O.OS2 I 10° o.OZt I 10° ' 0.013 I 10°
O.Otl
-mi IMPACT DAMAGE-
HUE PIPE FAULTS
OUTSIDE FORCES
0 OH ( 10 "'
0 Oil
-MISCELIAHEOUS—"
I
Figure 51. Fault trees, VST and f^t spill frequency and volume from typical
section of line (reference line).
-------
Line pipe faults such as welds and seam defects and corrosion are respon-
sible for most spills from a typical section of line. These are failures
of the line pipe itself and potentially can be reduced by periodic inspec-
tions. Outside force incidents, primarily due to impacts, are significant
causes of the frequency of spills. These accidents usually involve human
error primarily due to insufficient communication between equipment and
pipeline operators. Such spills potentially can be reduced by a prevention
program that is currently recommended52and by leak detection systems that
detect impacts on lines before significant damage can occur.
The frequency of spills for the typical section of line pipe (10 in- 3
ches in diameter and 25 years old) is shown to be approximately 1.30 x 10
spins/mile-year, Figure 32. This is in reasonable agreement with both the
average (1.34 x 10-3 spins/mile-year) for all line pipe3, Table 26, and
the average (1.15 x 10~3 spins/mile-year) based on the line pipe age,
Table 28. Agreement would be expected because the typical line was assumed
to be the average diameter and age of line pipe in the U.S. Considering
that the U.S. statistics on the actual ages of all U.S. pipelines are not
known and mileages were based on estimates, these comparative values are
considered quite reasonable.
Data, such as given in Tables 19 and 21, indicate that "leak type"
spills (see Section 6.3.3.3) considered here as causing minor to medium
damage account for about 75 percent of all reported spills. The frequency
of all types of spills for the typical section of line pipe is 1.3 10-3
spins/mile-year. Thus, leaks are estimated to be 0.98 10" 3 spins/mile-
year. "Rupture type" spills (see Section 6.3.3.3) are considered to ac-
count for the remaining 25 percent of the reported spills. Thus, the es-
timated frequency of spills from ruptures is 0.32 x 10"3 spins/mile-year.
6.3.2.2 Risk—Volume of Spills V$T~
The expected spill volume VST is the summation of the spill volume for
lack of the individual causes of failures. Individual failures which could
result in spillage from the typical section of line pipe are identified
in the fault treeb of Figure 51.
The three main causes of failures are:
• Line pipe faults (53 percent volume)
- Defective pipe (35 percent volume)
- Corrosion (18 percent volume)
• Outside forces (46 percent volume)
- Impacts (33 percent volume)
- Non-Impacts (13 percent volume)
• Other (1 percent volume).
Excluding gathering lines.
Percentages indicated were obtained from Table 19.
237
-------
The total volume spilled from the typical section of line pipe is shown
to be approximately 1.3 barrels/mile-year, Figure 33. This result is in
agreement with the average volume spilled 1.4 barrels/mile-year for all
line pipe (Table 26) and the average volume spilled 1.3 barrels/mile-year
based on the average pipeline age (Table 28A).
6.3.2.3 Risks—Size of Spills VNLL, VNLR, VM—
"Leak type" spills are defined here as those spills that occur as a
slow escape of petroleum. These are caused by various line pipe faults
and result in hole-through failures ranging from pinhole to medium-sized
breaks. These spills are considered to cause small to medium damage (less
than 1000 barrels). The nominala largest leak spill size VNLL that could
be leaked from the reference line before being noticed and the operation
shut down is estimated at 400 barrels. This value, of course, can vary
widely depending upon the particular pipeline system. However, the value
is realistic considering the limitations of the following two main spill
monitoring methods in common use:
• Biweekly or ground patrol visual line inspections for direct
indications of leakage. This method, under worst-case condi-
tions, could allow leakage for the entire two-week interval
between inspections.
• Pipeline monitoring systems (i.e., pressure monitoring, flow
monitoring, etc.) typically can only detect a spill if devia-
tions exceed five percent of throughput.
"Rupture" type spills are defined here as those spills that occur as
a sudden escape of petroleum; they are normally caused by various line
pipe faults and result in hole-through failures ranging from medium-size
breaks to catastrophic failures. These spills are considered to cause
medium to major damage. The nominal largest rupture size VNLR f°r a major
pipeline rupture in the typical section of line is estimated to have a
maximum spillage of 7500 barrels. This is based on the assumption that a
rupture would be detected in about two minutes and about 72 minutes would be
required to close a mainline valve.
The mean spill size VM can be computed from the ratio of VST and F<-,..
The computation for the reference line is as follows:
V - v - 1.3 barrels/mile-year _ 1000 barrels
M" " 1.3 x 10'3 spins/mile-year
aBased on assumptions as to how the line will operate (e.g., frequency of
inspection, accuracy of flow meters, emergency shutdown, etc.), the cal-
culated volume of the pipeline and spill size data for typical lines.
238
-------
6.3.2.4 Relative Measure of Risks (Frequency x Spill Size) Leak, Rupture,
Mean—
The relative measure of risks, product of frequency and spill size,
for the typical section of line is shown in Table 57 and Figure 52. Val-
ues are provided for both spill frequency and the two largest nominal spill
sizes (leak and rupture) and mean size that can be expected from a single
accident. This information on leaks and ruptures is particularly impor-
tant in the evaluation of the potential damage of an accident in a high
risk area.
The relative measure of spill risk per year for "leaks" per year is:
RMR, _ = F. - x VNI , = °:98 SP".15 x 40QgS?ne1S - 0.392 barrels .
LT LT NIL 10-3 mile/year spl11
The relative measure of spill risk per year for "ruptures" is:
RMR - F x v - 0-32 7500 barrels = 2 4 barrels
KMKRT - hRT x VN] p -- 175 x cm 11 £•<*• oarreis
R1 Rr NLR 10 J mile-year sp1 "
Since the estimated total of all types of spills for a typical section of
line is 1.3 x 10~3 spills/mile-year, the relative measure of spill risk
per year for all spills is:
F-- x VM - *'3 SP111S x - 1-3 barrels
ST M 10-3 mile/year sPll]
6.3.2.5 Risks External to Line Pipe—
The risks (potential severity) external to the line from the acciden
tal spills have been grouped into the following ten categories:
• Fluid transported
• Undergound water supplies
• Water
• Industrial
• Population
• Commercial
• Underground facilities
• Surface transportation
• National preserves
• Spill volume.
239
-------
TABLE 57. RELATIVE RISK OF OIL SPILLS FROM
A TYPICAL SECTION OF LINE PIPE
Type of Spill
Leak
Rupture
Mean
Frequency
(Per Year)
0.98X10"3
(FLT)
0.32 X 10"3
1.3 X 10"3
Spill Size
Small to
Medium
Medium to
Major
Medium to
Major
Nominal
Largest Size
(Barrels)
400
<-VNLL)
7500
-------
"RUPTURE TYPE" SPILL FROM
"TYPICAL" SECTION OF LINE PIPE
(REFERENCE LINE)
MEM SPILL FMM "TYPICAL"
SECTION OF LINE PIPE
(REFERENCE LIKE)
"LEAK TYPE" SPIll FROM
"TYPICAL" SECTION OF LIKE PIPE
(REFERENCE LINE)
2.4 BARRELS/YEAR
1.3 BARRELS/YEAH
0.192 BARRELS/YEAR
ro
-pi
NOMINAL
LARGEST
SPILL SUE
FOR "RUPTUK
OF "TYPICAL"
SECTION OF
LINE
SPILL
FREQUENCY
OF "RUPTURES'
FROM "TYPICAL
SECTION OF
LINE
MEW SPILL
SIZE
SPILL
FREQUENCY
1000 BARRELS
1.3 » JO"3 SPILLS/YEAR
NOMINAL
LARGEST
SPILL SIZE
FOR "IE.W
OF "TYPICAL
SECTION OF
LINE
SPILL
FREQUENCY
OF "LEAKS"
FROM "TYPICAL
SECTION OF
LINE
7500 BARRELS
'W
0.12 X 10" 3 SPILLS/YEAR
400 BARRELS
0.99 I 10'3 SPILLS/YEAR
Figure 52. Relative measure of risk of oil spilled from typical section
of line (reference line)--leaks, ruptures, mean.
-------
The relationship of these potential failures is shown in the fault tree
of Figure 53. It should be noted that the risk value for failures in each
category is assigned a value of one because the typical line is assumed to
be located in a low-risk area. Correction factors that account for a com-
plete range of risks (i.e., low, medium, high), are provided in Section
6.3.3.4.
6.3.3 Correction Factors—General Use
The spill potential of most lines may be estimated by applying cor-
rection factors3 to the values developed for the reference line&. These
factors correct for the significant variations (e.g., geometry, age, etc.)
between lines. They are intended to provide a simple and practical means
of accounting for the overall effect of these variations on line pipe
failures.
Correction factors are provided for variations that have significant
effects on the four main items that are used in evaluating the risks of
oil spills. These are:
• Frequency of spills
• Volume of spills
• Size of spills
- Mean
- Leak
- Rupture
• External environment.
The first three items are primarily related to failures of the line itself.
The fourth item deals with damage to the environment, external to the line
pipe, that occurs after or during an accidental spill of petroleum. Cor-
rection factors for each of these four items are provided in the subsec-
tions that follow.
Because reportable information on accidental spills and operating com-
pany lines in the U.S. is limited (see Section 6.2.1), values for some
factors may be qualitative and should be considered as very rough es-
timates. These factors are intended for use in developing spill pre-
vention and control guidelines and should not be used for other analy-
sis purposes.
In this section it is assumed that the lines commonly use similar in-
spection and leak detection methods (see Section 6.3.1). Thus, cor-
rection factors are not included for these methods.
242
-------
SPILL DMWGE EXTERNAL
TO TYPICAL SECTION OF LINE PIPE
(REFERENCE LINE)
FLUID \ / UNDERGROUND
TRAIISPORTED /
-------
6.3.3.1 Frequency of Spills-
Many factors influence the frequency of spills from line pipes trans-
porting petroleum. Analysis and evaluation of available spill data indi-
cate, however, that only a few factors vary in such a manner as to signifi-
cantly affect the incidence of spills between different lines. These in-
clude:
• Age
• Geometry (diameter, wall thickness)
• Use
• Length.
Another important consideration is the minimum spill size. In this analy-
sis, spills of 50 barrels or more generally are considered to be signifi-
cant. In certain high-risk areas, however, even a spill of a few barrels
might be considered significant. Thus a correction factor is included for
spills between 1 and 50 barrels. Values for correction factors are pro-
vided for each of these five items in Figure 54. A fault tree for these
correction factors is shown in Figure 55. Note that the overall correc-
tion factor, CFp, is the product of the individual correction factors.
The five items are treated separately in the subsections that follow.
Other factors that are important include:
• Depth of burial
• Type of line
• Corrosion control
• Construction
• Material
• Soil condition
• Operating pressures
• Maintenance and inspection
• Overpressure.
The effect of this latter group appears to be minor. Effects of many of
these items are partially accounted for by the former group. For example,
the quality of line pipe construction and materials decreases with age.
Information that is necessary for a very accurate estimate of the effect
of these items in this latter group is not generally available (i.e., re-
portable to government agencies or available in the literature). For ex-
ample, the number of accidents versus depth of cover is reported, but the
miles of pipeline for each depth are unknown. The same holds true for type
of weld and grade of .pipe. Despite the lack of optimum information, reason-
able estimates can be made of the effects of these factors. Information
pertaining to the actual spills is reportable (e.g., Appendices A and B),
and reasonable estimates of the relative effect of these factors are possible.
244
-------
•a
CJ
I.
0
4-1
U
Correction f
3.0
2.5
2.0
1.5
1.0
0.5
0
—
i
_
-
J '
II 1 |l
t-
o
C
o
£
o
1.2
1.0
0.8
0.6
0.4
0.2
0
10 20 30 40
Age (Years)
J_ I I I I I I I I 1 1 1
50
8 12 16 20 24 28 32 36 40 44 48
Geometry Diameter (Inches)
ro
-P*
en
_400
u.
o
L.
',o 300
200
100
I
100 200 300 400
Length (Miles)
o
o
1.00
0.75
0.50
0.25
J_
"25 50 75
Use (Percent)
I.
8
u
C
O
J 3
10
8
6
4
3
100
1 2 34 6 8 10 20 30 40 50
Minimum Significant Spill Size
(Barrels)
Figure 54. Correction factors for frequency of spills--
age, geometry, length, use, size.
-------
Correction Factor
Frequency
Q
Spill Size
(CFSS)
Figure 55. Fault tree, CFp, correction factors for
frequency of spills.
246
-------
Additionally, important statistics required for analysis such as mileage of
line pipe by age can be estimated, and mileage of line pipe for each diam-
eter and location (state) is known.
6.3.3.1.1 Age
Corrections for line pipe age are provided in Figure 53. Results in-
dicate that the age of the line pipe has the most significant effect on the
estimated spill frequency.
Data such as presented in Figure 36 and Table 28A show a dramatic in-
crease in the spill frequency with pipe age. Results presented in Fig-
ure 36A and Table 25 clearly show that the age of the line pipe is a major
factor in the frequency of incidents. Lines built before 1950 appear to
have a much greater incidence of corrosion, while lines built before 1930
appear to have a much greater incidence of spills caused by outside forces.
Corrosion is a time-dependent process. Hence, older lines are ex-
pected to have a higher incidence of corrosion. Also, as the average age
of U.S. lines continues to increase, higher incidents of corrosion normally
would be expected. However, spills reportedly caused by corrosion have
decreased significantly in the past few years. Some of this decrease can
be accounted for by operator compliance with U.S. regulations that are in-
tended to reduce line pipe corrosion (i.e., Titles 49, Part 195.414,
195.415, and 195.416). Other decreases can be attributed to operator sys-
tems that exceed the requirements of government regulations.
6.3.3.1.2 Geometry-Diameter and Wall Thickness
Corrections for line pipe geometry (CFg) are provided in Figure 54.
These corrections indicate that the diameter of the line pipe has the
second most significant effect on the frequency of spills.
Data presented in Figure 32 show that the incidence of spills de-
creased rapidly with increasing line pipe diameter. This result occurred
for line pipe diameters of four inches to approximately 16 inches. The
incidence of spills increased slightly for line pipe diameters of 16 in-
ches to 32 inches. These results are in almost direct contrast to the ex-
pected incidence of spills based purely on the cross-sectional area of the
pipe; spill frequency normally would be expected to increase with increas-
ing cross-sectional area of the pipe.
There are a number of possible explanations to account for these con-
trasting results. Recent research82 on line pipe damage has indicated
that thin-wall line pipe is more easily damaged. Our analysis of spill
data indicates that this conclusion is reasonably correct for pipelines
transporting liquids. Thin-walled small-diameter lines, particularly
older ones (built before 1934), have a higher frequency of failures from
outside force incidents. Data indicates that the wall thickness effect
appears to become less a factor for line pipe diameters greater than 16
inches. At about this diameter, defective pipe and corrosion cause in-
creasingly more failures apparently because of the larger cross-sectional
areas.
247
-------
The age of the line pipe for each diameter is not known and the ef-
fects of age are uncertain. However, larger diameter lines (i.e., greater
than 16 inches in diameter) would be of newer vintage. Thus, low rates of
failure from corrosion and construction defects would be expected. Also,
the mileage of line pipe by diameter that is excluded from reporting (pri-
marily gathering lines) is unknown. Despite the limited data available, the
correction presented in Figure 54 is considered to provide an adequate
estimate of the overall effects of the various causes of line pipe failures
as related to diameter.
6.3.3.1.3 Use
Corrections for line pipe use (CFg) are provided in Figure 54. The
frequency of spills is assumed to be directly related to the use of the
line. For example, if the line is in operation 50 percent of the time, the
incidence of spills would be expected to be slightly more than 50 percent of
the value than if the line were operating at all times. Long periods of
shutdown would be expected to increase the frequency of spills, for example,
from internal corrosion.
6.3.3.1.4 Length
Corrections for line pipe length (CF-j) are provided in Figure 53.
The frequency of spills is assumed to be directly related to the length
of the line. For example, if a line is 100 miles long, the incidence of
spills would be expected to be 100 times greater than the one-mile sec-
tion of line.
6.3.3.1.5 Minimum Spill Size
The correction factor for the frequency of spills for spill size (CFSS)
of less than 50 barrels is shown in Figure 54. Various data and other con-
siderations were evaluated for this correction factor.
Spills of less than 50 barrels are difficult to estimate. Most spills
of less than 50 barrels are not reportable. Estimates of spills of less
than 50 barrels that are reported are also subject to criticism. Various
data bases (U.S. and foreign) on accidental spills are available for esti-
mating these incidents. For example, the mathematical analysis in Appendix
E, based on OPSO reported spills, indicates that at least 70 percent of
crude spills are less than 50 barrels. Data in Table 33 indicate that this
percentage is much lower. In contrast, careful reporting and analysis of
spills by one company, for a number of lines and for a large amount of
throughput, indicates that over 85 percent of the spills were less than 50
barrels. Other data bases such as Figure 42, indicate similar varying
results.
The size of small spills in the range of 50 barrels is especially dif-
ficult to estimate accurately for a number of reasons. No specific guide-
lines are in common use for accurately estimating the spill size. One would
normally expect a natural tendency to underestimate the size of a small
spill and thus many spills may go unreported.
248
-------
Talcing all these items into consideration, the correction factor for
minimum spill size is given in Table 54. This factor is based on the as-
sumptions that 75 percent of the spills are less than 50 barrels and the
size distribution is similar to the one presented in Figure 42.
6.3.3.1.6 Other Important Factors
Depth of Cover
The number of outside force incidents has been reported as a function
of the depth of burial of line pipe (Table 31), but the mileage, geometry,
and age of line at each depth are not reported. Thus, the effect of depth
of cover on the incidence of spills cannot be properly evaluated and a cor-
rection factor developed. Depth of cover is considered an important factor
in the incidence of spills, and suitable information is needed for proper
evaluation.
It should be noted that only 21.1 percent of the incidents occured
for a depth of cover from 31 to 40 inches (Table 31). Assuming3 a much
larger proportion of lines are under this depth of cover than the portion
of incidents reported, it could be inferred that a suitable depth of cover
is a significant factor in reducing the spill frequency.
The depth of cover for underwater lines is an extremely important fac-
tor in preventing spills. This is because most accidents from outside
forces are due to external impacts from such sources as anchor dragging.
A depth of cover of three to four feet is normally sufficient to eliminate
most damage from anchor dragging. In the case of onland lines, equipment
rupturing lines is the predominant cause of damage by outside forces and
evacuation equipment a minor one. A depth of cover of three to four feet
is considered sufficient to minimize spills caused by most equipment.
Depth of cover often becomes a problem because of soil erosion. For
example, lines buried underwater at three feet may become uncovered due to
ocean currents or onland lines due to erosion from water. Thus, even if a
line is buried, it is considered important to inspect the depth of cover.
This is particularly important for underwater lines where impact damage
cannot be easily detected. It may also be significant for onland lines,
particularly in high risk areas, because of potential damage from equip-
ment rupturing the line.
The depth of cover as required by existing U.S. regulations is con-
sidered adequate for line pipe. The possibility exists that the cover
above the line may substantially decrease, and in some instances the line
may become exposed because of soil erosion or other events. This is con-
sidered to be a factor in the incidence of spills. However, there is
aln 1971 and 1974, for example, there were 67 and 76 cases of equipment
rupturing the line and only four and eight cases of spills caused by
excavation.
249
-------
insufficient information pertaining to the depth of cover to establish a
suitable risk-correction factor. But this problem will be considered in the
development of a spill prevention program.
Various other factors have some bearing, but do not appear to be major
factors in the frequency of spills. A brief discussion of a few of these
follows.
Type, of Line
Crude gathering and trunk lines cannot be distinguished for most of the
incidents of spills reported to OPSO. Also, a large portion of the gather-
ing lines are exempt from spill reporting. Thus, a truly accurate correc-
tion factor cannot be developed. However, crude and product trunk!ines
appear to have similar incidence of spills. This is indicated in Figure 26
where crude spills averaged about 0.88 spills per mile, while product spills
average 0.92 spills per mile. Product lines are generally newer and of
larger diameter than crude lines; thus, a lower spill rate would be expected
for product lines. This latter observation is found to be correct when most
crude gathering lines are not included in the total mileage used in comput-
ing spills per mile. For this exclusion, crude spills average 1.3 spills
per mile. Crude lines are slightly older and of smaller diameter. However,
age and geometry effects have already been accounted for.
Based on these considerations, there appear to be no significant
differences for the type of line. Thus, no correction factors are provided.
Corrosion Inspection and Control
U.S. regulations exist for installation, maintenance and periodic
inspection of cathodic protection systems and for corrosion control (see
DOT 49 CFR 195.414, DOT 49 CFR 195.416 and DOT 49 CFR 195.418). These
regulations apply to most lines and are primarily for reduction of ex-
ternal corrosion. Since these regulations are quite comprehensive and
are applied equally to most lines, there appears to be no need for cor-
rection factors.
6.3.3.2 Volume of Spills—
A variety of factors influence the volume of spills from line pipe
transporting petroleum. However, only a few of the variations between
lines are considered to have the potential of significantly affecting the
spill volume. These include:
• Diameter
• Length
• Use
• Pumping station shutdown time
• Mainline valve closure time
• Line elevation.
250
-------
A fault tree for these correction factors is shown in Figure 56. The
overall correction factor CF$v is the product of the individual correction
factors. Values for correction factors are presented in Figure 57 for diam-
eter, length, use and pumping station shutdown. Correction factors are not
provided for mainline valve closure time and line elevation but these can be
computed using information provided in Table 48 and Reference 58 (see also
Section 6.3.1). These are considered to be less significant than the first
four factors. Estimates for these latter two factors are difficult to make
for two reasons. First, a number of variables must be considered. Second-
ly, necessary information for many of these variables is either not avail-
able or unknown.
6.3.3.2.1 Diameter
Corrections for the diameter of the line pipe (CF^) are provided in
Figure 37. Results indicate that the diameter of the Tine has a major ef-
fect on the estimated volume of a spill.
Data, such as presented in Table 26 and Figures 31 and 33, show a
dramatic increase in the average spill size with pipe diameter. The spill
size is essentially proportional to the cross-sectional area of the pipe.
These data follow approximately the same profile as the spill size data
for Western Europe and Canada (Figure 41). However, the mean spill size
in the U.S. for each diameter appears to be much larger than for Western
Europe, i.e., 1000 barrels to 666 barrels.
6.3.3.2.2 Length
Corrections for line pipe length (CF-j) are provided in Figure 57.
The volume of spills is assumed to be directly related to the length of
the line. For example, if a line is 100 miles long, the volume of spills
would be expected to be 100 times greater than the one-mile section of line.
6.3.3.2.3 Use
Corrections for line pipe use (CFU) are provided in Figure 57. The
volume of spills is assumed to be directly related to the use of the line.
6.3.3.2.4 Pumping Station Shutdown
Corrections for pumping station shutdown time (CFps) are presented in
Figure 57. This correction is an important consideration in the volume of
accidental spills. In the event a rupture or large-size break occurs, the
ability to rapidly shut3 the system down at the pumping stations is
Shutdowns not occurring at the proper time should be avoided. Incorrect
shutdown can create surge pressure that might cause leaks at other line
pipe locations.
251
-------
ro
tn
ro
CF,
Di ameter
\
/Mainline**
/ Valve
Closure
V (CFn,c> '
Line
Elevation^
(CF,
Figure 56. Fault tree, CFSy, correction factor for the volume of spills.
-------
8.0_
cn
co
2.0
£-
u
i; 1-5
1.0
0.5
12 16 20 24 28 32 36
Line Pipe Diameter (Inches)
40 44 48
6"~ 8
500
400 500
Length (Miles)
Shutdown time (Minutes)
Use (percent)
Figure 57. Correction factors for volume of spills—diameter, length, use, shutdown time.
-------
critical in minimizing the volume spilled. For example, if a line rupture
discharge rate3 were 5,000 barrels per hour, a two-minute pump shutdown time
would allow 166 barrels to be spilled, a six-minute shutdown time would
allow 500 barrels to be spilled.
A survey of pumping station facilities indicates that over 50 percent
of the facilities can shut their systems down within one minute, 70 percent
in two minutes, 96 percent in five minutes. Thus, a range of zero to five
minutes was used in the correction factor. Also, it was assumed for the ref-
erence line that rupture-type spills would be detected within ten minutes
and the line required two minutes for pump shutdown. Thus, if it required
five minutes to shut the pumps down in another line, the spill volume for
this line would be expected to be at least 25 percent greater than for the
reference line.
6.3.3.2.5 Mainline Valve Closure
Rapid closure of a mainline valve can significantly reduce the volume
of petroleum that escapes from an accidental spill. A recent study58 in-
dicates that additional spillage can occur unless the mainline valves are
closed rapidly after pump station shutdown. This study indicates, for
example, that a 14-inch line with a break (4-inch diameter hole) at the
bottom could decrease the 300 barrels per hour of spillage after pump sta-
tion shutdown. However, diffusion into the surrounding soil and eventual
buildup around the pipe until the static head is equalized is expected to
significantly reduce the spill rate.
Results of an industry survey58 indicated that it requires an average
of 72 minutes to reach and close a mainline valve and an average of 2.6
minutes for a remotely controlled valve. Ninety-five percent of the valves
surveyed required manual closure. Manual closure and a 72-minute closure
time was assumed for the reference line.
In addition to the effect of fluid buildup, a number of other factors
affect the spill rate. These include:
• Hole size
• Location of hole
• Line pressure
• Line elevation
• Soil
• Other.
Again, the effect of many of these factors on the spill rate is unknown.
Thus, an accurate estimate of this factor is difficult for individual lines.
It is extremely complicated to develop a general factor that could apply to
Line pipe rupture can result in spills in excess of throughput. Depend-
ing upon the line, spill rates can exceed flow rates by large factors
(i.e., two or three).
254
-------
most lines. Considering that the effect of mainline valve closure is of
much less significance than CFj or CFps and considering also the difficulty
in obtaining an accurate correction factor for CFmVc» a value of one is
normally assumed for this correction factor.
6.3.3.2.6 Line Elevation
Even after pumping station shutdown and mainline valve closure, spill-
age can occur because of the existing static head in an elevated line.
This problem is particularly significant in isolated and/or high risk areas.
The extent of the effect of line elevation depends upon a number of line
parameters (e.g., diameter, pressure, flow rate, etc.) and is not simply
determined. Values for the line elevation correction factor (CFie) are not
provided here (assume unity) but should be estimated for a particular line
where a potential problem exists. The relationship of line elevation to
other correction factors, however, is shown in the fault tree (Figure 56).
6.3.3.2.7 Other Factors
Flow Velocity
Flow velocities depend upon the size of the line and typically range
from 6 fps for six-inch lines to 12 fps for 36-inch lines. No correction
factor is provided since the factor is accounted for in the line diameter
correction.
Location of Mainline Valves
Check valves in uphill sections and remotely controlled valves in down-
hill sections are desirable. Since 1974, the ANSIS 31.4 Code requires re-
motely-controlled valves at a maximum spacing of 7.5 miles in commercial,
residential and industrial areas and 10-mile spacing of manual valves for
other liquids.
Valves generally cannot be installed in long length offshore lines.
This presents a serious problem in underwater lines located in elevated
areas.
6.3.3.3 Size of Spills-
Most of the factors that have a significant influence on the volume of
spills also influence the size of spills. These include:
• Diameter
• Pumping station shutdown time
• Mainline valve closure time
• Line elevation.
255
-------
These four factors have an effect on the size of spills resulting from rup-
tures or mean (average size) spill size. Fault trees for ruptures CFyR and
mean size spills CV\/M are presented in Figure 58. Values for these correc-
tion factors are the same as those presented for the volume of spills in
Table 57. Also, the discussion of each factor presented in Sections
6.3.3.2.1 through 6.3.3.2.4 applies to the size of spills and will not be
repeated here.
All four factors are considered to have a very minor effect on the
spill size for leaks. Thus, no correction factors of fault tree are pro-
vided for "leak type" spills.
6.3.3.4 External Environment-
There are many risks to the environment from escaping petroleum. These
risks are identified for each of ten categories in Table 58. Correction
factors that account for a complete range of risks (low, medium, high) are
also presented in this table. Many of the values9 for the correction fac-
tors are considered to be only qualitative estimates (see Section 6.2.1)
because of the absence in required spill reporting forms of suitable quan-
titative data relating to the external environment.
A fault tree for correction factors for risks to the external environ-
ment from escaping petroleum is presented in Figure 59. Note that the over-
all correction factor, CFgQ, is the product of the individual correction fac-
tors.
Rather than discuss each correction factor value in each category, ex-
amples of typical categories will be provided. Spills occurring in lakes
and rivers generally can be confined to small areas using suitable contain-
ment techniques; risk factors of 10 and 20 are assigned, respectively. Off-
shore spills, however, are quite difficult to contain and often (about 95
percent of the time) reach recreational areas along the shoreline; risk fac-
tor of 100 is assigned for spills located offshore. A recent study1*6 indi-
cates that a serious potential exists for damage to underground water sup-
plies in the United States. The study indicates that large supplies near
large urban populations are particularly vulnerable. Based on information
contained in the study, lines near medium to large volumes of underground
water supplies are assigned risk factors of 10 and 100, respectively.
6.3.4 Computation of Oil Spill Risk for Accidental Spillage
6.3.4.1 Risks that Oil will Escape from the Line Pipe--
Oil spill risks for line pipe for most petroleum pipeline systems can
be computed using information supplied in this section. Values are obtained
by applying the appropriate correction factors to the values determined for
the reference line.
aThese values are primarily intended to identify sources of high risk and
for use in developing guidelines in this study. They should not be used
in other analyses.
256
-------
A
V
&
CF,
Correction Factor
Spill Size—Rupture, Mean
Diameter \ /'
(CFd)
Pumping
Station
/ \ Shutdown
/ \CCFpjOx'
Mainline
Valve .
Closure
Figure 58. Fault tree, CFyR or CFy^, correction factors
for spill size—rupture and mean.
257
-------
TABLE 58. CORRECTION FACTORS FOR RISK OF SPILL DAMAGE
EXTERNAL TO LINE PIPE
Location or Coirmodlty
1. Fluid Transported
Crude
Products
LPG
LUG
Other
2. Underground Water Supplies
Zero potential
Snail volume
Hedlun voluise
Large volume
.>. uter
Zero potential
Streen
Lake -
River
Marshlands
Offshore
teaches
Terminals
High seas
4. Industrial
Zero
Light
1 Bedim
i Heavy
S. Population
Undeveloped
Rural
, Residential
Urban
6. Coemrclal
Zero
Light
Medlup
Heavy
7. Underground or Adjacent
Facilities
Zero
Electrical
fias
LPS
LN6
3. Surface Transportation
None
Road
Highway
Railway
Freeway
Sajor freeway
9. National Preserve
Zero
Snail
Medium
Major
10. Spill Volume
Fatalities
1-100 (barrels)
100-500 (barrels)
500-1,000 (barrels)
1,000-10,000 (barrels)
>10,000 (barrels)
Injuries
O-ICO (barrels)
100-500 (barrels)
500-1,000 (barrels)
1,000-10.000 (barrels)
>10,000 (barrels)
Correction Factor
Identification Low Risk Medium Risk Major Risk
I-' 5-9 ' 10-100
CFuw
M
CFi
"P
"c
CFuf
CFnp
CF,v
3 . '
10
2' ,
i«> i
i • i
10 !
wo :
id)
10 i
20 I
100 ;
100 i
100 '
100
2
I
1<»
l'1'
2
1
1»>
jdl
Z
5 :
10 :
100
s ;
10 j
i SO
s ;
10
100 1
i
5
10
20
50
S
10
50
5
10
s
10
Note: (1) Deference Line Pipe
258
-------
CORRECTION FACTOR
RISK OF SPILL DAMAGE
EXTERNAL TO LIME PIPE
in
vo
Figure 59. Fault tree, CFfp. correction factors for risks of spill
damage external to line pipe.
-------
Oil spill risks for frequency F$TC and volume V$TC of spills can be
computed using Table 59 and the figures indicated. Fault trees for F$TC
and VSTC are shown in Figure 60.
Oil spill risks of the nominal largest spill size of ruptures VNLRC
leaks V|\||_|_c and mean volume VMC, can be computed using Table 60 and the in
d fi
__
dicated figures. Fault trees for VNLRC> VNLLC ^ VMC are sn°wn i" Fig-
ure 61.
The relative measure of oil spill risks for rupture RMRR, leaks RMR\_
and means spills RMRw can be computed using Table 61. Fault trees RMRR,
RMR|_ and RMR|v| are provided in Figures 62 and 63.
6.3.4.2 Risks External to Line Pipe—
The relative severity of spills or the risks external to the line from
accidental spills can be computed using information suppl-ied in this sec-
tion.
First, the correction factor CF^o for risks external to the line are
computed using Table 62. Then the values for risks external to the line
can be computed using Table 63; this is accomplished by taking the product
of the risk correction factor CFgo and the previously computed risks (see
Section 6.3.4) that petroleum will escape from the line. Spillage risks
external to line pipe can be computed in Table 63 for the following:
• Spills
- Frequence F<-E
- Volume VSE
• Spill size
- Rupture (nominal largest)
- Leak (nominal largest)
- Mean VSME
• Relative measure of risk
- Rupture
- Leak
- Mean
If, for example, the nominal largest rupture size VNL.RC were 5000 bar-
rels for a particular line located in an urban area, the risk correction
factor is:
CFED = CFFT x CFUW x CFW x CFj x CFp x CFC x CFyF x CFSJ x CFNp x CFSC
= Ix IxlxlxlOOxlx 1x1 xl x 10 = 1000.
260
-------
TABLE 59. CALCULATION OF THE FREQUENCY FSTr AND VOLUME VcTr
OF SPILLS FOR LINE PIPE
IN* *r HM
Crudt Cithtrln* lint
Onlll*
Vndtnaltr
fruit InitkltM
OnltM
IMtmltr
rnxtucl frunUflit
Onltn*
IMtnattr
IOIM
SPIU FREOUENCr
Mftr-
MCt
«>
'si
Spllll/
Ittr
rrMjutncy Corrtctlon rtcUrl' '
Intflilduil (irlitlant
A*
«.
Ctawtrr
",
Itnttn
"l
u»
".
Spill
Sift
",,
CiMuUtlvt
cf. • cr.
> cr. * cf.
> «,, •
"r
u«t ri»t
'si""r-
'sic
DtftrtiiM
lint MM
(Spill
felim)
*SI
Itrnti/
Tt>r
SPIU VOLUnE
«>|IM CtrrtcIlM ricltn'"
l»4l>l«itl Vtrlitloni
OliiHltr
"<
Unflll
Ml
Hit
tr.
»«Vln(
SUIlM
SKul-
wxn
HP.
Nilnllnt
rti>«
ClMurt
"«
lint
lltM-
tlm
"l.
CimiltlKt
"< " "•
.cr.
'"P.
•««
»"i.
•««»
line Up.
»5l"
"$y-
•»TC
••rrcli/
Year
ro
bt<: III SM liklt •-!.
It) SM I(|nn 4-f.
Ill SM Mt«* 4-1.
-------
Spill Volume
Line Pipe
STCX
Spfl) Frequency
Line Pipe
ro
en
ro
Correction Factor
for Volume
of Spills
Spill
Volume
Spill Frequency '
of All Spills
from Reference Line
Correction Factor
Frequency
'ST
1.3 Barrels/Year
1.3 X 10"J Spills/Year
Figure 60. Fault trees, V$jc and F
volume of spills from
, frequency and mean
ne pipe.
-------
TABLE 60. CALCULATIONS OF THE NOMINAL LARGEST SIZE OF RUPTURES, VM1Dr!
LEAKSNLLC AND MEAN VMC FOR LINE PIPE SPILLS NLKL
Type of Line
Crude Gathering
Line
On land
Underwater
Crude Trunk! ine
Onland
Underwater
Product Trunk! Ine
Onland
Underwater
TOTAL
Reference
Line Pipel
(Nominal
Largest
Ruptured
Spill
Size)
VHLR
(Barrels)
NOW
1)
Diameter
CRd
WL LARGEST RUPTURE SPILL VNLRC
Volume Correction Factors'2*
Individual Variations Cumulative
Pumping
Station
Shutdown
"Ps
Mainline
Valve
Closure
"me
Line
E1eva- -
tion
CF,e
"d x CF
« ffmc *
CFle .
CFVR
Line
Pipe
VNLR *
CFVR -
V«IRC
(Barrels)
NOMINAL MEAN SPILL SIZE V^.
Reference
Line PtpeG
(Mean
Spill
Size)<3>
VM
(Barrels)
Cumula-
tive
Volume
Correc-
tion
Factor
CFVR
Line
Pipe
VH*
CFVH.
»nc
(Barrels)
NOMINAL
Reference.
Line Pipe1
(Nominal
Largest
Leak
Spill
Size)
VNLI
(Barrels)
LARGEST LEAK SPILL SUE VNU(.
1)
Individual
Variations
Line
Eleva-
tion
CFle
-
Cumula-
tive
CFle *
CFVL
Line
Pipe
VNLL *
CF¥L*
VNLLC
(Barrels)
ro
o>
OJ
Note: (I) S«« Table 4-1.
(2) See figure 4-9.
-------
ro
cr»
.
A.
i V
/ViCV
Urottl Spill Sl/f
«'
U»k»
Ml)
Correction Factor
Urottt Spill Sill
of loll
(Nu.lr.il)
,'Cf.,
.. -
X
spill Slit or P.f.
• lino l«k>
Correct lo
Spill V
of Rupl
1 14I9.1I Spill SIM
1 0»
C 1 nuptorot
& 1 (NlWlMl)
t
n factor 1 s' ... ^.
-I,.- 1 /nominal larootl^
„„ I V Spill Slia of lof
1 "VIIM duplyr.j.
1 "
^HC\~ 1 """ *
1
Cor reel to* factor
of Spllli
(««.)
IDUO Birr.ll
Figure 61. Fault trees, V^LLC* VNLRC» VMC> nominal largest size
of ruptures, leaks and mean for line pipe spills.
-------
TABLE 61. CALCULATIONS OF THE RELATIVE MEASURE OF OIL SPILL RISKS FOR RUPTURE RMRp,
LEAKS RMRL AND MEAN SIZE RMRM SPILLS FOR LINE PIPE K
Type of Line
Crude Gathering Line
On land
Underwater
i
Crude Trunk! ine
On land
Underwater
Product Trunk! ine
On land
Underwater
Total
Relative Measure of
Rupture Spill Risk RMRR
v (1)
NLRC
0.25 F$T(2>
CFf<3>
VHLRC
x O.Z5 FST
x CFf «
RMRR
Relative Measure of
Leak Spill Risk RHRL
v (1)
"HLLC
0.»Fs«>
(3)
CFF
VHLLC
x 0.75 FST
x CFF =
RMRL
Relative Measure of
Mean Spill Risk RMRM
„ (1)
>C
(2)
FST
(3)
CFf
VMC
x FST
xCFp =
RMRH
ro
o>
en
Note: (1) See Table 4-5.
(2) See Table 4-1.
(3) See Table 4-4.
-------
_ lypt" Splllt fro* LlM
(Itlttlvi Ntiwn of HUM
until spin SIM
lupturts
(Nwliul )
Spill Frtwwicy
o«
•uptyrtl
ro
en
luk Typt- Jpllli fro. Mm Clp.
(«tlttl» Nl»ur« of Kl
Figure 62. Fault trees, RMRp, RMRi , relative measure of risks (barrels/year) of
ruptures ana leaks from line pipe.
-------
Spilli from HIM
(RaUtlv* HMwn of Msk)
MOM Spill VoluM
Spill Fnqotney
0
Correction Factor
For HMH
of Spllli
Spill
Slzt
Spill Frtquwcy
of All Spllli
fro* Rofvrtneo Lino
Correction Fictor
Froquoney
1000 torroli 1.3 X 10"1
Figure 63. Fault tree, RMfyj, relative measure of risk
(barrels/year) of mean spills from line pipe.
267
-------
TABLE 62. CALCULATIONS OF THE CORRECTION FACTOR
CF£D FOR RISKS EXTERNAL TO LINE PIPE
Type of Line
Crude Gathering Line
On) and
Underwater
Crude Trunk) ine
On land
Underwater
Product Trunk) ine
On) and
Underwater
Individual Variations
Fluid
Transported
CFfT
Underground
Hater
Supplies
CFUH
Water
CFH
Industrial
CFl
Population
CFp
Conraercial
cfc
Underground
Facilities
CfUF
Surface
Transportation
Natural
Preserves
Spill
Volume
Cumulative
x CF., x CF.
x CFp x CFC
x CFuf: x CFjj.
x CF x CF
NP SV
'CFED
ro
cr>
c»
Note: See fable 4-1.
-------
TABLE 63. CALCULATIONS OF RISKS EXTERNAL TO LINE PIPE
Type or Line
Crude Gathering Line
Onland
Underwater
Crude Trunk! ine
Onland
Underwater
Product Trunk! ine
Onland
Underwater
Tola)
Spills
Frequency
FEO x FSTC
*FSE
Volume
CF£D x VSTC
* VSE
Spill' Size
Rupture
Norn. Largest
CFEO x VNLRC
'VSRE
Leak
Norn. Largest
CFED x VNLLC
IVSLE
Mean
CFEO x VMC
= VSME
Relative Measure of Spill Risk
Rupture
CFED x RMRR
" RHRSRE
Leak
CFED x RMRL
• RM«SLE
Mean
CFED X RHRH
* RMR,...-
irtt.
r\>
cr>
vo
-------
Hence, the relative severity or risk external to the line VSRE is:
VSRE = 500° barrels x 100° = 500,000 barrels
Thus, the indicated spill is considered to be equivalent to a 500,000 bar-
rel spill from the reference line.
270
-------
SECTION 7
ANALYSIS OF THE REDUCTION OF THE RISK OF OIL SPILLS FROM LINE PIPE
BY UTILIZATION OF LEAK DETECTION AND INSPECTION METHODS
The potential of selected leak detection and inspection methods to re-
duce the risk3 of oil spills (frequency and volume of spills and risks ex-
ternal to the line) from petroleum pipeline systems is estimated in this
section. Means are also provided to enable an operator to estimate the
risk reduction capabilities (effectiveness) of inspection and leak detection
methods for his own line. Since costs are a major consideration in a prac-
tical maintenance program for line pipe, costs of the various options (in-
spection and leak detection methods) and spillage are estimated and a cost-
effectiveness analysis carried out.
Means for reducing the risk of line pipe spills are examined in detail
in Section 7.1. First, the most promising inspection and leak detection
methods were selected based on a selection criteria. Then estimates made
of the capabilities of leak detection and inspection equipment to detect a
leak of a certain magnitude and/or impending failures. The methods are
evaluated based on their capability to reduce the frequency and volume of
"leak type" and "rupture type" spills for the reference line. Factors are
established which provide a simple means of comparing the capability of
methods to reduce the frequency and volume of spills. These factors help a
potential user select the most suitable method to satisfy the spill preven-
tion programs needs of a particular line.
The amount of oil spillage that can be prevented is examined in Section
7.2. Accidental oil spillage that exists for line pipe is first estimated.
Then estimates are made of spillage that can be prevented by implementation
of various scheduled inspection and leak detection systems. This is done
for all U.S. lines and the reference line. Means are provided so that
quantitative values of spillage and prevention of spillage can be determined
for most lines.
Section 7.3 contains a cost analysis of inspection and spillage.
A cost-effectiveness analysis of the selected inspection and leak de-
tection methods for various inspection schedules was provided in Section
7.4. Two measures of cost-effectiveness were used in the analysis.
Means are provided in Section 6 to enable an operator to estimate the
risk of oil spills for his own line.
271
-------
7.1 COMPARISON AND EVALUATION OF LEAK DETECTION AND INSPECTION METHODS
This section provides an in-depth comparison and evaluation of leak de-
tection and inspection methods that appear to be the most promising. An oil
spill risk reduction analysis is carried out for these selected methods.
This information is then used to estimate detectable and undetectable spill-
age for the reference line pipe and for all U.S. lines in Section 7.2.
The most promising methods are reviewed in the first subsection. Gen-
eral guidelines and criteria for method selection are presented. Methods
selected for further evaluation are identified and categorized by optimum
use, i.e., reducing one or both parts of the oil spill risk.
An analysis of the risk reduction capabilities of the selected methods
is carried out in the second subsection. Methods are analyzed as to their
capability of reducing the volume and frequency of "leak type" and "rupture
type" spills for both onland and underwater use. Risk reduction factors are
estimated for all methods and combinations of methods. In order to simplify
comparisons, normalized risk reduction values, based on a single reference
inspection, are provided. Using these values, for example, the effective-
ness of one inspection can be equated to a certain number of other inspec-
tions, i.e., one inspection pig survey to a number of visual inspections of
the line.
7.1.1 Selection of the Most Promising Leak Detection and Inspection
Methods
7.1.1.1 Guidelines--
No single inspection or leak detection method currently exists that is
capable of detecting all leaks in sufficient time to avoid an oil spill in-
cident. This situation exists for a number of reasons such as:
• Variety of line pipe systems
• Accidental spillage may occur at any location along the
line
• Wide variations in the frequency and volume of spills
• Numerous causes of spills.
Despite these difficulties, this report shows that the potential exists
for significant reductions in the volume and frequency of petroleum spillage
both for individual lines and those nationwide. In this study, the major
emphasis is for reductions of spillage nationwide. However, means are
provided in Section 6 for identifying and quantifying the risks of both
individual lines such as those located in potentially high risk areas and
lines nationwide and in Section 7 for estimating the reduction of risks
using the most promising methods. On a nationwide basis, maximum oil spill
risk reduction is accomplished by implementation of spill prevention pro-
grams incorporating methods that adhere to the following guidelines:
272
-------
• Adaptable to most lines
• Highly effective in reducing frequency of spills, particularly
those that are expected to result in ruptures
• Highly effective in limiting the spill size
• Cost-effective.
In high-risk areas, however, emphasis is placed on reducing the frequency
and volume of all spills to as low a level as practical for the specific
type of line. Hence, methods considered highly effective but, for example,
not adaptable to most lines are considered for use in individual spill pre-
vention programs for optimum spill reduction.
7.1.1.2 Selection Criteria--
Selecting the most promising inspection and leak detection methods was
based on the following criteria:
• Must be adaptable to most onland lines
• Must be adaptable to most underwater lines
• Must have a potential for a significant reduction in the
frequency or volume of spills
• Practical implementation and operation costs
• Limited interference with pipeline operations
• Rapid response for "rupture type" spills
• Inspections can be performed either by semi-skilied line
pipe personnel or inspection services
• High reliability or jiigh probability that the equipment
will operate satisfactorily during the inspection
• High design adequacy or probability that the inspection
equipment will accomplish its performance requirements.
7.1.1.3 Methods Selected for Further Evaluation—
Applicable methods were briefly described and compared in Section 5.3.
Of these, only a few leak detection and inspection methods were judged to
satisfy the general guidelines and selection criteria for line pipe. The
methods selected for further evaluation are identified in Table 64. Gen-
erally, the methods selected are highly effective in reducing one of the
two parts of the oil spill risks, i.e., reducing either the volume of
spills (Section 5.2.4.2) or the frequency of spills (Section 5.2.4.1). In
a few cases, a selected method may be effective for both parts. Therefore,
methods are identified as to their optimum use, i.e., reducing one or both
parts of the oil spill risk.
Although not selected, some leak detection and inspection methods may
be effective in solving atypical spill problems that are characteristic of
a particular line or small group of lines. For these special applications,
273
-------
TABLE 64. INSPECTION AND LEAK DETECTION METHODS SELECTED
FOR FURTHER EVALUATION OF LINE PIPE
Leak Detection and Inspection Method
1. Visual inspection by sir or ground patrol
in excess of required inspections
2. Visual inspection i, ;round patrol with
hydrocarbon detector :r other
comparable device
3. Hydrocarbon prone-towftsn or similar device
- Underwater lines 'inly
- All lines
4. Oil spill detectors
• Marine terminal or alatform
- Total line pioe rileege
5. Pressure deviations
a. Pump stations (existing method)
b. Along line
«. Flo, rate
a. Deviations
b. Comparisons (computerized)
7. volume comparisons (computerized)
a. Mathematical medelln; (computerized)
9. negative pressure surge (computerized)
10. Passive acoustic array (computerized)
11. External rods ulth passive acoustic
sensors
12. Pressure static
13. Hydrostatic
14. Pressure difference
IS. Change or add inhibitors as needed
ISr-lnsaeetlon of sample of line for veil
thickness by ultrasonic or comparable
technique
17. Survey by inspection pig-magnetic flux
type or other comoaraole device
18. Depth of cover inspection by sonar
(sldescan and penetrating) or other
comparable device j
- underwater lines only
- All lines
19. Charting of line pipe 1
- underwater Un« only
. All lines
20. Preventive program for outside
forces (Deference I2j-«ne call system
21. Pig line for water removal
22. Otner
- Catnodic protection system
Installation and maintenance
- visual inspection (biweekly) by air or
ground patrol (required inspection)
Reduction of
Size of Spill
Leaks j Ruptures
i
Reduction of Frequency of
Leaks
1
« j X «
X X
[NO
X X
X
X
X
! X
Spill (1)
! | Causes
Ruptures
X
Line Pipe Faults
Defects
X
X ' X
X i X
X '' X
;
X ;
X ; X
j
, X
I X
I
" i x
X
X
X
X
1
I
X
X
X
X
«
X
X
I NO
I NO
I
[NO
I
X
X
x
X
X
x x
X
X
X
X
X
X
X
X
X
X X
1(10 I*a
X X
X
I
X
I
External Internal
Corrosion Corrosion
X X
X X
X X
x ; x
Outside Forces
Equipment
Rupturing
Line
X
X
Damage byj
Excavation!
Equipment Other
X x
i
, ! x
;
X i X i X
X | X
X X
X
X i
!
X
X i
X X
1
X ! X
X
X
x x
| x \
X
x
X
X
X
X
X
mo
net discernible
274
-------
the operator should consider the potential of other methods described in
Section 5.3.
The most commonly used spill prevention methods for operating lines
currently required by U.S. government regulations are included in Table 64
for comparison purposes only. These methods, mainly bimonthly visual line
inspections and monitoring of cathodic protection systems, have already af-
fected some limited spill prevention. Cathodic protection systems, for
example, are considered to be responsible for some of the reduction of "leak
type" spills caused by external corrosion of line pipe.
7.1.2 Analysis of the Capabilities of the Selected Methods to Reduce
the Oil Spill Risk (Volume and Frequency of Spills)
For the purpose of this study, a spill reduction analysis can be best
accomplished by evaluating and comparing the methods that are applicable to
each part of the risk3. Therefore, the capability of selected methods to
reduce the volume and the frequency of spills are discussed and analyzed in
separate subsections.
Methods for onland lines are generally assumed in the analysis. These
methods normally apply to both onland and underwater lines.
Methods that might be particularly effective for only underwater lines
or lines close to water supplies are also included in the analysis. This
is done even though these methods would not contribute to a significant*3
reduction in the volume or frequency of spills nationwide. The reason
these methods are included is that high reduction of the frequency and/or
volume of spills from underwater lines can result in a significant reduc-
tion in the nationwide total of serious spills. This is because of the
high risk to the external environment from even low volume oil spills in
underwater lines.
A general discussion of factors that affect the capability to reduce
the volume and frequency of spills is presented in the subsections that
follow. Then a spill reduction analysis is carried out for methods that
reduce the volume and frequency of spills. Selected leak detection and
inspection methods are identified in tables along with inspection frequency,
Risks to the external environment are not directly accounted" for in the
reduction analysis based on only the frequency and volume of spills.
Underwater lines account for less than ten percent of the total line pipe
mileage. Hence, even if methods have the capability of significantly re-
ducing spillage from underwater lines, it would have a small effect of the
total nationwide.
275
-------
Other factors that should be considered include:
• System effectiveness
Reliability
Operational readiness
Design adequacy
• False alarms
• Other.
The effect of each of these factors varies widely depending upon the imple-
mentation of each method. It also depends on whether the method is used
for detection of rupture and/or leaks. The combined effects of these char-
acteristics along with these other considerations determine the overall
capability of a method to reduce the volume of a spill. Hence, each is
considered in the evaluation of selected methods.
Implementation of leak detection and inspection methods that are capa-
ble of adequately satisfying the required characteristics potentially will
not only prevent major pollution incidents but will significantly reduce
the annual loss of oil. Hence, implementation of methods that are effec-
tive in reducing the size of an accidental spill is an important considera-
tion in a spill prevention and control program. It should be noted, how-
ever, that methods effective in reducing spill volume generally are not
highly effective in preventing spills or reducing the frequency of spills.
Various leak detection and inspection methods to varying degrees can be
implemented to detect a spill before the volume becomes large enough to
cause a major pollution incident. Table 65 compares the characteristics of
selected methods for use on the reference line, assuming stable flowa.
Values are included for the four major system characteristics (sensitivity,
response, inspection frequency and leak location). For analysis purposes,
single values are presented in the table. However, wide variations in
sensitivity are possible in implementing certain methods. These variations
result from the variety of systems, equipment variations, operational pro-
cedures and other factors. Values given in the table and figures are not
optimum. However, these are considered typical of modern installations and
achievable for most lines. Many of the values presented in the table are
only rough estimates because the information available is insufficient for
more accurate estimates. This is often the case for new or experimental
methods. Additional details of specific systems are available from the
manufacturers indicated in Appendix E and from References 14, 58 and 60.
aDuring the periods when significant line transients exist, many methods
are much less effective than indicated.
276
-------
TABLE 65. COMPARISON OF THE SELECTED METHODS FOR DETECTION
AND LOCATION OF REFERENCE LINE LEAKS AND RUPTURES
Inunction or
Leak Detection Method
COXTINUOUS MMITOUW
Pressure deviations pue» station
along line pipe
Flow ratt deviation comparison
(cowuteriud)
VoluM comparisons (computerized)
NetMutical saddling (conputeHzei
Negative pressure surge
(cdeputertzed)
Passive acoustic array
- fta» 11M
- Retrofit
Oil spill detectors at narine
tenelnel or platfom
KXIOOIC
Pressure >ut1c
Hydrostatic
Pressure difference
External rods Kith passive
acoustic sensors
Leaks
Sensitivity
Thrauonout
us
is
1
0.3
0.6
1 0.1
0.2
HA
<.2
K
-
0.1
0.03
0.002
i 0.2
Visual Inspections by air or ' ..
around patrol for indication
of a spill
Visual inspection By ground patrol
irith nydracarbon probe or coeoara-
bla device for Indications of spill
< 0.002
larrels/
Hour
tt
HS
25
7.5
15
2.5
S.O
HA
2.0
US
-
3
0.7
0.06
5.0
-
<0.06
Response
Ti«e (1)
Lono-
Tera
ie
NS
1 hr.
2< tours
1 tour
24 tours
1 tour
DA
20 «1n.
US
15 «1n.
24 tours
72 tons
<2 nin. (}
288 tours
288 tours
loss
Sensitivity
TIM < 2
(barrels)
NS
NS
50
180
X
36
10
NA
<1
NS
SHll Spill
.75
16.8
4.3
-
•tinor spll
snail spil
Ruptures
Sensitivity
Percent
Throughout
20
2
>5
<4
<3
O.S
5
O.S
4
-
0.1
IK
NS
0.2
NS
< 0.002
Barrels/
Hour
500
50
125
100
75
25
125
25
100
-
3
NS
NS
5.0
NS
<0.06
Aesoonse
T1e» (il
rem
1 Hr.
10 hrs
Thr.
< 2 nin.
10 »1fl.
<2 «1n.
<2 «1n
1000
1000
250
6.6
25
< 1
31
<1
<*
SHll SPill
< 1
NS
NS
--
-
Inspections
Frequency
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
After
indication
of laroe
lut
2
2
After
indication
of large
!••*
26
26
Location
Accuracy
I
Norn
None
None
None
t 2 riles
21 of
sensor
spacing
None
None
(etxeen
block
v«lve«
s: of
sensor
spacing
-
Feir feet
NOTES: (1) NS - Not suitable for indicated detection of leaks or ruptures.
(2) IHA- Information Is unavailable.
(3) Asswes systei operational after leak or rupture indication.
277
-------
The most important capability in reducing the volume of spills, for
both leaks and ruptures, is the sensitivity or accuracy of the particular
methods. A high leak sensitivity, i.e., a few barrels per hour, provides
the capability of detecting sptllage before a large volume of petroleum
can escape from the line.
High sensitivity, however, does not necessarily guarantee that a spill
can be detected and the spill volume reduced. Both the frequency of the
inspection and response time must also be considered. Frequent or contin-
uous inspection methods with good sensitivity are mandated for detecting
rupture type spills. In contrast, high sensitivity methods that require
longer response time and less frequent inspections are often suitable for
detecting small leaks. Rapid response time3 (few minutes) is necessary for
ruptures, whereas long-term response (1 to 24 hours) is usually suitable
for leaks. For example, a typical volume comparison system may be capable
of detecting a leak of 0.3 percent of throughput, but the leak must exist
for 24 hours before an alarm would be activated. In the case of the refer-
ence line, such a system would permit 180 barrels of spillage over a 24-
hour period before detection.
The capability of providing accurate leak location, i.e., within a few
feet, is also important. This capability is particularly advantageous in
certain high-risk areas. For example, spills from elevated lines in rough
terrain may continue (because of static head) even though the line is shut
down and the mainline valve closed. Location of a spill by conventional air
patrol might be quite time consuming and extremely difficult to carry out in
darkness, bad weather or dense foliage. A serious pollution incident could
occur. This could be avoided if a method that accurately locates leaks were
installed at the elevated sections of the line.
Other factors such as system effectiveness and false alarms are also
important considerations. False alarms, however, are generally accounted
for in the system sensitivity and response. System effectiveness depends
upon the specific system and will not be discussed further in this section.
It should be considered for each specific installation.
In addition to the capabilities of methods to reduce the volume of
spillage, sufficient information must be known about the actual spills.
This is important in selecting the most suitable methods for certain types
of spills. It is also important for defining spills so that estimates can
be made of the oil spill risk reduction that is achievable with each method.
The information needed for each accident includes:
• Geometry, dimensions and location on the line pipe of the
source of the escaping petroleum
• Volume of fluid lost as a function of time
• Spill volume
Response time is defined here as the time duration required to positively
identify a spill so that the system can be shut down.
278
-------
• Time the leak was detected and by what means
• Time the pumping station was shut down after detection of
spill
• Time the mainline valve closed
• Type of soil
• Other.
Much of this information is not available. In this study, however, esti-
mates and assumptions are made to account for this lack of information. For
example, leak-type spills are assumed to have low flow rates (less than a
few barrels per hour) with losses ranging from 1 to 400 barrels. Thus,
approximately ten percent of the reported spill volume is attributed to
leaks; the remainder is attributed to ruptures. (These percentages were
obtained from Table 19).
A reduction analysis of the spill volume for ruptures and leaks is
presented for the selected methods in the subsections that follow.
7.1.2.1.1 Estimation of the Capability of Reducing Rupture Volume Using
the Selected Methods
Selected methods for reduction of the volume of rupture type spills are
shown in Table 66. Frequency of inspection, percent reduction of spill vol-
ume, risk reduction factors and normalized values for risk reduction are also
included in the table. A single visual inspection in excess of the required
bimonthly inspections by air or ground patrol, is the reference inspection.
Bimonthly visual line inspections, periodic monitoring of cathodic protec-
tion systems, and the monitoring of pressure deviations at the pump stations
are considered to be the commonly used methods during the reference year for
detection of ruptures. Methods are evaluated primarily on the basis of the
product of sensitivity and short-term response time. However, effects of
line transients on the capability of a method to detect ruptures are also
considered.
In the analysis performed in this section, ruptures and large-size
breaks are assumed to account for approximately 90 percent of the volume
spilled. Also, ruptures and large size breaks are assumed to typically re-
sult in spill rates in excess of five percent of throughput. Hence, for the
reference line (flow rate of 2,500 barrels per hour), this type of spill
would result in a loss in excess of 125 barrels per hour.
Spill statistics in Section 4 (see Table 19) indicate that over 90
percent of the spill volume results from spills in excess of 400 barrels,
and over 80 percent result from spills in excess of 1,000 barrels. Thus,
methods that can limit the spill volume to less than 1,000 barrels (about
four percent of average hourly throughput) would conceivably eliminate
approximately 72 percent of the spill volume.
279
-------
TABLE 66. SPILL REDUCTION ANALYSIS FOR VOLUME OF RUPTURES
FOR TYPICAL SECTION OF LINE PIPE
Inspection or Leak Detection Method
1. Visual Inspections by air or ground patrol for
indication of a spill (Required inspection—
existing MtMd)
2. Visual inspections by air or ground oatrol In
encess of required inspections
3. Visual inspection by air or ground patrol with
hydrocarbon probe or comrable device
Indication of a spill
FffJQIMflcy/
rear
2S
26(Ref)
338
26
338
Ruptures' "'
J Reduction of
Spill volume
Indicated i Single
Inspections! Inspection
0 0
9 O.I9(R.f)
40 0.12
9 0.19
40 0.12
Risk
Factor*
1
0.95
0.6
0.95
0.6
Seduction
Normal tied'
Nft
l.O(Ref)
0.6.
1.0
0.6
4. Hydrocarbon prooe-towflsn or staiilar device
- UMenMter lines only
- Total line pipe «ileage
i. Oil spill detectors
- Marine terminal or platfora
- Total line pipe •iloaoa}
6. Pressure deviations
a. Puii) station (nisttng wtkod)
t. HaKf Une
7. F1« rate
a. Deviations
B. Canaarlsoin (ocwterized)
a. VotuM conarlsom (coeouteriied)
9. »oie»it1cal "odellng (coaputeritM)
10. Hegetive pressure surge (coeguterlted)
11. fiulve acoustic array (computerized)
12. Eiternel rods «lt» passive acoustic sensors
1). Pressure static
14. Hydrostatic
IS. Pressure difference
16. !!(•) and 13
17. 11(6) and 13
18. «(a). 7(b). *
19. <(a). 7(a). 7(o). a. 10
20. 10. 13
after Indi-
cation of
spill
after indi-
cation of
spill
continuous
continuous
continuous
continuous
continuous
continuous
continous
continuous
a. continuous*
b. eoHtinmui'
after Indi-
cation of
rupture*
after Indi-
cation of
metlire*
IB
«
continuous
continuous
continuous
continuous
continuous
I NO
!NO
30
[NO
0
10
20
40
70
90
33
SO
70
10
20
us
us
70
SJ
30
95
SO
[NO
[NO
30
[NO
0
10
20
40
70
90.
33
60
70
3.3
6.6
70
30
30
95
SO
[NO
[NO
0.7
(NO
m
0.9
0.8
0.6
0.3
0.1
0.7
0.4
0.9
0.8
us
NS
0.3
0.2
0.2
0.05
0.5
[NO
[NO
153
[NO
1U
S3
105
210
3M
474
174
315
36a
17.3
34.6
NS
us
122
237
4Z1
500
263
Nit-Net applicable since mathed MS cosamly used for yeer wwn risks xere determined.
NS-Hot suitable for indicated detection of leaks or ruptures.
3. lNO-lm»u»i»ent not discernible.
«. Msk of oil spills after applying CM Inspection otMd is CM product of t«U factor and tne risk
: and cosssgnly used Mtliods. The value is obtained by subtracting the percent n
from 1.0.
i. Risk redaction noramllted is the percent reduction froe a single inspection divided by the percent i
resulting free OM reference inspection.
i. Retrofit Installation.
7. Installation on new line.
a. Assam frequency of Inspection carried out three tines a year.
value «1th
eduction
280
-------
Bimonthly visual line inspections, the only major inspections required
by U.S. regulations, ar-e ineffective in reducing the volume of rupture type
spills. At a spillage rate of 125 barrels per hour, 42,000 barrels of oil
could be spilled between biweekly inspections or 21,000 barrels between
weekly inspections. Even for more frequent inspections, i.e., daily, 1,500
barrels of oil typically would be spilled before detection. Considering
that spills in excess of 1,500 barrels account for about 70 percent of the
total spill volume, reductions in spillage would be expected by more fre-
quent visual line inspections. However, many spills of this magnitude are
detected by outside observers. Thus, more frequent inspections are not as
effective as indicated; a risk reduction factor of 0.6 was assessed for
daily inspections and 0.95 for weekly inspections. Aided bimonthly visual
inspections such as using a hydrocarbon probe or other comparable device are
not expected to produce any additional reduction in the spill volume that is
discernible.
Although there is a trend towards continuous monitoring of lines using
advanced computerized methods, most operating companies only monitor pres-
sures at pump stations for indications of ruptures. This method is extreme-
ly insensitive and is capable of detecting only rupture type spills close
to the pump station; the sensitivity of the method decreases with distance
from the pump station. For this method, it has been estimated that, on the
average, ruptures resulting in 20 percent of throughput could go undetected
for greater than one hour.
Monitoring of pressure deviations along the line reduces the problem
of decreased sensitivity with distance. The method is considered only mar-
ginally adequate for rupture detection; a risk reduction factor of 0.9 is
assessed.
Simple monitoring of flow deviations at one or more stations for indi-
cations of rupture is often used by operating companies. Line transients
generally require that the alarm setpoint be quite high, i.e., five to ten
percent of throughput to eliminate false alarms. The method is considered
only marginally adequate for rupture detections; a risk reduction factor of
0.8 is assessed.
An approach to significantly reduce the volume of ruptures is to use
one or more of the methods that employ computerized continuous monitoring.
Based on the information supplied in Table 66, limiting the spill size to
less than 1,000 barrels appears to be relatively easy to accomplish using
many of the computerized methods. However, the various transients that oc-
cur in the line, such as line pack, pressure changes, flow changes, pump
shutdown, etc., make this somewhat more difficult to accomplish. These
transients are often accounted for by various measures such as lengthening
the time duration of monitoring for a leak alarm, raising alarm setpoints so
that the sensitivity is compromised, or using a computerized model that
automatically monitors and accounts for these variations.
The mathematical modeling method currently under evaluation on a number
of lines, has the potential of being the most effective of all methods
281
-------
surveyed. Despite transients, the method appears to be capable of detect-
ing leakage rates of 0.5 percent of throughput in about two minutes. This
would result in a loss of less than one barrel for a typical line before a
leak could be detected and verified. This method appears capable of de-
tecting essentially all rupture type spills; a risk reduction factor of 0.1
was assessed.
The flow rate comparison method is also effective in detecting rupture
type spills. The method requires that high accuracy meters (0.02 to 0.1
percent of flow) be installed at pumping stations and at inlet and outlet
locations. A leak between any two stations results in a characteristic in-
crease in flow rate upstream and a decrease downstream. Because of the
unique and characteristic rupture signal, the method is unaffected by many
line transients. The method is capable of detecting short-term leaks of
less than four percent of throughput in about two minutes. Primarily be-
cause the method appears capable of detecting most rupture type spills, a
risk reduction factor of 0.6 was assessed.
The computerized volume comparison method continuously monitors the
volumes at the input and output of the line. Corrections are normally made
for pressure, temperature and other factors. Modern systems incorporating
this method routinely detect ruptures of large-sized breaks at better than
three percent of throughput over a ten-minute interval. This method is con-
sidered to be an excellent means of indicating "rupture type" spills; a risk
reduction factor of 0.3 was assessed.
Negative pressure surge method is insensitive to many large-sized breaks
but should be capable of rupture detection. A risk reduction factor of 0.66
was assessed.
The passive acoustic array is an experimental method that has the dual
capability of rapid detection and accurate location of rupture or large-
sized breaks. Sensitivity, reliability and false alarms are uncertain.
Considering that the method is unproven on an operational line, a risk
reduction factor of 0.3 was assessed. Potentially, a risk reduction factor
of 0.1 is possible, primarily because of its ability to locate the rupture.
Two methods in use on a few lines are particularly useful after a rup-
ture or large-sized break is indicated by other means. Passive acoustic
sensors installed on rods permanently attached to the line would be a great
benefit in high risk areas because of the capability of locating the spill.
However, for use on a typical line, a risk reduction factor of only 0.9 is
warranted. The pressure static method is particularly well suited for veri-
fying the existence of a large leak which may be slightly below the sensi-
tivity of the leak indication method. A risk reduction factor of 0.8 was
assessed for the latter method.
Combinations of leak detection and inspection methods are capable of
affecting an improved reduction in the risk of rupture type spills. A few
of the more effective combinations are indicated for methods 16 through 20.
in Table 66.
282
-------
In summary, only a few methods are judged to have the potential for
significantly reducing the risks, i.e., have a risk reduction factor of
better than 0.5. These include:
• Mathematical modeling
• Passive acoustic array
• Volume comparison
• Combinations of pressure, flow and volume comparisons methods
• Pressure deviations, flow rate, volume comparison and negative
pressure surge.
Based on normalized risk reduction, the mathematical model method appears
most effective of those selected. One such inspection is estimated to be
equivalent to 474 visual inspections of the line. The volume comparison
method and passive acoustic array are also considered effective; these are
estimated to be equivalent to 368 visual inspections of the line.
7.1.2.1.2 Estimating the Capability of Reducing Leak Volume Using Selected
Methods
Selected methods for reducing the volume of "leak type" spills (less
than 400 barrels) are shown in Table 67 along with frequency of inspection,
percent reduction of spill volume, risk reduction factors and normalized
values for risk reduction. A single inspection in excess of the required
bimonthly visual line inspections is the reference inspection. Biweekly
visual line inspections and periodic monitoring of the cathodic protection
systems are assumed to be the commonly used methods for detecting leaks.
For leak reduction, continuous monitoring methods are evaluated primarily on
the basis of the product of long-term response time and sensitivity, peri-
odic methods are evaluated primarily on the_basis of sensitivity and fre-
quency of inspection.
In the analysis, leakage of less than 400 barrels is assumed to account
for about ten percent of the reported volume of spillage. Line pipe leakage
normally is assumed to occur continuously at very low rates (less than a few
barrels per hour). However, leaks may often occur intermittently. Reference
78, for example, indicates that for some lines leak rates of approximately
0.7 barrels per hour are required for hair crack type leaks to stay open.
Hence, intermittent leaks are also considered in this analysis.
Bimonthly visual line inspections are considered to be marginally ef-
fective in reducing the volume of "leak type" spills. For example, a con-
tinuous leak of two barrels per hour could spill 336 barrels before detec-
tion by biweekly visual inspections.
Assuming the leakage is normally continuous, more frequent visual line
inspections would be expected to reduce the volume lost by an amount almost
proportional to the inspection frequency. Thus, weekly inspections are
judged to reduce the spill volume by about 30 percent; a risk reduction
283
-------
TABLE 67. SPILL REDUCTION ANALYSIS FOR THE VOLUME OF LEAKS
FOR A TYPICAL SECTION OF LINE PIPE
I.I.I
; LEAKS
Inspection or Uak Detection Method
!
frnofrxyf |
y«ar ',
1. Visual Inspections By air or ground patrol for 25
Indication of > spill (Required insptction--
existlng method) '
2. Visual inspections By air or ground patrol in t. 2((Ref) ;
«Ctu of required Inspections s JM
3. Visual inspection By air or ground patrol with a. 2S(Ref)
hydroeiroeii proM or coraaraole dtvici h »
Indication of a soill , "
;c. 338
4. Hydrocarbon probe-tmrlsh or similar device
- Underwater lints only
- Total tine pipe mileage
5. Oil spill detectors
• NaHne terminal or platform
- Total KM pip* miMit
6. Prtssur* dtvittlom
a. Plav stltiom (Kilting nttlwd)
B. Along Hi*
1. flat ran
a. Otyiatiom
B. Coawrltam (comitirlzM)
8. VOIUM comnsons (coiouttrltid)
9. mtnmtlul aoMlinf (cMpuwHitd)
10. Ittjjtlv* prasnm turn (cowttrind)
S
s
continuous
continuous
continuous
continuous
continuous
contlnous
continuous
continuous
continuous
11. Pmtw s cuaiuuly ustd 'or ytar tKt1on of leaks or njptum.
3. llB-li»ii
-------
factor of 0.7 was assessed. For daily inspections, a risk reduction factor
of 0.3 was assessed.
Use of visual aids, such as hydrocarbon probes or other comparable de-
vices, by ground patrol are expected to further reduce the volume spilled.
These inspections provide the potential for detecting very small or inter-
mittent spills or spillage that may be trapped and not reach the surface
for a long period of time. A risk reduction factor of 0.8 was assessed for
aided biweekly inspections by ground patrol, 0.6 for weekly and 0.2 for
daily inspections.
Bimonthly periodic inspections of underwater lines using hydrocarbon
probes in a towfish system are expected to be quite effective. These in-
spections are expected to detect small leaks that may not be detected by
visual inspections. For example, small leaks that might otherwise be con-
sidered as underground seepage could be detected and located. A risk re-
duction factor of 0.5 was assessed for these inspections. Since only ap-
proximately ten percent of line pipes are underwater, the risk reduction
factor assessed on a nationwide basis for all lines is 0.95.
Continuous monitoring of internal fluid variations during fluid trans-
fer using pressure, flow rate, and negative surge are not considered suit-
able for leak detection. Normal operations generally produce line transients
that require an operator to raise alarm levels so as to preclude the de-
tection of small to medium sized leaks, i.e., few barrels per hour. The
volume comparisons method is only marginally capable of detecting leaks and
only under optimum conditions. These methods are expected to provide no
discernible improvement over biweekly visual inspections by ground patrol.
Of the remaining continuous monitoring methods, only mathematical
modeling and passive acoustic array are considered to be capable (margin-
ally) of detecting medium sized leaks. Risk reduction factors of 0.8 were
assessed~for these methods.
The method employing rods with passive acoustic sensors has poor sen-
sitivity for leak detection. However, it can be used to reduce the time
required to locate an expected leak. Thus, a risk reduction factor of 0.9
was assessed.
Periodic pressure testing methods, unless carried out often, are not
particularly beneficial. The pressure difference method is the most sensi-
tive of the inspection methods. However, frequent tests, i.e., monthly,
would be required to substantially reduce leakage. A risk reduction factor
of 0.1 was assessed for such frequent inspections. This method would be
particularly beneficial in certain high risk areas where even minute spills
can be hazardous. The pressure static method, by itself, would not appre-
ciably reduce leak spill volume because of its poor sensitivity. However,
after a medium sized leak is indicated by some other means, this method is
effective in verifying the existence of a leak. It was assessed a risk re-
duction factor of 0.8 assuming it would be used in conjunction with mathe-
matical modeling or the passive acoustic array. Hydrostatic tests carried
out even on a frequent basis are not expected to substantially reduce the
285
-------
leak spill volume. The method, however,_wou Id be quite effective in veri-
fying the existence of small to medium sized leaks. Risk reduction factors
of 0.6 and 0.7 were assessed for the two inspection schedules given in
Table 67.
Combinations of leak detection and inspection methods are capable of
affecting improved reduction in the risk. A few of the more effective com-
binations are shown in Table 67.
Only a few methods appear to be highly effective in reducing the volume
of leak type spills. Of all the methods, the pressure difference methods
appear to be the most effective. However, this inspection method requires
installation of closely spaced block valves and also requires line shutdown
during the inspection. Frequent visual and visual-aided line inspections
appear to be highly effective methods in reducing the volume of these oil
spills. However, almost daily inspections are required to produce risk
reduction factors better than 0.5. Twice yearly hydrostatic tests with the
passive acoustic array are judged to be effective. The main reason is that
the acoustic array can be used to locate the leaks. This is particularly
important during hydrostatic tests on long lines where a number of small
leaks may be erroneously accounted for by temperature or other effects.
Hydrocarbon probes may be substituted for the acoustic array if the line
is filled with petroleum or gas detectors or analyzers may be substituted
if the line is pressurized with helium of some other inert gas.
Since only about ten percent of the spill volume is attributed to leak-
type spills, no method presented can affect a significant reduction in the
spill volume as compared to the methods identified for rupture type spills.
Because even leak type spills can be serious, particularly in.high risk
areas, the volume of these spills should be reduced as much as possible.
7.1.2.2 Factors Affecting the Capability of Methods to Reduce the Fre-
quency of Spills--
The capability of a method to reduce and, if possible, eliminate the
occurrence of spills depends upon the ability of the method to detect im-
pending failures (internal defects) sufficiently early so that pipe line
repairs can be made and a spill prevented. Various methods can be imple-
mented to detect pipeline defects that may result in a spill. The following
three main factors affect the capability of these leak detection and inspec-
tion methods detect impending failure and thereby reduce the frequency of
spills:
• Sensitivity (detectable defect size)
• Location accuracy (pinpointing defect)
• Frequency of inspection.
The effect of each of these factors varies widely depending upon the imple-
mentation of each method. It also depends'upon whether the method is used
for reducing the frequency of leaks or ruptures or the frequency of spills
by cause. Thus the combined effects of these characteristics along with
286
-------
risk reduction factors3 and normalized values'3 for risk reduction. Spill
analysis risk reduction is based on the capability of an individual method
or combination of methods to reduce the oil spill risk below the value estj-
mated for the methods in common use on most lines for the reference year
1975. Inspection and leak detection methods for operational lines that are
assumed in the analysis for the reference year are:
• Biweekly visual inspections by air or ground patrol for
indications of a spill—(Required by U.S. regulations)
• Periodic inspections of the cathodic protection system—
(Required by U.S. regulations)
• Monitoring of line pipe pressure deviations at pump stations
• Voluntary One-Call System.
To simplify comparisons of the selected methods, a normalized risk re-
duction value is provided. This allows one to compare the number of inspec-
tions by various methods to achieve a certain reduction in the oil spill
risk. The normalized value is based on a single reference inspection. One
visual inspection in excess of the bimonthly inspections by air or ground
patrol is used for this purpose. Results indicate, for example, that one
inspection by an inspection survey pig is equivalent to 136 visual inspec-
tions of the line for reducing the frequency of leaks by 52 percent.
7.1.2.1 Factors Affecting the Capability of Methods to Reduce the Volume
of Spills-
Rapid detection and location of the onset of small quantities of
petroleum pipeline leakage so that system shutdown can be initiated are the
four most important factors in reducing the volume of accidental spills.
The four major factors (method characteristics or specifications) for re-
ducing the volume of spill are specifically:
• Response time
• Leak location accuracy
• Leak sensitivity
• Frequency of inspection.
Risk of oil spills, after applying the inspection method, is the product
of this factor and the risk value with currently required commonly used
inspections. The value is obtained by subtracting the percent reduction
from 1.00.
Risk reduction normalized is the value of the percent reduction of the
spill risk for a single inspection divided by the percent reduction of
the spill risk for one reference inspection.
287
-------
these other considerations determine the overall capability of a method to
reduce the frequency of spills. Hence, each is considered in the evalua-
tion. Section 7.1.2.1 provides a discussion of the significance of these
factors.
Implementation of leak detection and inspection methods that are capa-
ble of satisfying these required characteristics is considered to be the
optimum approach for minimizing the hazards of accidental spills from
petroleum line pipe. In general, prevention of ruptures would normally be
of higher priority than the prevention of leaks. However, the objective
should be to reduce all spill incidents. At this time, U.S. regulations
for installation and periodic inspections of cathodic protection systems in
the line pipe and depth of cover on line pipe are the main U.S. efforts in
achieving reduction of frequency of spills. Although these methods are
quite useful, they have not resulted in significant reductions in the fre-
quency of spills, particularly those resulting in "rupture-type" spills.
The major emphasis in a spill prevention and control program should be
directed towards the goal of eliminating or at least minimizing the fre-
quency of spills. The reason for this conclusion is that methods that re-
duce the volume of spills (detect actual spills) do not stop spills. These
methods have two inherent limitations. First, even with rapid detection of
medium to large size spills, a certain amount of hazardous fluid can escape
from the line before the spill is totally contained. Secondly, many "leak-
type" spills and many "rupture-type" spills cannot be detected.
The sensitivity of the method is the most important capability in re-
ducing the frequency of spills. Sensitivity is based on the ability of the
method to detect minute internal defects that may lead to a leak or minutely
small leaks (drip type) that may lead to failure.
The frequency of inspection is also an important consideration. For
example, increased frequency of visual inspection of the line for the pur-
pose of eliminating third party activities such as excavations that might
result in damage to the line pipe, reduces the risk of a line pipe spill.
The capability of providing accurate leak location, i.e., within a
few feet is also important. For example, the ability to pinpoint a small
leak during hydrostatic tests greatly enhances the effectiveness of a method.
It is difficult to assess quantitatively the ability of a method to
reduce the frequency of spills, for a number of reasons. These include:
• The geometry and dimensions of an interval defect that will
result in a spill incident are not precisely known.
• The geometry and dimensions of leaking areas are not reporta-
ble. Thus, information as to minimum or typical hole size
that would result in a leak or rupture type spill is not pre-
cisely known.
• Quantitative data suitable for detailed comparisons of many
of the selected methods are not available.
288
-------
• Effectiveness of some inspection methods often depend upon
such factors as line pipe dimensions (i.e., diameter) and
location (i.e., on!and, underwater, etc.).
Nevertheless, sufficient information is available from manufacturers and
user experience (see Tables through and Appendix E) to make qualita-
tive estimates that are suitable for analysis.
For typical lines, the capability of a method to reduce the frequency
of spills by cause is of prime importance. For certain line pipe, analysis
of the capability of a method to reduce incidents of spills based on type,
leak or rupture, can be particularly advantageous. For example, older lines
typically have high potential for leaks whereas large diameter new lines
have an inordinately high potential for ruptures.
Analysis of the reduction of the frequency of spills is carried out in
the subsections that follow. Analysis by cause and type (leaks, rupture)
are treated separately.
7.1.2.2.1 Estimation of Capability of Reducing Spill Incidents from All
Causes Using Selected Methods
Selected leak detection and inspection methods for reducing the fre-
quency of spill incidents for each of the major causes of spills and all
causes combined are presented in Table 68. Methods are shown along with
frequency of inspection, percent reduction of incidents, risk reduction
factors and normalized values for risk reduction. A single inspection in
excess of the required bimonthly visual inspections is the reference inspec-
tion. It is used in the computation of the normalized values for risk
reduction. Biweekly visual line inspections and periodic monitoring of the
cathodic protection system are assumed to be the commonly used methods dur-
ing the reference year for spill prevention.
Capability to prevent line pipe faults is based primarily upon the
overall ability of a method to detect insignificant leaks or line pipe de-
fects that are generally indicative of impending failure. Capability to
prevent damage by outside forces is based on the overall ability of a
method to detect activities of outside forces (usually impacts) before a
failure can occur.
The number of incidents for the causes of line pipe failures were
obtained from Table 19. These are:
• Line pipe faults - 56 percent of spills
• Outside forces - 41 percent of spills
• Other causes - 3 percent of spills.
These values are used in the computation of the percent reduction of spill
incidents identified under all causes. For example, a method that accounts
for a 50 percent reduction of spills from the line pipe faults but no other
reductions would account for a 28 percent reduction in the overall causes
of spills.
289
-------
TABLE 68. REDUCTION ANALYSIS FOR THE FREQUENCY OF OIL SPILLS BY CAUSE
FOR A TYPICAL SECTION OF LINE PIPE (REFERENCE LINE)
I
Inspection Or Leak Detection Method
1. Vlsiul Inspection by >ir or ground
patrol (Seoul red Inspections)
Z. Visual Inspection by air or ground .
Mini in excess of required h
Inspection*
niptctlom
ronmey/
Yttr
2S
. 26 !D1pt
FaulU
(S6t of
Spills)
0
OutHdt
Forcas
(405 of
Spills)
0
5 | JO-
ll) : 80
Outer
(3 -. of
Spills)
0
[NO
INO :
AH Causes
Indicated
nsaectlons
0
u
38
30 . [NO !NO ib
35 20 '.HO 28
40 80 ! :iO 55.
I
1
SO IW
5 INO
I!0
IW
I HO
IK)
WO
10
SO
60
70
90
10
w
M
7S
ss
10
10
80
90
9t
30
10
mo
[NO
70
90
IW
IW
IW
I»
[Ml
[in
I HO
im
IW
INO
so
90
90
95
[NO
INO
3
0
[NO
INO
MO
IW
IW
I NO
INO
IW
in
IW
INO
IW
IW
[HO
IW
IW
IW
IW
28
2.3
32
4.1
3.4
[NO
2*
43
28
34
39
SO
s.s
u
37
42
47
S.S
30
32
37
92
Single
nsoeetlon
a
0.42(Ref
3.11
3.2
:.os
0.16
».7
3. 47
a
i
5.4
[NO
28
43
28
34
39
12. S
1.9
11
37
42
47
1.9
30
32
0.37
3.54
Disk
Reduction
Factor* It
HA
0.39
0.62
0.34
0.72
5.45 j
Risk
Deduction
braallted'
NA
1.0 (Ref)
0.3
7.62
2.52
0.38
1
0. 72 11.2
0.97 i !.2
0.63
0.96
0.9
INO
0.72
0.57
0.72
0.66
0.61
0.50
0.95
0.89
0.63
O.S8
0.5}
0.95
0.70
9.18
0.13
0.08
19
2.4
20
IW
67
107
57
40
n
46
4.5
26
88
100
112
4.5
71
195
207
8.43
Notei: (l) m - Mt aooltcable since netnod M« convmly used «ien soil! frequencies «ere determined,
(2) IW - uionwtvent not discernible.
(3) Deduction of spill incidents, after applying inspection and/or leak detection iteund is cite sun of tfle produces of tne reduction
factors and Uw percentage of spills resulting from casn cause (line oipe - Sts, outside forces 41:. other 3D ?or cue reference!ins.
(4) Disk of spills, after applying Oie inspection method is tne product of Ulis factor and tne risk «alu< oitn current required and
ccneonly used inspections, cue «akie is obtained by subtracting tne '. reduction fro i.o.
(5) Risk nonialKed is the percent reduction fro» a single inspection divided by tne percent reduction resulting fro* one reference
Inspection..
Retrofit Installation.
He* line Installation.
1:1
Altwe freeuency of Inspection carried out three ti«n a rear.
290
-------
Biweekly visual inspections carried out by air or ground patrol are
considered ineffective in preventing spills, even spills caused by outside
forces. Analysis of spill statistics (see Figure 22) indicates little or
no change in the reported incidents by outside forces, such as equipment
rupturing the line, between 1970 and 1976. Spill prevention by this in-
spection method is considered to be minimal.
Periodic inspections of cathodic protection systems are considered to
be responsible for some reduction in the spill incidents from external
corrosion. Data such as presented in Figure 22 indicate substantial reduction
in external corrosion between 1970 and 1976. Some of this reduction can be
attributed to cathodic protection systems. It should be noted, however,
that external corrosion generally results in the smallest spill size for the
major causes of spills (see Table 19). Thus, a significant reduction in
external corrosion does not affect a significant reduction in the total
volume of petroleum spilled. Also, these cathodic protection systems are
ineffective for reducing the incidence of internal corrosion and other major
causes of spills.
Visual inspections by air or ground patrol carried out on a weekly
basis are expected to reduce incidents of damage by outside forces by
about 20 percent and line pipe faults by about five percent. For these
26 additional inspections, a risk reduction factor of 0.9 was assessed.
For daily inspections, a risk reduction factor of 0.6 was assessed.
Use of visual aids, such as hydrocarbon probes or other comparable
devices, by ground patrol is expected to improve the detection of insig-
nificantly small leaks that may result in a reportable spill. Respective
risk reduction factors of 0.84, 0.72 and 0.45 were assessed for aided in-
spections by ground patrol that are carried out biweekly, weekly and daily.
Bimonthly inspections of underwater lines using hydrocarbon probes or
other equivalent devices in a towfish system that traverses the line is
expected to be quite effective in detecting and locating small leaks that
occur from corrosion and weld defects. These inspections are expected to
detect very small leaks that may lead to failure and that could not be de-
tected by other means. A risk reduction factor of 0.72 is assessed for
underwater lines, and a factor of 0.97 when all line pipe mileage is in-
cluded. Visual inspections at the surface for underwater lines are con-
sidered to provide no discernible prevention of line pipe faults.
Quarterly inspections of the line pipe for the depth of cover may re-
duce significantly the frequency of ruptures. Since most undersea pipeline
ruptures are caused by external impacts such as anchor dragging, a proper
depth of cover will minimize the potential of damage from these sources.
These inspections are judged to reduce the incidents of spills from outside
forces by about 30 percent. The overall risk reduction factor is 0.68.
For all line pipe, these surveys were judged to have a risk reduction fac-
tor of only 0.97.
291
-------
Charting the movements underwater lines enables one to detect abnormal
movements which could excessively stress the line. Inspections every two
years were judged to reduce the incidents of line pipe faults by about 15
percent; a risk reduction factor of 0.91 was assessed for underwater lines
and negligible risk reduction factor when all lines are included.
Use of a continuous monitoring passive acoustic array is expected to
be highly effective in reducing the incidents of damage by outside forces
and slightly effective in detecting impending line pipe failures, primarily
ruptures. A risk reduction factor of 0.57 was assessed for this method.
Yearly hydrostatic tests of the line pipe were judged to be capable of
detecting a majority of serious line pipe faults, i.e., minute leaks. For
this method, an overall risk reduction factor of 0.66 was assessed. If used
with the acoustic array, a much greater effectiveness can be achieved since
the line pipe response to changes in stress levels can be monitored. The
risk reduction factor of 0.18 is assessed for the combined methods.
Periodic pressure difference tests are judged to be the most effective
inspection method for detecting small leaks that may lead to failure. For
inspections carried out yearly and quarterly, risk reduction factors were
assessed at 0.61 and 0.50, respectively.
Yearly inspections of the condition of the interior of the line pipe
using inspection pigs are considered to be the best method overall for de-
tecting line pipe faults. Commercially available devices, such as equip-
ment from AMF Tuboscope, Inc. and Vetco, Inc. can be used in lines ranging
from six to 36 inches in diameter. A risk reduction factor of 0.53 was
assessed for yearly inspections with this device.
The prevention program for outside forces, the One-Call System, as
recommended in Reference 12, is considered to have the potential of signifi-
cantly reducing the damage by outside forces. An overall risk reduction
factor of 0.70 was assessed for this program.
Pigging the line for water removal is an important inspection/mainte-
nance activity that should be carried out on a frequent basis. This method
reduces the risk of internal corrosion and other causes of line pipe spills.
Since the method is often used on many lines, it has affected some reduction
in the spill risk. Thus, a risk reduction factor of only 0.95 was assessed.
Inspections of sample sections of the line for wall thickness changes
caused by corrosion can be effective in reducing the risk of oil spill in-
cidents, particularly for lines with corrosion problems. It is only prac-
tical to sample a small area of a line. This small sampling is judged
to be inadequate and thus no significant reduction in the risk can be at-
tained; a risk reduction factor of only 0.89 was assessed.
Combinations of leak detection and inspection methods are capable of
significantly reducing the risk of spill incidents. A few of the more ef-
fective combinations are shown in Table 28. Pigging the line for preven-
tion of line pipe faults used in conjunction with a One-Call System program
292
-------
to prevent outside forces is expected to produce an excellent risk reduc-
tion factor of 0.13. If weekly visual inspections added by the use of
hydrocarbon probes are also carried out, the risk reduction factor further
improves to 0.08.
7.1.4.2.2 Estimation of the Capability of Reducing the Frequency of Leaks
Using Selected Methods
Results of a reduction analysis for the prevention of "leak type"
spills are given in Table 69. Selected methods and major causes of spills
are the same as in the previous section. However, the values indicated in
the table are specifically for the reduction of "leak type" spills. These
values have been based on two estimates9. First, "leak type" spills are
considered to account for 75 percent of the reported accidental spills.
Second, the major causes of spills are expected to account for the follow-
ing incidents of leaks:
LEAKS (75 percent of all spills)
• Line pipe faults - 61 percent of leaks (46 percent of all spills)
corrosion - 52 percent of leaks (39 percent of all spills)
defective pipe seams, welds, etc. - 9 percent of all leaks
(7 percent of all spills)
• Outside forces - 35 percent of leaks (26 percent of all spills)
equipment rupturing line - 28 percent of all leaks (21
percent of all spills)
miscellaneous - 7 percent of leaks (5 percent of all spills)
• Other - 4 percent of leaks (3 percent of all spills).
Only a few methods appear to have the potential of significantly re-
ducing the line pipe faults which account for most (over 61 percent) of the
incidents of leaks. One method, survey by inspection pig, appears to be
the most promising. Other methods judged to have the potential of signifi-
cantly reducing line pipe faults include:
• Hydrocarbon probe with towfish for underwater lines
• Hydrostatic pressure testing
• Pressure difference pressure testing.
In preventing damage by outside forces, only these methods appear to be
effective. These include:
• Acoustic array
• Depth of cover inspection of underwater lines
• Frequent, e.g., daily, visual inspections of the line
• Prevention program for outside forces--One-Call System.
aThese are rough estimates and suitable for the evaluation purposes in this
study only.
293
-------
TABLE 69. SPILL REDUCTION ANALYSIS FOR THE FREQUENCY OF LEAKS
FOR A TYPICAL SECTION OF LINE PIPE
I
Inunction or Leak D*t*ct1m Mttlnd
1. iMiuil Inspection by air or ground
Htral (KtoulrM Inspections)
Z. Vlutl Inspection by air or ground
patrol In excess of required :
Inspections *
nsptctlOM
•rtoumcy/
Ytar
26 :
. 25(Rtf)
. 338
3. »1sual Inspection by ground patrol a. 26[
[NO
a
0
:m>
[no
im>
uto
INO
I»
IW
IM)
INO
IW
IW
IW
IW
IM)
IW
INO
IW
IW
IW
30.5
1.0
28
2.3
9.2
INO
21.5
37.6
30.5
36.6
42.7
67.3
6.1
12.2
40.3
45.8
51.8
6.1
27.1
30.3
36.4
91.2
36.4
SlmjU
nsptctlon
a
0.38(Ref
0.10
3.66
1.04
0.13
5.08
.51
7
.7
9.2
IW
21.5
37.6
30.5
18.3
42.7
17
2.03
12.2
40.3
45.3
51.3
2.03
27.1
30.3
36.4
3.51
36.4
Risk
Reduction
Factor* H
(«RFaj ;
W
Risk
Reduction
arnaltitd*
ill Causes
Single
nsptctlon
1A
0.90 l.O(Ref)
0.66 1 0.3
0.32 9.63
0.72 ! 2.37
a. 55 ' 0.34
0.70 !
0.97
0.72
0.97
0.91
IW
0.79
0.62
0.70
0.6T
0.57
0.32
0.94
0.88
0.60
0.54
0.48
0.94
0.73
0.20
0.14
0.09
0.14
13.1
1.3
18.4
1.3
24.2
IW
57
99
-.0.6
48.6
112
44.7
5.34
32.1
106
120
136
5.3
71.3
21 1
227
9.2
227
Notes: (i) *A . not applicant* since method M«S coomnly ustd vh«fl spill frequencies «ere d*temhn«d.
(2) INO - ImproveMent not discernible.
(3) Reduction of SQill incidents, after aoplying. imptctton and/or leak detection method is the sum of tne products of the reduction
factors and the percentage of spills resulting fron cash cause (Tine pipe - 61'. outside forces 35*. other 4?) for tne reference Hr>
(*) Risk of spills, after applying the inspection method is the product of this factor and tne risk value with current required and
coMonly used inspections, tne value is obtained by subtracting tne • reduction fron 1.0.
Risk nonNlizeti is the percent reduction fro* « single inspection divided Oy trie percent reduction resulting from one reference
inspection..
Retro/It installation.
New line Installation.
(5)
(6)
(7) .
(8) AHUM frequency of inspection carried out three t1«et a year.
294
]
-------
These methods are most effective in reducing either line pipe faults or
outside incidents. Hence, no individual method appears to have the poten-
tial of eliminating most of the leak type spills. Only two methods are
judged to have risk reduction factors better than 0.5. Bi-yearly surveys by
inspection pigs are assessed at slightly better than 0.5. Frequent pressure
difference tests are assessed at 0.32. By using combinations of inspections,
however, risk reduction factors of better than 0.20 are potentially possi-
ble. For example, using the survey inspection pig and either a prevention
program for outside force or a passive acoustic array system are assessed
excellent risk reduction factors of 0.14.
Based on normalized risk reduction factors and single inspections,
five methods stand out for reducing risks. These include:
• Survey by inspection pigs
• Pressure difference
• Passive acoustic array
• Hydrostatic
• Prevention program for outside forces One-Call System.
7.1.4.2.3 Estimation of the Capability of Reducing the Frequency of Rup-
tures Using Selected Methods
Results of reduction analysis for the prevention of "rupture type"
spills are given in Table 70. Selected methods and major causes of spills
are the same as those identified in Section 7.1.4.2.1. Values indicated in
the table are computed using the same approach followed in the reduction
analysis of the frequency of "leak type" spills. "Rupture type" spills
are estimated to account for 25 percent of the reported accidental spills.
The major causes of spills are estimated to account for the following inci-
dents of rupture:
RUPTURES (25 percent of all spills)
• Line pipe faults - 40 percent of ruptures (10 percent of all
spills)
defective line pipe - 40 percent of ruptures (10 percent
of all spills)
• Outside forces - 60 percent of ruptures (15 percent of all
spills)
Equipment rupturing line - 40 percent of ruptures (10
percent of all spills)
Excavation equipment - 12 percent of ruptures (3 percent
of all spills)
Miscellaneous - 8 percent of ruptures (2 percent of all
spills).
295
-------
TABLE 70. SPILL REDUCTION ANALYSIS FOR THE FREQUENCY OF
RUPTURES FOR A TYPICAL SECTION OF LINE PIPE
Inspection or Ltik Dtttctlon Method
1. y
-------
Methods that appear most promising for reducing line pipe faults and
outside forces for "rupture type" spills are similar to those previously
identified for "leak type" spills. Whereas line pipe faults account for
most leak incidents, outside forces are the major causes of ruptures. Thus,
there are some differences in the risk reduction factors and normalized risk
values for the most effective methods for "rupture type" spills. Two meth-
ods judged to have risk reduction factors better than 0.5 are:
• Frequent, e.g., daily, visual inspections by ground patrol
with hydrocarbon detectors or other comparable devices
• Passive acoustic array.
By using a combination of inspections, risk reduction factors of better than
0.20 are potentially possible.
7.2 OIL SPILLAGE THAT POTENTIALLY CAN BE PREVENTED USING THE SELECTED LEAK
DETECTION AND INSPECTION METHODS
Analysis of the spillage that potentially can be prevented (or go unde-
tected) by implementation of the selected inspection and leak detection
methods is carried out in this section. From this analysis, it is possible
to estimate the expected reduction of spill incidents and spill volume for a
scheduled series of inspections. Estimates are based on the results of the
analysis of the oil spill risks in Section 6.3 and the capabilities of
selected methods to reduce the oil spill risks in Section 7.1.2.
The approach and necessary equations for estimating spillage are pre-
sented in Section 7.2.1. Sufficient information is provided so that quan-
titative values can be determined for most lines.
Values for spillage prevented using selected leak detection and inspec-
tion methods are computed and results discussed for the reference line in
Section 7.2.2. Spillage values are computed for all U.S. lines in Section
7.2.3.
7.2.1 Means of Calculating Spillage that Potentially can be Prevented
Quantitative values of the spillage that potentially can be prevented
(or go undetected) can be computed for most lines using the equations pro-
vided in Sections 7.2.1.2 through 7.2.1.4. The frequency and volume of
spillage can be estimated for all spills and also for "leak type" and "rup-
ture type" spills. Values for existing spillage that must be used in these
equations can be obtained from information provided in Section 7.2.1.1. The
risk factors for the various leak detection and inspection methods that also
must be used in these equations can be obtained in Table 71a.
aThis table summarized the risk reduction factors from Tables 65, 67, 69
and 70.
297
-------
TABLE 71. SUMMARY OF RISK REDUCTION FACTORS FOR SELECTED
INSPECTION AND LEAK METHODS
Oil S>111 Mtt Rtductlon Ftcton1"'1
Inspection uid/or Ltak Detection nttmos
1. V1SW1 Inspection of lint by «1r or
ground patrol (required Inspections)
for Indication of spill
2. Visual Inspection of line by air or
ground patrol in txcess of required
inspections 'or indication of 50111
3. yisual Inspection of I1n* or jround
Mtroi «IOi hydrocarbon probe or
cosmrable 3t»lct for indication of
jplll
4. HydraeirMn proM-CMflsn or jimlar
device
-Underwater llnM only
-All 11m*
5. f ratlin deviations
(.Pin* stations (eitstlno notnod)
b.Alo«« Ifnt
«. no. tatt
• .Oavlttlom
i.Co^artioin (comittrtM)
7. Mmm eo«wrtjont(a»p<.t«rltM)
3. mtlMHtlul adtitng (omtarlad)
9. Nfgitlw prntyr* surot (cowttrlztd
10. PtutM Mowttc S
O.TO e
o.so us
0.40 NS
n. m «
« NS
IS NS
NS NS
NS NS
NS NS
is e
NS NS
NS NS
NS «
(continued)
298
-------
TABLE 71 (continued)
20
21
22
23
24
25
26
27
28
29
Inspection and/or Leek Detection Methods
. Preventive program for outside forces
(Reference 12)
. P1g line for weter removal
. Oil spill detectors
-Herlne temlna! or platform
-Total line pipe «1!ea«e
. 10(b) and )3(a;
. 17(c) em) 20
. 3(a). 17(c) and 20
. HXb) and 17(c)
. 5(a). 6(a). 7
. 5(a). «(a). 6 (t). 7 and 9
. B end 17(c)
' Oil
Inspections i frequency
'-""" ; %%
cont. 0.73
3' 0.94
continuous IW
continuous INO
0.20
0.14
0.09
0.10
0
0
0.48
Spill Disk deduction Factors'"-'
Ruptures
0.60
0.96
1C
MS
0.14
0.10
O.OS
0.14
0
0
0.6C
Volume
Leaks
NS
•6
0.50
0.95
0.50
NS
o.co
0.80
1X0
IW)
0.80
Ruptures
NS
«
IB
NS
0.70
NS
0.95
0.30
0.20
O.OS
0.10
(1) M - Hot ippllciblt slnct nthod MI umaiiily uud for ynr «ftw ritkt wrt dtuminta.
(2) NS - Not lulUblc for indiuuo dttietlon of luki or ruptures. Thtrtfore < risk
reduction factor of 1 1s «ss1ontfl.
(3) [NO - Immanent not discernible. Tnerefore i risk reduction fictor of 1 is
assigned.
(4) Retrofit Installation.
(5) Installation of nex lines.
(6) Assune frequency of Inspection carried out tnree times a year.
299
-------
Particular attention should be given to the means of computing the
total volume of spills (Section 7.2.1.4) that can be prevented. Total
volume depends on the capabilities of a particular method to reduce both
parts of the risk, i.e., preventing spills and reducing the size of each
spill. This results in more complex equations than required in computing
spillage for methods that reduce only one part of the risk.
7.2.1.1 Computation of Existing Annual Spillage—Frequency, Volume and
Spil-1 Size—
The oil spill risk, total volume spilled V$TC and frequency F$TC» is
computed for the line using an approach similar to the one presented in
Section 6.3.4. First, the spill risk for the reference line, frequency
FST and volume V$j, are obtained from Table 57. Then values for correction
factors which are used to account for variations from the reference line
are obtained. Correction factors for the frequency CFp (age, geometry,
length, use, spill size) and volume CFyM (diameter, length, use, pumping
station shutdown, mainline valve closure, line elevation) are estimated
using Figures 54 and 57. Annual volume V$TC and frequency FSTC °f spills
from the line are then calculated using Table 59.
The same approach can be used in computing the nominal largest spill
size for ruptures V^i RC» leaks VNM c and mean spill size VJVJQ. Table 60,
however, is used instead of Table 59.
7.2.1.2 Computation for Reducing the Frequency of Spills—
The number of spills that can be prevented (or go undetected) can be
computed for the methods installed specifically for the reduction of oil
spill incidents. This can be done since the oil spill risk FSTC and the
risk reduction factors, RRFpi_ and RRFpR, for the methods are known. Assum-
ing 75 percent of the spills can be attributed to "leakage-type" and the
remainder to "rupture type," the following can be used to estimate annual
frequency of spills:
FLp = (0.75 x FST(.) (1 - RRFFL) (1)
FRp = (0.25 x FSTC) (1 - RRFFR) (2)
FP =FLP+FRP
FU " FLP ' FRP + RSTC
where
FSTC = total frequency of spills corrected for line pipe
F, p = frequency of leaks prevented after installation of leak
detection and/or inspection method(s)
300
-------
FRp = frequency of rupture prevented after installation of leak
detection and/or inspection method(s)
Fp = total frequency of spills prevented after installation of
leak detection and/or inspection method(s)
RRFp, = risk reduction factor for frequency of leaks after installa-
tion of leak detection and/or inspection method(s) - see
Table 71
RRFpn = risk reduction factor for frequency of ruptures after in-
stallation of leak detection and/or inspection installed -
see Table 71
F.. = total frequency of spills undetected after installation
of leak detection and inspection method(s).
7.2.1.3 Computation of the Reduction of the Volume of Spills Using Methods
that Reduce Only the Spill Size—
The value of volume of spills that can be prevented or go undetected
can be computed for the methods installed specifically for spill size re-
duction. This can be done since the oil spill risk for the volume spilled
VSTC and tne ris|< reduction factors, RRFyF and RRFvi_» for the methods are
known. Assuming that 90 percent of the spill volume can be attributed to
"rupture-type" and the remainder to "leak-type," the following can be used
to estimate annual volume of spills:
VLR = 0.10 VSTC (1 - RRFV|_) (5)
VRp = 0.90 VSTC (1 - RRFVR) (6)
Vp =VLp+VRp (7)
VU ' VLP = VRP + VSTC
where
VSTC = total vo^ume of spills corrected for line pipe
V.p = volume of leaks prevented after installation of leak
detection and/or inspection method(s)
VRp = volume of ruptures prevented after installation of leak
detection and/or inspection method(s)
RRFy, = risk reduction factor for volume of leaks after installa-
tion of leak detection and/or inspection method(s) - see
Table 71
RRFVR = risk reduction factor for volume of rupture after installa-
tion of leak detection and/or inspection method(s) - see
Table 71
301
-------
Vp = volume of spills prevented after installation of leak de-
tection and/or inspection method(s)
V.. = volume of spills undetected after installation of leak de-
tection and/or inspection method(s).
7.2.1.4 Computation of the Reduction of Volume of Spills for Methods that
Reduce Size and/or Frequency of Spills--
The volume of petroleum spillage that can be prevented (or go undetec-
ted) depends upon the capability of reducing both parts of the spill risk,
i.e., preventing spills or reducing the size of each spill3. As indicated
in the previous section, methods that reduce spill size cause the total
spill volume to decrease. Also, methods that reduce spill size often affect
some reduction in the frequency of spills. However, methods that reduce the
frequency of spills also perform a secondary function; they eliminate the
spillage volume that would have occurred if the spill had not been prevented.
Generally, a spill prevention and control program would be expected to
include a combination of methods that result in the reduction of both the
frequency and volume of spills.
The following equations can be used to compute the total spillage pre-
vented Vjp and spillage undetected Vju for one or more methods that reduce
one or both parts of the oil spill risk:
VSMC = VSTC/FSTC (9)
VTRp = VSMC x FSTC (1 - 0.9 x RRFVR x RRFFR - 0.1) (10)
\i — \i v C M n 1 v BDF Y BPF -DCn M "M
VTLP " VSMC x FSTC U ' °a X RRFVL x RRFFL °'9; U1)
VTP = VTRP x VTLP = VSMC = VSTC (1 " °'9 x RRFVR
x RRFFR - 0.1 RRFVI_ x RRFF1_) (12)
VTU = V$TC - VTp (13)
where
VCMP = Mean spill size corrected for line pipe
oMv,
= Total volume of spills corrected for line pipe
= Total frequency of spills corrected for line pipe
VTRp = Total annual volume of ruptures prevented after installa-
tion of leak detection and/or inspection tnethod(s)
aln the previous approaches for computing the reduction of the frequency and
mean volume of spills, methods were assumed to reduce only one part of the
risk.
302
-------
VTP = Total annual volume of spills prevented after installa-
tion of leak detection and/or inspection method(s)
V,... = Total annual volume of spills undetected after installa-
tion of leak detection and/or inspection method(s).
As an example, a method may have the following risk reduction factors:
RRFyR =0.5
RRFVL =1.0
RRFFR =0.5
RRFFL « 1.0.
Assuming VSMC = 1000 barrels/spill and F^JQ = 100 spills/year, then:
VSTC = 100° barrels/year x 100 spills/year = 100,000 barrels/year
VTD = 1000 barrels/year x 100 spills/year x (1 - 0.9 x 0.5 x 0.5
IK - 0.1 x 1 x 1) - 100,000 barrels/year (1 - 0.225 - 0.100)
= 67,500 barrels/year
V,.. = 100,000 barrels/year - 67,500 barrels/year = 32,500 barrels/
year.
7.2.2 Estimated Existing and Potential Reduction of Spillage for the
Reference Line
Accidental spillage (incidents and volume) from the reference line that
can be prevented (or go undetected) is estimated based on information pre-
sented in Section 7.2.1. Results for the selected methods are given in
Table 72. Estimates are included for leaks and ruptures. In order to pro-
vide a general comparison of the capabilities of the selected methods,
spillage that can be prevented (or go undetected) is indicated in percen-
tages rather than barrels spilled or number of incidents.
Only a few of the selected methods appear to have the potential of
substantially (33 percent or better) decreasing both the incidents and the
volume of accidental spillage. These include:
• Visual inspection of the line
daily by air or ground patrol
daily by ground patrol with hydrocarbon probe or
comparable device for indication of the spill
• Passive acoustic array
• Pressure difference
• Survey by inspection pig
303
-------
TABLE 72. ANALYSIS OF OIL SPILLED FROM THE REFERENCE LINE
THAT CAN BE PREVENTED OR GO UNDETECTED
Inspection and/or Leak Detection MetMds
SplUaoe
i
Inspection L!ikl
Frequency/ f'J>
rear .10.
1. Visual line inspection by air or ground 26 ! 0
patrol (required Inspections) far
indication of spill
2. Visual line inspection by air or general i. 26 (Ref) 22
patrol in excess of required inspection . .. ... ,.
for indications of a spill | "• 3M "
3. Visual inspection by ground patrol »itn ' a. 26 Oeq) 39
hydrocarbon probe or comparable device : K .. ..
for indication of spill (onland lines *• » •»
only c. 338 , 98
4. Hydrocarbon probe-towfish or similar
device
- Unaarwter lines only
- All lines
5. Pressure deviations
a. Puep stations (existing net nod)
b. Along, line
6. F1o» rate
a. Deviations
b. Comparisons (comouteritedl
7. volume comparisons (comterlteO
8. Matlosetlcel modeling (computerized)
9. negative pressure surge (computerized)
10. Passive acoustic array (computerized)
a. Retrofit
b. Hex line
11. External rods vith passive acoustic
sensors
12. Pressure static
13. Hydrostatic
6 «
6 ' S
continuous ! M
continuous 0
continuous j 0
continuous : 0
t
continuous 0
continuous 0
continuous 1 0
1
a. continuous 1 46
b. continuous ' 32
after indication 0
of spill1
after indication 0
of spill1 :
a. 1 85
b. 2 69
c. after indication 80
of spill' i
Prevented 1
Spills
Ruptures^ Total
.10. ' NO.
0 0
10 32
35 106
! 9 48
i 19 90
i 47 MS
1 7
1 I 7
M M
0 0
1
0 | 0
•oo
0 0
0 0
' o i o
1
25 I 71
: 42 i 124
o ! o
0 0
IS 80
It 88
i 22 102
t
volute
Leaks ;
''TU>
( bbls
Ruptures i Total
V : tf
*TRP *TP
K bbls i K bbls
0 0 ! 0
U 40 57
23 186 209
9 39 48
17 i 78 95
26 | 206 232
2
2
0
o
0
0
6
10
10
M
27
53
10S
183
23S
< 0 | 80
: 6
14
194
230
12
12
M
27
S3
10S
183
241
90
200
244
3 i 26 24
6 i 52
9
17
17
52
63
78
58
61
80
95
Undetected
Spills j Volume
Total Total
fu ''u
No. ic bbls
290 | 291
258 233
184 31
242 243
219 198
MS 58
I
22 j 17
283 \ 277
s
M i M
290 | 264
I
290 ! 237
290 | 185
290 ( 107
290 : SO
290 | 211
219 92
166 47
290 ! 262
290 : 233
I
210 ; 230
208 ! 211
188 | 196
[continued)
304
-------
TABLE 72 (continued)
Inspection and/or leak Detection Methods
Inspoctlon
Frtflotncy/
»oar
14. Pressure difference >. 1
; b. Z
[ C. 4
d. 12
Suilljoe
Spills
Ltaks
ri>
no.
93
108
148
152
RuOturtl
FRP
Ho.
20
23
26
29
15. ChMO* or add Inhibitors « needed :* 13 J
16. Inspection at sarnie of line for Mil 1 26 6
tftlckneu By ultriwnic or CMMrUlt
technique i
17. Surny by inspection p1a-Menet1c i. 0.25
flux typt or other comreble K „ „
device '• O'w
1 c. 1
18. Den* of covtr Inspection by sonar
(lidttcwi and penetrating) or otMr
coBOarablt oe«1ce
- UndOTMter 11iw> only 4
- All Unas 4
19. Charting of lino P1PO
- Underwater linn only 0.5
- All MUM O.S
20. ProMfttlM proerw for outside forcts
(•efefOMO 12) One-Call SystM , ""•
21, Pig KM for ottor rooval
22. Oil iplll aittcurs
- Mrino tomlnal or platform
- Totil Hit pipt mi lost
23. 10(0) and 13)«)
24. 17(e) Md 20
2S. ](»). 17(c) and 20
26. 10(b) and 17(c)
27. 5(6), 6(«) and 7
2S. S(a), <(t). 6(6). 7 and 9
29. a and 17(c)
J1
continuous
continuous
87
100
113
6
6
2
2
59.
13
19
22
24
4
4
0
0
29
3
0 0
0 0
174 (3
; 187 68
197 69
i 195 63
°
°
113
«
0
IS
Prawtttd
Total Latks
% "TIP
NO. K DblS
113 17
131 22
174 26
181 29
16 3
32 3
106 12
122 13
128 15
10 j 1
10 | 1
2 i 0.3
2 < 0.)
88 i 10
1
K , 3
0 1.4
0 1.4
237 26
253 26
266 28
258 29
0 0
o : o
128 i 17
| unditoctod
Volusc
Duptum
"TUP
K bbls
Total
"TP
K bbls
73 i 90
84 ; 106
93 ! 119
105 133
Spills
Total
:•.
177
159
116
109
VolUM
Total
vu
K Obi!
201
185
198
186
12 15 274 276
20
68
79
90
12
12
1.4
1.4
23 ' 258 268
80 184
92 168
105 : 162
13
13
1.7
1.7
10S 120
12 15
0
0
1.4
1.4
235 261
19
210
27
m
202
274
29
290
53
235 | 261 > 37
250 : 278 i 24
!
250
209
2*8
279
209
42
290
248 ! 2K
'• i
244 ! 261 i 1(2
211
199
196
16
278
27.3
2*0
170
276
27.4
290
30
30
13
12
82
43
30
(1) EstlMtod annual sg111a
-------
• Preventive program for outside forces
• Depth of cover by sonar or other comparable device .
Methods that have the potential of significantly (60 percent or better)
decreasing the spill volume include:
• Visual inspection of the line
daily by ground patrol with hydrocarbon probe or
comparable device
• Volume comparison
• Mathematical modeling
• Passive acoustic array.
Methods that have the potential of substantially (40 percent or better)
decreasing the incidents of spills include:
• Visual inspections of the line
daily by ground patrol with hydrocarbon probe or compara-
ble device
• Passive acoustic array
• Pressure difference
• Survey by inspection pig-magnetic flux type or other compara-
ble device.
Overall, mathematical modeling and passive acoustic array appear to be the
most promising for preventing the greatest volume of spillage; periodic sur-
veys by inspection pigs and the pressure difference method appear to be the
most promising for reducing the frequency of spills.
Most methods are highly effective in reducing either the frequency or
volume of spills, and in some instances are moderately effective in reduc-
ing both parts of the risk. Results indicate that the overall reduction of
both the frequency and volume of spills is never better than 50 percent for
any method. However, various combinations of as few as two methods result
in potential reductions of greater than 80 percent of both the frequency and
volume of spills; combinations of three methods or more can result in poten-
tial reductions of greater than 90 percent for both the frequency and volume
of spills.
7.2.3 Estimated Spillage and Prevention for All U.S. Lines
Total accidental spillage from U.S. lines that can be prevented or go
undetected is estimated based on information presented in Section 7.2.1.
Results for the selected methods are given in Table 73. Values are provided
aUnderwater lines only.
306
-------
TABLE 73. ANALYSIS OF OIL SPILLAGE THAT CAN BE PREVENTED OR GO UNDETECTED FOR ALL U.S. LINES
CO
o
o
o
3
n>
o.
Inspection and/or leak Detection Methods
1. Visual Inspection of line by air or
ground patrol (required Inspections)
2. Visual Inspection of line by air or
ground patrol In excess of required
Inspections
3. Visual inspection of line by ground
patrol with hydrocarbon probe or
comparable device for Indication of
spill
4. Hydrocarbon probc-tOHf Ish or similar
device
' Underwater I inns only
- All lines
5. Pressure deviations
a. Pump stations (existing method)
b. Along line
6. flow rate
a. Deviations
b. Comparisons (computerized)
7. Volume comparisons (computerized)
S. Mathematical modeling (computerized)
9. Negative pressure surge (computerized)
10. Passive acoustic array (computerized)
11. External rods with passive acoustic
sensors
12. Pressure static
)3. Hydrostatic
Inspections •
F i equency/
Vcar
26
Spillage
Prevented
Spills
Leaks
flP
I
0
a. 26(rcf) ' 10
b. 338 33
ji
». 26(reg) '
b. 26
c. 338
6 !
6
18
28
45
*
30
3
continuous • 0
continuous 0
continuous
continuous
continuous
continuous
continuous
a. continuous*
k- cent!n«Q«j'
after Indi-
cation of
spill*
after indi-
cation of
rupture*
« I
b. 2
c. after Indi-
cation of
rupture*
0
0
0
0
0
21
39
0
0
sr •
32
37
Ruptures
'HP
".
0
14
49
12
26
64
20
1
0
0
0
0
0
0
0
34
.58 __.
0
0
- ?o
24
30
total
fP
S
0
11
37
17
26
50
24
2.4
0
0
0
0
0
0
0
30
13
0
6
28
30
35
Volume
Leaks
y
0
3D
79
31
59
90
69
10
0
0
0
0
0
21
0
21
48
10
21
n
59
59
Ruptures
V1RP
0
18
71
15
3D
79
38
4
0
10
20
40
70
90
30
M
10
Total
y
0
20
72
16
33
Fd
41
4.1
0
9
18
36
63
83
27
70"
84
10
20 ( 20
I
20
24
30
21
27
33
Undetected
Spills 1 Volume
Total ! Total
1 u : vu
•.
100
89
63
83
72
to
76
98
100
100
100
100
100
100
100
"W
'57
100
ion
W~"
70
65
100
80
28
84
67
i'C
59
95
100
3?
81
64
37
17
73
XT '
16
90
W
»-
73
67
-------
TABLE 73 (continued)
CO
o
00
Inspection and/or leak Bisection Hulhods
14. fitiiiurt dlllcrcniB
IS. Change or *dd Inhllillnrs *s needed
16. Inspection of ta*ple ol Hue for mil
Ihlcknctl by ultrasonic or compartbU
technlaui
17. Survey by Inspection pl|-«uttnetlc flux
typt or oilier c»«|>arabl* devlct
II. Ueptb of cover Usueil Ion - Underwater
- All lines
19. Clurtlmol line pipe - Und«n«ttr
- All lints
20. freventlve program lor outside forcel
(lefcrenct 12) One -Oil iyslea
21. fig line for water rcwivtl
22. Oil spill detectors
- (Urine tei«ln
Leaks 1 Ruptures
»ar 1 '•w
i t
M
76
90
97
10
10
— «r
46
14
1
10
1
11
10
40
&
90
90
97
99
0
0
S9
It
12
»
40
S
76
u
10
. M
46
6
4.6
1
40
(
0
0
90
90
9S
9S
80
9S
91
loUl
t
11
16
41
46
S
a
12
16
U
4
4
1
19
&
6
0
90
90
96
96
72
as
90
undetected
•nii •«
Total
1
6t
SS
40
18
9«
89
(4
S6
66
97
94
99
70
94
100
100
IB
11
14
It
100
100
56
Tolil
»U
t
»
64
68
64
91.
9?
74
70
. M
Si
9t
9f
V'J
61
9S .
94
100
10
10
4 .
4
21
IS
10
^,
(I) Ammal tplllaye: lulal vulunc (¥,_,) • 1.1 barrels! Ruptures (0.90 »s|(.| • 1.17 barrels; leaks (O.I «s|[|
1.1 > 10 '( Ru|>lurct (0.2S f$|) • 0.12 » 10°; teaks (0.7S fil(.J
• 0.11 Until.
total spills (f,
• 0 Id » 10°.
(2| Retrofit Im
(I) Nm line In-.Ullillim.
(4) (requcncr ol lni|»!< I Ion It issiwiud
-------
for both the frequency (number of incidents) and volume (barrels of oil) of
spills that can be prevented (or go undetected). Estimates are included for
leaks and ruptures.
The relative effectiveness of the methods is, of course, similar to
results presented in the previous section for the reference line pipe.
Annual inspections of the line can be quite effective. For example, yearly
surveys by an inspection pig can potentially prevent 128 spills and elim-
inate 100,000 barrels spilled. On a comparative basis, this particular
inspection potentially could result in reducing the frequency and volume
of spills by a factor of at least three times better than cathodic protec-
tion systems. Use of more than one method can result in substantial reduc-
tions in the reported spill incidents and volume. For example, annual sur-
veys by inspection pigs and implementation of a mathematical modeling system
on the lines can potentially result in a reduction of 128 spills and pre-
vention of spillage of 244,000 barrels yearly. The dual prevention capabil-
ity is particularly desirable for use in older smaller diameter lines where
the incidents of spills are high, but spill volume relatively low. In cases
of large-diameter lines, where high throughput presents a continuing poten-
tial danger of a major spill, methods that are particularly effective in
reducing the volume of spills are highly desirable. For example, computer-
ized mathematical modeling or volume comparison methods are expected to
reduce the annual spill volume by 240,000 barrels and 185,000 barrels,
respectively.
7.3 COST ANALYSIS
Costs of inspections and spillage are extremely important in the de-
velopment of a practical spill prevention program. All significant costs
must be obtained to properly evaluate the cost and cost-effectiveness of
the various options (methods and schedules). When a number of options are
suitable for spill prevention and control, inspection costs would normally
be the most important factor in recommending a particular method. When high
spillage costs are expected, such as in high risk areas, additional inspec-
tions or methods may be justified. Costs for inspections and leak detec-
tion and spillage are discussed in the following subsection.
7.3.1 Inspection and Leak Detection Costs
Significant cost items for implementation of each inspection or leak
detection method are included in the estimate of the total inspection cost.
Costing includes such items as:
• Equipment
• Installation
• Interest
• Operation
• Maintenance
• Facility downtime
309
-------
• Training
• Inspection services.
Cost estimates, with a baseline year 1978, were made using data supplied by
inspection services, equipment manufacturers, operators, industry surveys,
trade journals and from a number of references in this study.
The reference line is assumed for estimating the costs of the various
inspection and leak detection methods. The assumptions for the reference
line are given in Tables 56 and 74. The reference line is assumed to con-
sist of 300 miles of on!and and 30 miles of underwater lines. Costs for
the reference line are multiplied by a factor of 676 (mileage of U.S. lines/
mileage of reference line) to obtain an estimate for all U.S. petroleum
pipelines. Typical costs of equipment and/or inspection services that are
assumed for the cost analysis are shown in Table 75.
Costs for methods requiring purchase of equipment and/or permanent or
semi-permanent installations were obtained by first estimating the equip-
ment costs. Added to this value was a 25 percent cost for installation.
Yearly maintenance and operational costs were assumed to be five percent
of the cost of equipment and installation. The equipment was assumed to
have a life of ten years with no salvage value. Total annual costs were
computed by amortizing the equipment and installation costs over a ten-
year period and then adding the maintenance and operational costs.
Estimates of the yearly costs3 (equipment, installation, maintenance,
operation, etc.) of the selected leak detection and inspection methods for
the reference line and all U.S. lines are presented in Table 76. These
estimates are presented on an annual basis and do not include interest and
inflationary costs"; this is done to help simplify the comparison of methods
that may not require equipment or installation, such as line walking, with
those methods that do, such as flow deviation monitoring. It is normally
assumed in the costing that implementation of the various methods can be
accomplished either by limited interference (retrofitting) or not inter-
ference with the line.
aCosting is developed at a level suitable for evaluation purposes of this
study only. Cost estimates are based on an assumed reference line. De-
tailed costing and optimum accounting for each method is beyond the scope
of this study. Costs for a specific line may vary considerably.
Interest and inflationary costs are not needed for the cost analysis.
Equipment costs (once purchased) are fixed and thus affected by inter-
est costs and not significantly affected by inflationary costs. Labor,
rentals, or inspection services are affected by inflationary costs but
not significantly affected by interest costs.
310
-------
TABLE 74. ASSUMPTIONS FOR REFERENCE LINE
Mileage:
On!and - total 300 miles
- crude gathering lines
- crude trunk!ines
- product trunk!ines
Marine Terminal:
Underwater - total 30 miles
- crude gathering lines 20 miles
- crude trunklines 10 miles
- product trunklines
Pump Station:
Number - 6
Spacing - 50 miles
Inlet and Outlet Meter:
Number - 3
Spacing - 100 miles
Corrosion Monitor:
Number - 30
Spacing - 10 miles
311
-------
TABLE 75. EQUIPMENT AND INSPECTION SERVICE COSTS FOR SELECTED
LEAK DETECTION AND INSPECTION METHODS
item No.
1
2
j
4
5
6
7
i
9
10
u
12
13
14
15
16
17
13
19
20
21
2:
23
24
25
26
27
23
29
Equipment or Inspection Service
Alp patrol line pipe inspection service
Ground patrol
Hydrocarbon probe or equivalent
Ground patrol with hydrocarbon probe or other comparable device
Hydrocarbon prooe (towfisn type) or otner camparaole device
- lease or rent system
• operator
Oil spill detector system
Line pressure meter
Telemetry for remote monitoring
Telephone lines for remote monitoring
Leak detection display, control and alarms for pressure monitoring
and/or flow monitoring
Flow meter system
Correction equipment for flow transients
Inlet and outlet meters modified for leak detection
Leak detection display, control and alarms - flow rate comparison
- master control room
Central minicomputer
Real-time pipeline model software
Negative pressure surge monitor
Acoustic detector (portable)
Acoustic analyzer and display
Acoustic detector and signal conditioning (permanently installed)
Acoustic transmission/receiver cabling - on land
- underwater
Acoustic master unit
Acoustic central minicomputer
Remotely controlled block valves witn pressure difference
transducers (includes valve, transducers, power,
telemetry units, connectors to telephone lines)
Laboratory equipment for analysis of fluid in line
Survey inspection pig-magnetic flux type or equivalent
-by inspection service
Depth of cover inspection of underwater lines by .inspection service
Sonar system (sidescan and penetrating) towfish type or other
comparable device
- lease or rental of equipment
- operator
Charting of underwater lines by inspection service
Estimated Cost
SO. SO / mile
$4.00 / mile
$2,000 / meter
$250 / day
$250 / day
$200 / day
$7,000 / unit
$2.000 / meter
S3, 000 / unit
$5,000 / station
$3,000 / pump station
$15,000 / pump station
$10,000 / pump station
$5,000 / meter
$5,000 / pump station
J10.000 /line
$100,000 / line
150,000 /line
$5.000 / unit
$500 / detector
$3,000 / unit
$200 / unit
$2.500 / mile
$10.000 / mile
$10.000 / station
$100,000 / line
$20,000 / valve
$2,000 / unit
$500 /mile
$300 / mile
S500 / day
$200 / day
$300 /mile
312
-------
TABLE 76. COST OF INSPECTION AND LEAK DETECTION METHODS
Inspection and/or Leak Detection Methods
I. Visual line inspection by air or
grouna patrol (Required inspections
for indication of spill )
2. visual line inspection by air or
general patrol in excess of re-
quited inspection for indications
of a spill
3. Visual inspection by ground patrol
»itn nydrocarbon prooe or compar-
able device for indication of spill
(on land lines only)
4. Hydrocarbon probe-towfish or sim-
ilar device
-Underwater lines only
5. Pressure deviations
a. Pump stations (existing method)
b. Along line
6. Flow rate
a. Deviations
b. Comparisons (computerized)
7. Volume comparisons (computerized)
o. Mathematical modeling (computerized)
9. Negative pressure surge (computerized)
10. Passive acoustic array (computerized)
a. Retrofit
b. New line
11. External rods with passive acoustic
sensors
12. Pressure static
13. Hydrostatic
INSPECTIONS
Frequency/
Year
26
a. 26 (Ref.)
b. 338
a. 26 (Reg.)
b. 26
c. 338
6
ANNUAL COSTS
Reference Line '
Per(1) Total
Mile
$ S K
All U.S. Lines
Total
S Million
14 4.8 3
!
14
187
110
4.8 3
62 i 42
33 22
220 66 i 44
1,420
1,200
429 | 286
36 24
continuous NA IJ'
continuous 85
continuous
continuous
continuous
continuous
continuous
continuous
continuous
after indica-,,,
tion of spillu'
after indica-.,.
tion of spill^'
i
a. 1
b. 2
s- after indica-,,,
I tion of spilT^'
28 19
68
185
185
212
159
23
61
61
70
52
210 70
954
59
9
36
315
18
3
12
72 24
15
41
41
47
35
46
210
12
2
8
16
• !
36 12
8
313
(continued)
-------
TABLE 76 (continued)
Inspection and/or Leak detection Methods
14.
15.
16.
17.
18.
19.
20.
21.
22.
n.
24.
25.
26.
27.
28.
29.
Pressure difference
Change or dad inhibitors is needed
Inspection of sample of line for wall
thickness by ultrasonic or comparable
technique.
Survey by inspection pig-magnetic flux
type or other comparable device
Depth of cover inspection by sonar
(sidescan and penetrating) or other
comparable device
-Underwater lines only
Charting of line pipe
-Underwater lines only
Preventive program for outside forces
(Reference 12) One-Call System
Pig line for water removal (low
elevation only)
Oil spill detectors
-Marine terminal or platform
-Total line pipe mileage
INSPECTIONS
Frequency/
Year
a. 1
b. 2
C. 4
d. 12
jlZ)
1
a. 0.25
b. 0.50
c. 1
4
O.S
Cont.
3<2>
continuous
continuous
10 (b) and 13 (a)
17 (a) and 20
3 (a), 17 (c) and 20
10 (o) and 17 (c)
5 (b). 6 (a). 7
5 (a). 6 (a). 6 (b), 7 and 9
3 and 17 (c)
ANNUAL COSTS
Reference Line
Per'1' Total
Mile
5 S K
290
327
400
690
4
87
125
250
500
1,200
150
45
15
16
16
1,000
1,080
303
454
712
96
108
132
228
1.2
26
42
83
165
36
4.5
15
5
5.2
5.2
327
357
100
150
235
All U.S. Lines
Total
S Million
64
72
38
152
0.8
18
28
56
111
24
3
10
3
3.5
3.5
218
238
67
100
156
NOTE: (1) Cost per mile for single inspection can be computed by dividing the cost by number of inspections/year
(2) Frequency of inspection is assumed at three per year
(3) NA - Not applicable since method is commonly used
314
-------
Typical construction costs per mile for offshore pipeline are shown in
Table 77 for various diameters. This information is useful in comparing
the cost of the pipeline and the cost of spill prevention.
Pertinent items assumed for the selected methods are provided in the
subsections that follow.
7.3.1.1 Cost of Selected Visual and Visual-Aided Line Inspections--
Visual inspections of the line pipe are normally carried out in the
U.S. by air patrol inspection services. Cost estimates are based on in-
spections by air patrol services with some adjustments for the limited use
of ground patrol by the pipeline company personnel. Air patrol inspections
services3 are estimated at 50 cents per mile for each inspection. Ground
patrol inspections are estimated at four dollars per mile. Inspections
carried out every two weeks are estimated to cost approximately 3.2 million
dollars each year for all U.S. lines.
Ground patrol inspections with a hydrocarbon probe or other comparable
devices are estimated at 4.2 dollars per mile for each inspection. Inspec-
tions carried out every two weeks are estimated to cost approximately 22
million dollars each year for all onland U.S. lines.
Inspections of underwater lines using a hydrocarbon towfish or other
comparable devices are expected to cost approximately 200 dollars per mile
for each inspection. These inspections are normally performed by inspec-
tion services that provide both the equipment and the operator. A boar
(with a winch) and support crew are also required. Inspections carried
out every two months are estimated to cost approximately 36,000 dollars
for the reference line and 24 million dollars each year for all underwater
U.S. lines.
7.3.1.2 Cost of Selected Method for Oil Spill Detectors on or Near~"the
Water—
The method employing oil spill detectors at marine terminals and off-
shore platforms would typically require about four detectors at each loca-
tion. Annual costs are estimated at 5,200 dollars for the reference line
and 3.5 million dollars for all U.S. lines.
aCost of electronic monitoring by air patrol of the corrosion monitors
installed on the line, typically spaced at 5 to 15 miles, are not in-
cluded. However, this service is estimated at 50 cents per mile as-
suming bi-weekly inspections. Typically, the monthly charge for each
monitor is about ten dollars.
315
-------
TABLE 77. OFFSHORE PIPELINE CONSTRUCTION COSTS
(a)
Diameter
(inch)
6
8
10
12
14
16
18
20
22
24
26
28
30
32
36
40
42
44
48
Cost
Installation
$K/mile
250
262
278
300
325
350
385
420
465.
510
576
642
720
810
1,010
1,290
1,440
1,660
2,210
Yearly(b)
$K/mile
5.0
5.24
5.56
6.0
6.5
7.0
7.7
8.4
9.3
10.2
11.5
12.8
14.4
16.2
20.2
25.8
28.8
33.2
44.2
aSource: CEQ 1974, Inflated 31 percent (Ocean Industry pipeline
inflation factor) to convert 1972 dollars to 1975 dollars.
Assumes 50-year life with no salvage value.
316
-------
7.3.1.3 Cost of Selected Methods for Continuous Monitoring of Internal
Fluid Variations During Transfer—
The method employing continuous monitoring of pressure deviations
along the line is assumed to include the existing pressure monitoring sys-
tems at each pump station and new installations at two locations (approxi-
mately 16 miles apart) between each pump station. Twelve of these sta-
tions would typically be installed on the reference line. Other equipment
includes telemetry and telephone lines at remote monitoring stations and
leak detection displays, controls and alarms at each pump station. Annual
costs are estimated at 28,000 dollars for the reference line and 19 million
dollars for all U.S. lines.
The computerized flow rate comparison method requires the installa-
tion of flow meters at each pump station and modification (for leak detec-
tion) of inlet and outlet meters typically at three locations. Other
equipment includes electronics that connect flow meter to telephone lines,
leak detection monitoring units with control and alarms and correction
equipment for flow transients at each pump station, and a central mini-
computer at the main control room. Annual costs are estimated at 61,000
dollars for the reference line and 41 million dollars for all U.S. lines.
Costs for implementing the computerized volume comparison method are
about the same as for the flow comparison method. Similar equipment is
required.
The mathematical modeling method requires equipment similar to the
volume comparison method. However, some additional equipment is required
for implementing the real-time pipeline model. Typically, the equipment
is implemented in the central computer as a software implemented system.
Annual costs are estimated at 70,000 dollars for the reference line and
47 million dollars for all U.S. lines.
Implementation of the negative pressure surge method primarily re-
quires installation of pressure surge monitoring stations at the pump sta-
tions and at various locations, typically at two stations approximately
16 miles apart, between each pump station. A total of 18 stations typi-
cally would be required. Other equipment includes telemetry and telephone
lines for remote monitoring and a central minicomputer at the central con-
trol room. Annual costs are estimated at 50,500 dollars for the reference
line or 35 million dollars for all U.S. lines.
7.3.1.4 Cost of Selected Methods for Detection and Location of Spills
on or at a Short Distance from the Line Pipe—
The major installation required for the method employing external rods
with passive acoustic sensor are the metal rods permanently attached (by
brazing) to the lines. The rods are typically spaced approximately one-
quarter mile apart. Portable acoustic sensors with associated analyzing
equipment normally would be stored at each pump station. Annual costs are
estimated at 17,600 dollars for the reference line and 12 million dollars
for all U.S. lines. This estimate does not include installation on under-
water lines.
317
-------
Two cost values are provided for the passive acoustic array inspection.
One cost is based on a typical system for retrofit installations. The
second cost is based on a typical system for new lines. A system retrofit-
ted to the line is expected to be capable primarily of preventing damage by
outside forces and detecting ruptures, while a system for a new line is
expected to be capable of preventing most failures and detecting most leaks.
Costs for this latter system are expected to be too high for most existing
lines because of the large number of sensors and associated equipment and
the high expense to uncover the line for equipment installation. However,
this system should be considered for short sections of lines in high risk
areas, i.e., underwater.
For retrofitting on existing lines, the passive acoustic array method
is expected to require installation of acoustic transducers at the pump sta-
tion and at various locations, typically at four stations (approximately
ten miles apart), between each pump station. Other equipment includes sig-
nal conditioning, signal processing, and telemetry and telephone lines for
remote monitoring. Annual costs are estimated at 69,600 dollars or 46 mil-
lion dollars for all U.S. lines.
For installation on new lines, acoustic sensors with signal condition-
ing and signal processing equipment are expected to be installed at approxi-
mately five locations each mile. Typically, a multiconductor cable running
the length of the line would provide both power and transmission of the sig-
nal from each acoustic sensor. (Numerous other means, such as telemetry
data link, might also be used for transmission of the acoustic signal from
line pipe to the control room.) Master units supply the power, signal pro-
cessing and control. These units would be located at each pump station and
at two locations between each pump station. • Annual costs for a new line
are estimated at 315,000 dollars or 210 million dollars for all U.S. lines.
7.3.1.5 Cost of Selected Methods for Periodic Pressure Tests-
Pressure static tests are expected to be of low cost. For a typical
test, the line would be held at normal line pressure for a short time interval
(less than one hour). Normally long sections of the line would be tested
separately and a few hours would be required for a complete test. It is
assumed that mainline valves would require manual closure. Yearly costs2,
assuming tests are carried out three times, are expected to be about 3,000
dollars for the reference line and 2 million dollars for all U.S. lines.
Hydrostatic tests are based on test section spacings of about 16 miles
and hold times of about 24 hours. Annual inspections are estimated to cost3
approximately 12,000 dollars for the reference line and 8 million dollars for
all U.S. lines. Hydrostatic tests carried out only after an indication of a '
leak are expected to be about the same cost. For this latter test scheme,
only a limited number of line sections would be tested. Inspections are
expected to be carried out about three times a year.
\ine downtime and leak location costs are not included in the estimate
for this inspection.
318
-------
7.3.1.6 Costs of Selected Corrosion Inspection Methods-
Inspections forMnternal pipeline corrosion through laboratory analysis
of fluid transported could be carried out by either operating company per-
sonnel or outside inspection services. Equipment for analysis of the fluid
can be either purchased or leased. Costs are based on the assumptions that
the inspection is done by an outside service three times a year. Annual
costs are estimated at 1200 dollars for the reference line and 800,000 dol-
lars for all U.S. lines.
7.3.1.7 Costs of Selected Standard Non-Destructive Testing Methods-
Inspections of sample sections of the line for wall thickness changes
by ultrasonic or comparable techniques are assumed to be carried out by an
inspection service. The cost estimate is based on inspection of small
areas of the line pipe at a spacing of approximately two miles. Annual
costs are estimated at 26,000 dollars for the reference line and 17.6 mil-
lion dollars for all U.S. lines.
7.3.1.8 Cost for Selected Inspection Pigs-
Inspection of the line using inspection pigs (magnetic flux type or
other comparable devices) are normally carried out by inspection services.
Costs are estimated at 500 dollars per mile per inspection. Annual costs
are estimated at 165,000 dollars for the reference line and 111 million
dollars for all U.S. lines.
7.3.1.9 Cost of Selected Methods for Line Pipe Charting and Depth of
Cover-
Inspections of the depth of cover of underwater lines using a sonar
(sidescan and penetrating) towfish or other comparable device would typi-
cally be carried out by inspection services that provide equipment and an
equipment operator. A boat (with winch) and a support crew are also re-
quired. These inspections are expected to cost approximately 300 dollars
per mile for each inspection. Inspections carried out every three months
are estimated to cost 36,000 dollars for the reference line and 24 million
dollars each year for all underwater lines in the U.S.
Charting the location of underwater lines is normally carried out by
inspection services. A diver, support crew and a boat are the major cost
items. Inspection costs are estimated at 300 dollars per mile. Annual
costs are estimated at 4,500 dollars for the reference line and 3 million
dollars for all underwater lines in the U.S.
aUnderwater lines are not included in this cost estimate.
319
-------
7.3.2 Spillage Costs
Spillage costs in the study are separated into the following three major
categories:
* Petroleum spilled from line pipe
• Spill cleanup (function of the location and means of
spill cleanup)
• External damage (function of the severity or risks
external to the line).
Separation into these three cost categories is particularly advantageous for
both the cost-effectiveness analysis carried out in Section. 7.4 and the se-
lection of methods for lines located in high risk areas. Spillage cost for
each category will be discussed in the subsections that follow.
7.3.2.1 Petroleum Spilled—
The cost (value) of petroleum spilled from line pipe is difficult to
estimate because of the wide range of petroleum prices that exist for crude
(imported, new production wells, old production wells, etc.) and product
(various types). To avoid this problem, the costs of petroleum spilled are
evaluated based on the quantity (in barrels) rather than the actual cost
(dollars). Conversion from barrels lost to dollar values can be made di-
rectly for any specific line or nationwide based on average petroleum costs.
7.3.2.2 Spill Cleanup—Cost Factor (Function of the Location and Means of
Spill Cleanup) —
Spillage costs for spill cleanup vary widely. However, these costs
generally depend on the location and means of cleanup of the spill. For
example, a spill located in a remote area at large distances from roads
would be very costly to clean up using typical oil recovery methods, but
the cost of burning the lost oil would be much lower. In this study, stan-
dard oil recovery methods will be assumed.
Values for the cost factors SCF$C that account for the location and
means of spill cleanup are provided in Table 78. These factors are quali-
tative estimates based upon information obtained from companies carrying out
spill cleanup, from a typical operating company and information available in
the literature. It should be noted that these cost factors can vary widely
depending upon company practices or local regulations for a particular line.
For example, if spilled petroleum were burned on!and costs of cleanup would
be minimal.
7.3.2.3 External Damage—Cost Factor (Function of Severity or Risks Ex-
ternal to the Line)--
Spillage costs, for damage external to the line from a spill also vary
widely. However, these costs generally depend upon the risks that exist
external to the line.
320
-------
TABLE 78. SPILL CLEANUP COST FACTORS AS A FUNCTION
OF THE LOCATION OF SPILL
Location Cost Factors SCFSC
Onland
Easy access 1
Moderate access 2
Difficult access 5
Underwater
Confined area 50
Offshore 100
321
-------
Values for the cost factor SCFgo that account for severity of the spill
or risks external to the line can be obtained from Table 58. This cost fac-
tor is assumed to be identical to the overall risk correction factor
presented in Section 7.3.3.4.
7.4 COST-EFFECTIVENESS ANALYSIS
An analysis of the cost-effectiveness of the selected inspection and
leak detection methods for various inspection schedules is carried out in
this section. The analysis accounts for both effectiveness (the capability
of methods to reduce the incidents and volume of spillage) and the costs
(inspection methods and spillage). The cost-effectiveness of the various
options is the most important consideration in the development of a practi-
cal spill prevention and control program for line pipe. The need for eval-
uation based on cost-effectiveness arises because of the variety and number
of options at various costs that are available for reducing the risks of
oil escaping from the line.
A general measure of cost-effectiveness C£QM based on the ratio of the
reduction of barrels of oil spilled to the inspection costs is presented in
Section 7.4.1. This measure applies to most lines. Values are computed
for the selected methods and results discussed.
A second or specialized measure of cost-effectiveness CE$M is presented
in Section 7.4.2. It accounts for spillage from lines located in areas
where the potential exists for high spillage cleanup costs and/or high spill
risks external to the line. This measure should be used for individual
lines where special spill prevention and control may be needed because of
the potential of serious and/or costly spillage.
7.4.1 General Measure of Cost-Effectiveness
The general measure of cost-effectiveness CEQM accounts for the volume
or incidents of spillage (barrels) and inspection costs. It is defined as:
For Volume Spilled
rp _ spillage (barrels of oil prevented)
GM ~ inspection costs
or
For Incidents
PP _ spillage (number of incidents prevented)
GM ~ inspection costs
Values for the selected methods are given in Table 79.
Two main reasons for using the general measure of cost-effectiveness
are:
322
-------
TABLE 79. COST-EFFECTIVENESS ANALYSIS FOR ALL U.S. LINES
Insptctton "id/or LMt IKUctlM NttMOS
1. Visull lint insptction by «1r or
grmia p«roJ (Rwuirtd fnsptcttons
for IMIutton of spill)
2. VtiiMl HIM Inspection by . 1
b. 2
c.
-------
TABLE 79 (continued)
[nsptetlon ind/or Luk Otttctlon Htuiods
14. Prtssurt dfffirtnct
IS. Cktnat or idd initiators a nttdtd
16. Insotctlon of stcplt of lint for Mil
talckntss by ultrasonic or comnolt
ucMlqut.
17. Sunny by Insptctlon plg-Montttc flu
tyet or otlwr cotptnolt dnict
1». Otpta of covtr inspection by sontr
(sldtfcn ind ptnttritinq) or otMr
coipirult dtvlct
-UMtnwttr lints only
-All HIM
19. ChMtlno. of lint plpt
-Unatnnttr 11nt< only
-All lints
20. Prntntlw pratrM for outltdt fonts
(Ktftrtnct 12) Ont-Ctll Systn
21. fit, lint for
1
I. 0.2S
b. 0.50
C. 1
4
4
0.5
O.S
cant.
3'"
continuous
continuous
I
IMUAL COSTS
U.S. Lints
rotil
S Million
S4
72
33
152
0.8
SPILLAGE PREVENTED COST -FflCTIVENESS
Inc1 dints
Itductd
Ha.
113
131
174
181
16
18
28
56
111
24
24
3
3
10
3
3.5
3.5
218
238
67
too
156
32
106
122
128
10
10
2
2
88
16
0
0
237
253
266
258
0
0
128
oluot
Sivtd
bbls
90
106
119
133
15
23
80
92
105
13
13
1.7
1.7
120
15
1.4
1.4
261
261
278
279
209
248
261
nc1 dtnts
»^«" ,
no.
TIT
1.3
1.3
2.0
1.2
20
1.8
3.8
2.2
1.15
4.2
4.2
0.7
0.7
8.8
5.3
0
0
1.1
olum
JVtd
cost
1.4
1.5
1.3
0.9
19.8
12.8
2.9
1.6
0.9
0.5
0.5
0.7
0.7
12
3
0.4
0.4
1.2
,
1.1 : 1.2
0 3.1
0 2.4
3.3 I 1.7
55:
(1) W - Mt 4pp!1cibtt ilnct «ttnod
-------
• Can be applied to most lines
• Independent of line location, i.e., depends only upon the
volume of petroleum escaping from the line.
This measure is particularly useful in the consideration of guidelines
or recommendations for a general spill prevention and control program that
might be developed for a typical line by the operating company or for most
U.S. lines by a nationwide program.
7.4.2 Special Measure of Cost-Effectiveness
High spillage costs are possible in certain locations where high spill
cleanup costs are expected or in areas where high oil spill risks to the en-
vironment exist external to the lines. These two sources of spillage costs3
are not directly accounted for in the general measure of cost-effectiveness.
In order to account for both of these spillage costs, a second or special
measure of cost-effectiveness CF$M is provided. It is defined as:
and
CESM = CEGM x SCF
SCF = SCF$C x SCFED
where
CE_M = special measure of cost-effectiveness
CEGM = general measure of cost-effectiveness
SCF = spillage cost factor
SCFSC = spillage cost factor for spill cleanup as function of
the location of spill (see Section 7.3.2)
SCFrn = CFPn = spillage cost factor for risks external to the
LU tu line (see Section 7.3.3).
Spillage costs due to risks of the external environment are accounted for
when the risk correction factor CF£0 for risks external to the line is
used in estimating the oil spill risk of a particular line or group of
1i nes.
If the.risk correction factor CF£D was used in estimating the oil spill
risk the spillage cost factor SCF£D for risks external to the line is
given a value of 1.
325
-------
The special measure of cost-effectiveness requires only the inclusion of the
spillage cost factor. Thus, the relative cost-effectiveness of the avail-
able options (see Section 7.3.1), based on the general measure of cost-
effectiveness, does not change.
As the costs of spillage increases, the cost-effectiveness3 of the
various options becomes greater. For example, if a line were located off-
shore the cost-effectiveness of each method would be substantially greater
than for a typical onland line. This obvious improvement in the cost-
effectiveness is indicated in the special measure of cost-effectiveness.
Improvement in cost-effectiveness often allows the user greater range of
selection, from a cost basis, of the various available options.
The special measure of cost-effectiveness should be considered in the
development of spill prevention and control programs for lines located in
areas where the following spillage problems exist:
• Potential of serious spill problems or high risks external
to the line pipe exists, i.e., the risk correction factor
C^rn is greater than 3.
• Spill cleanup costs are expected to be high, i.e., the cost
correction factor is greater than 3.
When the potential of these spillage problems exists, a more effective spill
prevention and control program is often needed. This might require more
effective methods (greater spill reduction capability) and/or more frequent
inspections.
aFor many lines, the additional costs of spillage may be so high that an
adequate spill prevention program may, in fact, result over the long-
term in substantial cost savings and other benefits.
326
-------
SECTION 8
RECOMMENDATIONS
8.1 DISCUSSION
Results of this study show that the potential exists for serious spills
from the line pipe of petroleum pipeline systems and that various options,
inspection and leak detection methods and schedules, are available to sig-
nificantly reduce the oil spill risk. Based on the results of this inves-
tigation, preventive maintenance programs for line pipe are recommended.
These recommendations are based primarily on qualitative3 estimates of the
oil spill risks that exist and the capabilities of various methods to reduce
the risks. However, recommendations are also based on practical considera-
tions such as costs of inspections and spillage.
Recommendations are primarily intended to aid the user both in evaluat-
ing the need for, and actually developing, a spill prevention and control
program for his own line pipe. The recommended programs are expected to
significantly improve the prevention and control of accidental spills of
petroleum from operational lines. The programs include scheduled inspec-
tions and/or in situ leak detection (some functioning continuously) that
could be effectively developed and implemented. Overall, the programs pro-
vide means of estimating the risks of spills from line pipe and the poten-
tial for preventive maintenance.
It should be noted that the statutory requirements and voluntary pre-
ventive maintenance programs by operating companies have already resulted in
a good safety record for line pipe. In many cases, voluntary individual
programs, such as implemented on many large-diameter lines or underwater
lines, exceed statutory requirements. Voluntary programs have helped to
significantly reduce the spill risk of these individual lines and also have
contributed to the good safety record nationwide. Despite these efforts,
spills that are costly, hazardous, or could result in a major pollution
The intent in this study is to provide the necessary background information
and approach so that recommendations are developed from a purely qualita-
tive basis. This is in contrast to most spill prevention plans that are
developed based on educated guesses using inadequate and possibly incorrect
information derived partly from the literature, manufacturers, experience,
hearsay, and quantitative estimates.
327
-------
incident can and do occur. The risk of such serious spills is particularly
high for certain lines or lines in certain areas. Results of this study
indicate that means are available to reduce the possibility of these serious
accidental spills and improve the safety record nationwide.
Since there are many variations between lines and wide ranges in the
oil spill risk, it is beyond the scope of this study to recommend programs
for particular lines. Hence, recommendations are generalized and do not
include specific details for implementing methods for particular lines.
However, recommended programs are developed that apply to typical lines.
Also, sufficient information is provided (see Sections 6 and 7) so that a
user may develop a program for his own line.
In order to evaluate the potential of spill prevention programs for
pipelines, spill records, the oil spill risks from petroleum pipeline sys-
tem preventive maintenance programs (statutory, required, voluntary),
and the risk reduction capabilities of the various available options (in-
spection and leak detection methods) were investigated. Costs of inspec-
tions and spillage were also studied. Since inadequate quantitative infor-
mation of the development of spill prevention programs was available for
many of the areas investigated, qualitative estimates3 were made to account
for these deficiencies. Then measures were developed for evaluating line
pipe oil spill risk (frequency and volume of spills), capabilities of meth-
ods to reduce the frequency and volume of spills (effectiveness), costs of
inspections and spillage, and cost-effectiveness. Values for these measures
were estimated. Finally, the recommended maintenance programs (Section 8.2)
were developed based primarily on analysis of the results of these measures.
The cost-effectiveness of the various available options (inspections and
leak detection methods and schedules), however, was the most important
consideration in the recommendations.
Benefits of a preventive maintenance program are discussed in Section
8.2. Although no inspectton or leak detection method can be justified
purely on the cost savings resulting from the value of oil that would be
saved, other factors that might justify preventive maintenance are pre-
sented.
A recommended preventive maintenance program for the line pipe of op-
erational line is presented in Section 8.3. Implementation of such a pro-
gram is expected to decrease substantially the total quantity of petroleum
lost, the number of spill incidents and the number of major spill incidents.
A recommended approach for the development of a spill prevention program
for individual lines is presented in Section 8.3.1. A general spill pre-
vention program is presented in Section 8.3.2 that produces the confidence
that lines will have no more than (X) barrels spilled and (X) number of in-
cidents per year. The program consists of a series of recommendations of
aAn in-depth analysis of these areas for the purpose of obtaining highly
accurate estimates is beyond the scope of this study.
328
-------
scheduled inspections and/or in situ leak detection. Finally, recommenda-
tions of a specific scheduled preventive maintenance program for all U.S.
lines and for special lines (lines with a serious potential that petroleum
will escape or those located in high risk areas) are presented in Section
8.3.3. Recommended developmental inspection and lead detection methods
are discussed in Section 8.4.
8.2 BENEFITS
No inspection or leak detection methods can be justified purely on the
cost savings resulting from the value (dollars) of the petroleum saved.
However, when other benefits are considered, preventive maintenance is often
justified. Overall, damage from spills is becoming more costly and the
benefits of spill prevention are evident.
Reduction of spillage costs (i.e., spill cleanup and external damage
(see Section 7.3)) is a major consideration in justification of preventive
maintenance. This is particularly true of lines located in high risk areas
(see Section 7.4) or lines that have a high risk that petroleum will escape
(i.e., large diameter lines, old lines, etc.). For many of these lines, the
additional costs of spillage may be so high that effective preventive main-
tenance programs may, in fact, result in substantial cost savings over the
long-term.
Benefits such as reduction of risks to personnel or others, reduction
of line shutdown, improved public relations, and the saving of the important
and valuable petroleum resources, further justify preventive maintenance.
Additionally, another important benefit is the reduction of the various
socio-economic-legal aspects of spills. For example, in evaluating real or
personal property of damage from a spill83, items such as diminished value,
temporary non-use, profit and loss, loss of taxes, penalties, etc., are
considered.
8.3 RECOMMENDED PREVENTIVE MAINTENANCE PROGRAM
8.3.1 Individual Lines
The recommended approach for developing a spill prevention program for
an individual or group of lines is based on the following steps:
• Estimate the risk that oil will escape from a line (see
Section 6.3.4.1)
• Identify locations of a line where a spill may create
special serious problems (see Sections 6.3.3.4 and 6.7.2)
such as the possible damage to the external environment
or the cost of spill cleanup.
• Estimate the level of corrective action to reduce the spill
risk to an acceptable level.
329
-------
• Identify the various options of a spill prevention program
that are available to achieve the necessary reductions in the
spill risk (see Sections 8.3.2.2 and 7.1.2).
• Select the optimum methods based on the cost-effectiveness
and other considerations of the various suitable options.
8.3.2 General Schedule
The general schedule produces confidence that an individual line or
group of lines will have no more than (X) barrels spilled and (X) number of
incidents per year. The recommended approach is to first estimate the risk
that oil will escape from the line (see Section 6.3.1.1). Then select one
of the specific preventive maintenance schedules:
• Reduction of frequency of spills - Table 80
• Reduction of volume of spills - Table 81
• Reduction of frequency and volume of spills - Table 82.
Using the indicated approach and schedules, selectable spilling reductions
of greater than 25 percent, 50 percent and 75 percent may be achieved.
8.3.3 Specific Schedule
8.3.3.1 Most U.S. Lines-
Recommendations for typical U.S. lines include:
• Visual inspections of the line by air or ground patrol -
weekly
• One-Call System (Reference 12)
• Survey by inspection pig (magnetic flux type or other
comparable device - every four years
or
• Hydrostatic tests
yearly, or
after indication of spill.
Increasing the frequency of visual inspections of the line by air or
ground patrol from bi-weekly to weekly is expected to result in annual sav-
ings of approximately 57,000 barrels of petroleum (20 percent of total) and
decrease in number of incidents by 32 (11 percent of tota.l). These reduc-
tions are expected to be achieved at a nominal cost of about 3 million dol-
lars. These inspections are the most cost-effective (19 bbls/$K) of any of
the selected methods. Assuming the average cost of petroleum (crudes and
products) at 25 dollars per barrel, cost savings of the value of petroleum
alone almost justifies these recommended inspections.
330
-------
TABLE 80. PREVENTIVE MAINTENANCE SCHEDULES FOR THE REDUCTION OF THE
FREQUENCY OF ACCIDENTAL SPILLS FROM LINE PIPE
Inspection ino/or ^tu »tttction "ttftoai
J*lL4l lint insetctlon Sy lir or ground
iitrol >n ticni of rtouirto 'nspKtions
/iiuil insatctim or ;round Html »iui
lyoncjraoii 9nM or joapjrieit 4tvtct
for inoiutlon of tpill (onlim Itnti
4yareciroan pra&**to«fiui or si»11«r
OKICt-JlOtrMUr Him only
Pxstn icaustlc imy iceouttriita)
i. JttrgfU
a. tta lint
4yerefUCic
Uun?t or ted timipiton u ntMM
In«ptctio255 ScntOult' ; >SOS SOlMult' >75S SclWdull'
A S t 0 E f 5' «' 4 i C D i1 A 3 C D1 £' f
XXX XXX IX
x !
X X
X X XXX
X XX
X X
I X X
i
i
x xx
.< X
x x xxx
J
X X
X I X I X , X X X
i
'
Wut:
!. ?ction4l scntaults co tcconoHin inaluttd otrcmt rtductlon of frtqutney of soills art idtntifftd in columt !A, 3. C.... tec.) &tlon.
I. :rtau«ncy of intotctisn *i tisurao it turn cim Mr yttr.
3. :no*n«ttr 1 (net only. na
-------
TABLE 81. PREVENTIVE MAINTENANCE SCHEDULES FOR THE REDUCTION OF THE
VOLUME OF ACCIDENTAL SPILLS FROM LINE PIPE
3*pct/it iMuc:ioA of voliot af Saflls
>2£i Scntcuie1
>5QS Scntfluli1
>?55 Scitcult*
1 3 - 3 = f : i 1 J' <' ' ; j 5 2 r : S'H'IM* i C 3 • ;'S'
v/crzcir«cn :roo« or csssiracl* civict :,
*sr ^;icjt:cn jr seili (ontind Itnts
anl,, . -. 133
-/srtcarccn sract-ccwf^sft 3r similar i
^ivut-vnctrMur hn«s snly
i. :--: sutions :.uitcin; -ttro;) , ^ntinuous
3. 4;acq : tot : continuous
:. l^c=»imons xC3rou: i. 0.25
-./;* sr 3C.-.tr cs=Cirw!« avict , , JG
. c. 1
r"lisar:Kr:w«rM-';;;:r"t«r
< (
i
X
1 ' x
X ; X
I
X X
j
1
X ' XX
X XX
i
X
X X
X
X
I
X X
:.nrvrj :r 1 ,„ ,:»--«•«*:» linti ! :.=
•-9v«rt:«« creqrsn for 3u£Slct forexs j continuous
= i{ -,!-.« '5f«:tr -MM! ' 2'
;il ioitl Kttctsrs^*iriit timinal , *tc. • cofttlnuous
j
< < < t 1 < x x x
1
1
1
rious ;a tccaireiitn inaiciud otrctnt 'tgucc:cn er
3^ intMc;1on is ittunM i: :nr»t :imts aer /«*c.
* lints only. ^OM*v«r, otntr tcnrruict s.iown n«y lisa
IUM af JBills «r« iatntH1« in cotuwt i.4. 3. C,...*tc.l Mlcw.
332
-------
TABLE 82. PREVENTIVE MAINTENANCE SCHEDULES FOR THE REDUCTION OF THE
FREQUENCY AND VOLUME OF ACCIDENTAL SPILLS FROM LINE PIPE
Inunction mayor Ltik ClCKtion Kttmes
pit ml in ucus of rtquirto inSMetlMK
visutl insstction ay ground sjtrol men
lyoroctroon orooo or ca*io«rtelt otvict
for ineiutlon of loll! (cnlwd linn
only)
Hyaroctroofl aroo«*cowfisn or siniltr
Stvict-Unotmtttr linn only
'rtsmrt anittians
*. Pu»o sutiMs (taistine. attnoa)
3. Alone, line
Ho* rltt
«. 3un turf* (EgrmiurttMl
?>s>i« iC3ultlc irriy (cn«»uttrut«l
i. Ditrafic
a. M>t lint
£ittn*l rgcs •ttn MUlvt tcouidc
Pntsun suite
«y«nml« of MM for »«U
cnteuins ay uitriMnle gr caiMriolt
ciemiout
Sarv«r Oy inioKtton gionMgiwcic 'lux
;yst or atntr comotraolo oovlct
>otn of cour insMCtior sy ion«r
l>19Ueu> >na otnttrttin?) or otMr
smtrtolc jnici-unainMur Un$ only
Durtfn; of I in* piw-unotnaur linn
?rt»«ntivt orognm for oyuia fsreis
Uifiraftci 12} Ono*CiU Sysun
?1j Itm for Mtir rMMl
311 tpill aitKUrs-idrtM ttrmntl , «tc.
Insottf.on
fur
>. 338
1. 26
3. 52
c. 333
6
continuous
continuous
continuous
continuous
continuous
continuous
continuous
continuous
continuous
•fttr inaic**
cion af set 11'
iftor indict-
don of spill'
s. 1
a. 2
c. tfttr i nota-
tion it spill1
i. 1
D. 2
C. 4
d. 12
31
i. C.2S
s. 0.50
C. *
«
3.5
continuous
3'
continuous
Ptrctnt aMuctlM of ValuM of Soilli
>2S: Scntdult' ><0t SOM«ilt'
A t : B £ f 5' H' ! » s : g E s1 n'
I I X I
.<
f
' i «
i
X j XX
,
• x
; * *
I
1 i "
1
1
!
i
i
X 1
i
1
:
1
X , I X X
:
x ; xx
>75«
Scntault'
* B C
XXX
X X
I
X
x
XXX
39tiM) SCMdulM to 4COMtt)lttn inaictua otrewt rfauctton gf vQim.* of spills art identified
in calums (A, 3. C....KC. } otto*.
Frequency of insoeccion is iisuMd *t cnree tines per year.
^noenMCer lines only, noitever, ocner ser.eoules shown my tUo
-------
Implementation of the One-Call System as recommended in Reference 12
is expected to result in annual savings of approximately 120,000 barrels
of petroleum (40 percent of total). This is also expected to decrease the
number of incidents by 88 (33 percent of total).
Survey of the line by inspection pigs (magnetic flux type or other com-
parable device) carried out every four years is expected to save approxi-
mately 80,000 barrels of petroleum (28 percent of total) and decrease the
number of incidents by 106 (36 percent of total). This inspection would be
particularly effective in preventing spills caused by line pipe faults.
Hydrostatic tests are recommended for lines where inspection pig sur-
veys are impractical because of line pipe size or other considerations.
Either yearly tests or tests after indication of a spill (whichever sched-
ule is most effective) are recommended. These inspections are expected to
save approximately 60 to 90 thousand barrels of petroleum (20 percent to 33
percent of the total) and decrease the number of incidents by 80 to 100 (28
percent to 35 percent of the total).
Overall, these inspections are expected to reduce the spill volume and
spill incidents by more than 66 percent. Total costs are estimated at less
than 40 million dollars per year. This cost is significantly lower than the
cost of preventive maintenance using cathodic protection systems. Yet, the
reduction of the number of incidents and spill volume is expected to be much
greater.
8.3.3.2 Underwater Lines--
Recommendations for underwater lines include:
• Visual inspections of the line by air or ground patrol - weekly
• Depth of cover inspection by sonar or other comparable device -
every two years
• Hydrocarbon probe (towfish or similar device) inspection -
yearly
• Survey by inspection pig (magnetic flux type or other compara-
ble device) - every two years
or
• Hydrostatic test - yearly.
(See also developmental and new methods Section 8.4).
8.3.3.3 Large Diameter Lines--
Recommendations for large diameter lines (greater than 16 inches in
diameter) include:
• Visual inspections by air or ground patrol - weekly
• One-Call System (Reference 12)
334
-------
• Survey by inspection pig (magnetic flux type or other com-
parable device) - every four years
• Volume comparison, flow rate comparison and pressure deviation
or
• Mathematical modeling.
(See also developmental and new methods Section 8.4).
8.3.3.4 Old Lines-
Recommendations for old lines (30 years or older) include:
• Visual inspections by air or ground patrol - weekly
• One-Call System (Reference 12)
• Survey by inspection pig (magnetic flux type or comparable
device) - every three years
or
• Hydrostatic tests
yearly, or
after indication of spill.
8.3.3.5 Lines with Two or More Reportable Spill Incidents within One Year--
Recommendations for lines with two or more reported spill incidents
within one year include:
• Visual inspection by air or ground patrol - weekly
• One-Call System (Reference 12)
• Survey by inspection pig (magnetic flux type or comparable
device) - every year
• Hydrostatic tests - yearly.
This schedule should be in effect until approximately three years after
spill incidents are reduced to a normal rate.
8.4 RECOMMENDED DEVELOPMENTAL AND NEW INSPECTION AND LEAK DETECTION
METHODS
Although a number of developmental and new inspection and leak detec-
tion methods are capable of reducing the potential of spills, only a few
are considered to have the potential of significantly reducing the oil
spill risk. These include:
335
-------
• Mathematical modeling
• Passive acoustic array
retrofit (prevent damage from outside forces)
new lines (prevent damage and detect failures).
Mathematical modeling of the line appears to be a proven new technique
but should be thoroughly reviewed and evaluated before it can be recommended
for most lines. It is recommended at this time for use on .lines that are
in high risk areas, such as underwater lines, and/or lines with a high risk
that oil may escape from a line such as those of large diameter. The
method, if used alone, is expected to reduce the expected volume of spills
by about 65 percent. It also appears to be one of the most cost-effective
methods available (see Table 78). No conclusive evidence is available to
prove that the method can prevent spills, although such events as line
pressure surges may be reduced with this method. The method should be con-
sidered with other options, particularly ones that prevent spills. Use of
this method on a large number of lines would be difficult to implement at
this time because only a few small sized commercial companies and a few oil
companies are actively involved in this area.
The passive acoustic array system for retrofitting on existing lines is
a developmental method that shows promise for most lines. It is recommended
that this method be investigated further to verify its capability of prevent-
ing damage from outside forces and rupture detection. The method, if used
alone, is expected to reduce the frequency of spills by about 30 percent and
the volume of spills by about 70 percent. The method appears to be one of
the most cost-effective methods available (see Table 78).
The passive acoustic array system for new lines is a developmental
method that is attractive for lines in certain high risk areas, i.e., under-
water lines, populated areas, etc. It is recommended that this method be
investigated further to verify its capability to both prevent failure from
outside forces and other causes and detect leaks. The method, if used
alone, is expected to reduce the frequency of spills by about 43 percent
and the volume of spills by about 84 percent. Since the method appears to
be of relatively low cost-effectiveness, its application should be limited
to lines in high risk areas.
336
-------
REFERENCES
1. Pipeline Safety Need for a Stronger'Federal Effort. PB-280321, U.S.
General Accounting Office, 1975.
2. Leggett, N., and M. Placet. A Comparison of National Air Residual in
; NEDS and SEAS. Working Paper IR&T-18, International Research and
: Technology Corp., 1978. j
! 3. Crude Petroleum, Petroleum Products and Natural Gas Liquids in the U.S.
I Annual Reports. U.S. Department'of Interior (Bureau of Mines), 1971-
1977.
i ;
i
j 4. Hittman Associates, Inc. Environmental Impacts, Efficiency, and Cost
| of Energy Supply and End Use. Volume 1. PB 238-784. Council on En-
j • vironmental Quality, Washington, ,D.C., 1974.
5. Association of Oil Pipelines. Press Release. June 7, 1975: May 26,
! 1975. | !
1 , !
6. Transport Statistics in the U.S.,' Part 6, Oil Pipeline. Annual Re-
ports. Interstate Commerce Commission (Bureau of Accounts). 1965-
1976. i
• i
1 7. Regulations on Transportation of Liquids by Pipeline. Title 49 of
Code of Federal Regulations, Part 195. Department of Transportation,
1977. ,' |
8. Petroleum Extension Service. Introduction to the Oil Pipeline Indus-
try. The University of Texas, Austin, Texas, 1966. 84 pp.
i ' '
i 9. Mineral Industry Surveys: Crude Oil and Refined Products Pipeline
I Mileage in the United States. U.S. Department of Interior (Bureau
! of Mines), 1971. I
i !
j 10. Mineral Industry Surveys: Crude Oil and Refined Products Pipeline
I •• Mileage in the United States. U.S. Department of Interior (Bureau
j of Mines),, 1974.
i ' •
i 11. Energy Data Reports: Crude Oil and Refined Products Pipeline Mileage
: in the United States. U.S. Department of Energy (Bureau of Mines),
< 1977. : !
337
-------
12. Courtney, W.J., G. Yie, and D. Kalbbrenner. Effectiveness of Programs
for Prevention of Damage to Pipelines by Outside Forces. Report DOT/
MTB/OPSO-77/12, ITT Research Institute, 1977.
13. Petroleum Storage Capacity, National Petroleum Council, 1974.
14. Mastandrea, J.R., O.A. Simmons, P.B. Kimball, and K.J. Gilbert. Deep-
water Port Inspection Methods and Procedures. Report No. CG-D-31-78,
United States Coast Guard, Department of Transportation, 1978.
15. Volumetric Shrinkage Resulting from Blending Volatile Hydrocarbons with
Crude Oils. Bull. API 2509C. American Petroleum Institute, Washington,
D.C., 1967.
16. Lease Automatic Custody Transfer. Bull. API Standard 2502. American
Petroleum Institute, Washington, D.C., _1967.__
.
17. Brooks - Bi Rotor Meters. Bulletin (S)DS-(B-42DEB). Brooks Instrument
Division, Emerson Electric Company, 1978.
18. Smith-Meter Systems. Bulletin 271. A. 0. Smith Company.
19. Karabelas, A..J. Recent Studies Improve Velocity Criteria Used for
BS&W Sampling. Oil and Gas Journal, April 17, 1978. pp. 98-104.
20. Reproducibility Between Laboratories. ASTM Standard D 287.
21. Lipkin, M.R. and S.S. Kurtz. Temperature Coefficient of Density and
Refractive Index for Hydrocarbons. Ind. Eng. Chem. Anal., Ed. 13,
1941. pp. 291-295.
22. Downer, J.L.' and F.A. Inkley. Need Shown for Separate Thermal-Expansion
Tables. Oil and Gas Journal 70:25, June 19, 1972. pp. 52.55.
23. Form P—Pipe Line Operation Expenses for Carrier Pipe Line Companies in
the U.S. Annual Reports. Interstate Commerce Commission (Bureau of
Accounts), 1965-1976.
24. Capital Systems. Digest of Pipeline Rates on Gasoline and Petroleum.
Capital Systems Publications, Rockville, MD, Annual Report.
25. Liquid Pipeline Accidents Reported to the Department of Transportation
on DOT-Form 7000-1. Annual Reports. Department of Transportation
(Office of Pipeline Safety), 1969-1977.
26. Ulrich, L. Detailed Information for Each Accident During the Period
1971 through 1975. Office of Pipeline Safety, 1977.
27. Danenberger, E.P. Oil Spills, 1971-1975, Gulf of Mexico Outer Con-
tinental Shelf. Circular 741. U.S. Geological Survey, 1976.
338
-------
28. Conservation Division. Accidents Connected with Federal Oil and Gas
Operations on the Outer Continental Shelf. U.S. Geological Survey,
Conservation Division, 1977.
29. Pollution Incidents in and Around U.S. Waters. U.S. Coast Guard Publi-
cation, Pollution Incident Reporting System (PIRS). CG-487. 1975 and
1976.
30. Ritchie, J.E., Jr., et al. Petroleum System Reliability Analysis.
Volume I and II. Report No. EPA-R2-73-820b, U.S. Environmental Pro-
tection Agency, Washington, D.C., 1973.
31. Leo, J.E. and G.G. Kruijer." Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1966-1969. Stichting CONCAWE Oil Pipelines Working Group, 1971.
32. King, E.M. and G.G.Kruijer. Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1971. Stichting CONCAWE Oil Pipelines Advisory Group, 1972.
33. King. E.M. and P. Rogier. Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1972. Stichting CONCAWE 011 Pipelines Special Task Force 1, 1973.
34. King, E.M. and P. Rogier. Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1973. Stichting CONCAWE Oil Pipelines Special Task Force 1, 1974.
35. King, E.M. and P. Rogier. Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1974. Stichting CONCAWE Oil Pipelines Special Task Force 1, 1975.
36. King, E.M. and P. Rogier. Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1975. Stichting CONCAWE Oil Pipelines Special Task Force 1, 1976.
37. King, E.M. and V. Baradat. Spillages from Oil Industry Cross-Country
Pipelines in Western Europe, Statistical Summary of Reported Incidents,
1976. Stichting CONCAWE Oil Pipelines Special Task Force 1, 1977.
38. Mackay, D., et al. The Physical Aspects of Crude Oil Spills on Northern
Terrain. Task Force on Northern Oil Development. Report 73-42; In-
formation Canada Catalog R72-9173, 1974.
39. Beyer, A.M. and L.J. Painter. Estimating the Potential for Future Oil
Spills from Tankers, Offshore Development and Onshore Pipelines. In:
Proceedings of the 1977 Oil Spills Conference, Prevention, Behavior,
Control, Cleanup. Am. Petroleum Institute, U.S. Environmental Protec-
tion Agency, and the U.S. Coast Guard, New Orleans, LA, 1977.
339
-------
40. Stewart, Robert J. The Tanker/Pipeline Controversy. Proceedings of
the 1977 Oil Spills Conference; Prevention, Behavior, Control, Clean-
up, Petroleum Institute, U.S. Environmental Protection Agency, and the
U.S. Coast Guard, New Orleans, LA, 1977. pp. 95-99.
41. Operations Research, Inc. Spill-Risk Analysis Program: Interim Report
E-2: Facilities Analysis, 1975.
42. Young, G.K., D. Evans, and R.U. Jettmar. Analysis of Oil Spill Trends.
Report to the Council of Environmental Quality, Alexandria, VA, 1976.
43. Bayaert, Bruce. Analysis of Oil Spill Accidents for Environmental Im-
pact Statements. In: Proceedings of the Conference on Prevention and
Control of Oil Pollution. American Petroleum Institute, U.S. Environ-
mental Protection Agency, and U.S. Coast Guard, San Francisco, CA, 1975.
pp. 39-45.
44. Paulson, A.S., A.D. Schumaker, and W.A. Wallace. A Risk-Analysis Ap-
proach to Control of Large-Volume Oil Spills. In: Proceedings of the
Conference on Prevention and Control of Oil Pollution. American
Petroleum Institute, U.S. Environmental Protection Agency, and the
U.S. Coast Guard, San Francisco, CA, 1975. pp. 301-106.
45. Wilson, J.D. A Statistical Estimate of Pipeline Leakage. Report SAI-
79-162. Santa Ana, CA, 1977.
46. Col burn, C. Methods of Preventing, Detecting and Dealing with Surface
Spills of Contaminants which may Degrade Underground Water Sources.
Report EPA 68-01-4620, U.S. Environmental Protection Agency, Office of
Water Supply, Washington, D.C., 1978.
47. Boyd, B.D., C.C. Bates, and J.R. Harrald. The Statistical Picture Re-
garding Discharges of Petroleum Hydrocarbons in and Around United
States Water. Sources, Effects and Sinks of Hydrocarbons in the
Aquatic Environment. In: Proceedings of the Symposium, American In-
stitute of Biological Sciences, American University, Washington, D.C.,
1974. pp. 38-53.
48. Petroleum in the Marine Environment. National Academy of Sciences,
1975.
49. Kiefner, J.R. and R.B. Smith. An Analysis of Reportable Incidents for
Natural Gas Transmission and Gathering Lines, 1970 through 1975. Re-
port NG-18, Report No. 106 to the Pipeline Research Committee, American
Gas Association, 1977.
50. Marine Environmental Protection Program: An Analysis of Mission Per-
formance. United States Coast Guard, Department of Transportation,
Washington, D.C. 1975.
340
-------
51. Funge, W.J., K.S. Change, D.I. Juran, et al. Offshore Pipeline Safety
Practices, Volume II - Main Text. Report DOT/MTB/OPSA-77/14, 1977.
52. Jones, S.C. and Roszelle, W.D. Graphical Techniques for Determining
Relative Permeability from Displacement Experiments. Journal of
Petroleum Technology, 1978.
53. Blocker, P.C. Migration of Oil in Soil. Paper Presented at Interna-
tional Conference, "Antinguinamento 71," 1971.
54. Dan J. Van. The Migration of Hydrocarbons in a Water Bearing Stratum
Of Stichting CONCAWE, The Hague, 1966.
55. Duffy, J., M.F. Mohtadi and E. Peaka. Subsurface Persistance of Crude
Oil Spilled on Land and Its Transport in Groundwater. Proceedings 1977
Oil Spill Conference. American Petroleum Institute, U.S. Environmental
Protection Agency, and U.S. Coast Guard, New Orleans, LA, 1977.
56. The Migration of Petroleum Products in Soil and Groundwater. Publica-
tion No. 4149, American Petroleum Institute, Washington, D.C., 1972.
57. Goodfellow, R. Underwater Engineering. Tulsa, OK, 1977.
58. Platus, D.L., et al. Rapid Shutdown of Failed Pipeline Systems and
Limiting of Pressure to Prevent Pipeline Failure Due to Overpressure.
Report PB 241-325, U.S. Department of Transportation, 1974.
59. McFarlane, C. and R.D. Watson. The Detection and Mapping of Oil on
a Marshy Area by a Remote Luminescent Sensor. Proceedings 1977 Oil
Spill Conference. American Petroleum Institute, U.S. Environmental
Protection Agency, and U.S. Coast Guard, New Orleans, LA, 1977.
60. Jackson, P. Leak Detection in Underwater Oil Pipelines. Report NMRC
272-23100-R2, National Maritime Research Center, 1973.
61. Oil Pollution Detection and Sensing - Bibliography with Abstracts.
Search Period 1964-July 1976. Report NTIS/PS-76-0701, NTIS, 1976.
62. Rambie, G.J., Jr., R.H. Morgan and R.J. Jones. Feasibility of Contin-
uous Monitoring for Oil Pollution Across Channels and Rivers. Proceed-
ings 1977 Oil Spills Conference, Prevention, Behavior, Control, Clean-
up, American Petroleum Institute, U.S. Environmental Protection Agency,
and U.S. Coast Guard, New Orleans, LA, 1977.
63. Alford, B.J., M.M. Paterson, and F.A. Womack. Development and Field
Evaluation of the Production Surveillance Monitor. Journal of
Petroleum Technology, 1978.
64. Jouve, P. Process and Apparatus for Detecting a Fluid Leak from a
Pipeline. Belgian Patent No. 823,862, 1977.
341
-------
65. Holland, W.E. and G.R. Burrell. Acoustic Method for Detecting Leaks
from Submerged Pipelines. U.S. Patent No. 4,001,769, 1977.
66. Ells, J.W. and A. Roberts. Underwater Pipelines. U.S. Patent
No. 3,992,924, 1976.
67. Boyens, V.C. Pipeline Leak Locator Method. U.S. Patend No.
4,016,748, 1977.
68. Bielawa, R. and H. Howe. Radar Unit Locates Buried Plastic and Metal
Lines. Pipeline Industry, July 1977.
69. Farmer, W.M., et al. Feasibility of Scour Monitoring. Report 1-SAI-
75-503-77, U.S. Department of Transportation, Washington, D.C., 1975.
70. Mastandrea, J.R. and J.M. Zuieback. Feasibility of Scour Monitoring
Instrumentation. Report SAI-260-76-518-LA for U.S. Department of
Transportation, Washington, D.C., 1976.
71. Underwater Inspection/Testing/Monitoring of Offshore Structures. Con-
ducted by R. Frank Busby Associates. Sponsored by DOT, DOE and DOI,
Contract 7-35336, February 1978.
72. Los Angeles Times.
73. Phil pot, F.V. and A.D. Higham. Pig and Leak Location Undersea Pipe
Lines. Presented to the Oceanology International Conference, Brighton,
England, 1978.
74. These Inspection Probes Check Internal Rise Corrosion. Ocean Industry,
February 1978.
75. Ultrasonic Rises Inspection Tool Successful. Ocean Industry, August
1978.
76. Metzler, J.A. Acoustic Holography may Permit Buried Pipe Line Inspec-
tion. Ocean Industry, May 1978.
77. Dodd, V.R. Integrated Machinery Inspection Program Cuts Maintenance
Costs. Oil and Gas Journal, April 1978.
78. Boor-man, R.D. and A.R. Walledge. Current Method of Routine Testing
and Leak Detection in Operating Oil Line. Report No. 5/73, Stichting
CONCAWE, The Hague, 1973.
79. Catagnet, A.C. Application of Radioisotopes in Oil, Gas and Petro-
chemical Industries - Transport of Hydrocarbons. Institute de Energia
Atomica, Sao Paulo (Brazil). Div. de aplicacao de Radioisotopos na
Engenharis e na Industrie, August 1976.
342
-------
80. Published Regulatory Guidelines of Environmental Concern to the Oil
Industry in Western Europe. CONCAWE Report No. 2/77.
81. Baker, J.M. Marine Ecology and Oil Pollution: The Work of the Oil
Pollution Research Unit.
82. Annual Report to Congress by National Transportation Safety Board, U.S.
Government Printing Office, Stock No. 5000-00084, 1975.
83. Dubiel, E.J. The Practical Aspects of Litigating an Oil Spill (Plain-
tiff's Viewpoint). Proceedings 1979 Oil Spills Conference, American
Petroleum Institute, U.S. Environmental Protection Agency, and U.S.
Coast Guard, Los Angeles, CA, 1979.
343
-------
APPENDIX A
EXISTING U.S. AND FOREIGN REGULATIONS FOR TRANSPORTATION
OF LIQUIDS BY PIPELINE
A.I TITLE 49-U.S. TRANSPORTATION OF LIQUIDS BY PIPELINES
TITLE 49 PART 145
A.I. TITLE 49-U.S. TRANSPORTATION OF LIQUIDS 8Y PIPELINES
OffAOTMENT OF TRANSPORTATION
MAI6UAU TRANSPORTATION 3U8EAU
WAiMMOTOM. 3-C HIM
no***^"«aiiapaftt*1aii "OtmatioB of ta* ConaMBtB" Motion
awmx t—MATDBAts TMNWOajTA. of -JO* snamal*. Cammnui vatca air-
«ug«»u. amutnum or mod m* c&aatai ouoid* ta* «ap* ot
ta* ui imuiaa noae» an act ilUmiMil big
say b* coaattcnd ay ta* 'ntanili
^•acporcaaaa "Inratn "» «* 0°*•"•* «•» nanane* ot ta*
URAlANOOTHCltaMSr MmiNK ptopoaU an aot dUeocMd Swat
.-_,_, «_ .__ OUemtnon at COHMWRCK. Wtta refart
^^^^ ^T2U2T JSSLi*"1' nl11"* ca ca> utm -small" la ta* tnapoHd
""•"• "•"•""• iiaa.tuui.an <
11II ill I •JitaniliTiiiiinaiiiliiii nil ta*ax«
.mfc Offle* of ttgtUa* Sattcr Opat»> to* t*i
QODA Qcpa^Bian of TiaiuuanaooA* *uuJd b* OD*B to ladtttdual l
ACSOail
P«naM» ttrdr. taawc
aanatatCTttaiaaaiaintBaaiaQlaiBa tatra* of ta* L.
pipvUfiiB wtt&om cntiBs, csctiocuo pro* toctui or !•• t& c
•MCMaV ISd tBOHlfmttlty VtM& •\dVQUftW up !••• 4« I*MMLH T^M (
. ___L|l_i_i_||_i. -nnr^i I i. i •• .1 «7 J t»M ^^ l^*»»«* *•*• »
nCVUw CORIwHB UMAUUI U LUUfMMQ OT
ailorafa. Tb* fatt Mfjop and •BBBOBB* .
tdvaBtac* of ta*H stciavi "*fflT*** b* •^••i*^ ^pi^u^ ^ ^«»i^.y ^ 'li'iiiiin^ur
nattnd ujular t&* PVCMBS rala b*caua Jaalaud. ?sra ot&ar oooiB*Bt*n iraiTntf
of t&* -«a» tag batttaa of srenatn* • tSat-aay .—"y""-i of atoao jaoold
S^BC^^nB OA7E: "Hsla •H**'1'"^'1*
I on ta»oj*
of plattle tttp* la CM nmea by ta* arail-
_.__. aU* lomsu nwtooda aad by ta* COM of
""-1- TH"rmi- iPmiutly. 13-inca dJaautcr
(tn-Ot-nm- plame ntp* u tb* lan*n nomaily ua«d
mmtiwrmw' * «*• MnrtMJ TlMM coouacaua alM
CTOOKMATIDW. pottMd out taat ca* nun ntaraat tan
of iaf«y woald b* mwcta* ta* BtopoMd
nojusvBMBt t* d*BMoatfac* taat umo*
rt«. (• nMB « onotenu yirthar. o& fH<*
mn'T.' ^^« SS^'SST'SS.S S««. ^« TSSeal Ptoalla* Saf«y
!22LdiB^2S53St^£SSK «*3arta gamma* <0nc^MH4-
i^4iTr.w,iSf^ar^sssss« tSsBS^Ss^H
by nmttus ta* opantar ta >aow by
tana, laraBUaaoo. or ttpirnnr* taat
adfqnat* oaoeaMB ooosoi ta obtain**
On ScpumMr a. HIS. tt»
Taaponattoo 3onM (MTB> mud s
aooo of .uugumit retaoaldac. Mode*
NO. TS-l. (41 PR 4381. StOCHBlMr TT.
not laakac* i
noaaitan*. aad taat ta* opanor «•••
J^Sd.fbV'lISSa^'SSSSS^ -firSTS-m J«3 ao-d tnat tj»
Mntw«r»gtTitida«nanUf»ntt«ndaca.
nir... or tivooaa by Wmobar I. iTtte'tam or toy eompanal* rmtOf
Tn^^n^p.^, *.«— S^tSSSS^
stae. cnuluorr aonete. I tnd. ajj SSslSar'e.^^SS
naoon. and l maanricrorp of imnn SS'.SSU^S^fSSSTSLUL^I
AU :, ceomuuta «m faTCnbla, a ISSSfySrV^-SS^Ski^II
', to ta* uruuuata aauBdmcBi. A iitomlnn of ta* ana -naaU could r*»
«« tB*nSSaatM^a«Ba mlt in noaoaifana apoUcaHon of ) IS2.-
wmca «.^M aTdSSL't.'SS. * •«>trgSSffSS* »
rn rn« nuiiiimii iniTntlmim* "v< "I-^T- AUO. a ax* ilnnfafinn 11 tgieuiuy en-
WHHHBH •jiiwuimim* ami *om MI*~ ~~, . _ _ t . - _j i*n_
of tao** eonmuBia a drrdoo. *"• « snaiat ^irmototr aau ««o»
iaal mliuoonaiMd am* acoue* ™»aMd to t&* us* of pla.de plpa.
344
-------
More significant than size, however.
in protecting against corrosion is the
fact that as discussed hereafter the op*
erator would be retmired under 5 192.455
?3) is intended to;
provide for anv future inspection, repair.
or replacement that might be required as
a result of future rulemaking should any
new information indicate a need for such
remedial action.
In addition, MTB requests that oper-
ators voluntarily report the condition of
any alloy fitting installed under } 192.455
(f) which is uncovered for any reason.
MTB Is interested in receiving reports on
corrosion performance of the fittings, es-
pecially any leakage of a fitting that is
not required to be reported under
1} 191J and 191J of this chapter, and the
number of fittings installed. These re-
ports could be submitted by operators in
letter form and need not be submitted
more often than once a year, unless the
operator desires to report more fre-
quently. MTB expects that information
obtained through the voluntary report-
ing may serve as a basis for a future rule-
making action either to relax the restric-
tions applicable to exemption under
§ 192.455 (f) or to prescribe any necessary
remedial measures, as the case mav be.
345
-------
Regarding the proposed { 182.459(1)
(2). the TPSSC further suggested that
the term "corrosion pitting" be replaced
by "corrosion attack." This comment was
not adopted for the sake of consistency
since the term "corrosion pitting" is used
elsewhere in Pan 192.
Another commenter thought that an
operator should not have to use tests. In-
vestigation. or experience "In the area of
application" to show under 3 192.455(f)
(1) that alloy fittings provide adequate
corrosion control. This commenter al-
leged that the testing, investigation, or
experience in the corrosion studies re-
ported in the National Bureau of Stand-
ard's (NBS) Circular No. 579 and two
California field studies mentioned in the
Notice are sufficient to allow a general
exception without the need for an indi-
vidual finding by each operator.
MTB does not agree. The NBS study
compares the performance of certain
materials under a limited number of en-
vironments. It did not establish a means
to quantitatively measure the corroslvitv
of anv environment in which a material
might be used. Also, the-two field studies
conducted In California do not have uni-
versal application to all soils. Those stud-
ies are more indicative of local condi-
tions. They include the type of testing
and investigation that an operator might
conduct in an area to determine whether
flttlntts are adequately nrotected affainst
corrosion by allovage. For these reasons.
MTB did not adopt the suggested change
in the final rule.
or THE TECHNICAL Pirsum
SAFETY STANDARDS COMMITTEE
Section 4(b) of the Natural Gas Pipe-
line Safety Act of 1968 requires that all
proposed standards and amendments to
such standards pertaining to gas pipe-
lines be submitted to the Committee and
that the Committee be afforded a rea-
sonable opportunity to prepare a report
on the "technical feasibility, reasonable-
ness, and practicability of each proposal."
The proposed amendment was submitted
to the Committee as Item A-l in a list of
two proposed amendments at a meeting
In Washington. D.C., on December 16 and
17, 1978. A minority report was not sub-
mitted.
On February 3. 1977. the Committee
filed the following favorable report:
This communication 13 the official report
of the Technical Pipeline Safety Standards
Committee concerning the Committee's ac
tion on two amendments to 49 CFR Part 192
proposed by the Office of Pipeline Safety Op-
erations and other matters which the Com-
mittee decided should be brought to the at-
tention of the Department of Transportation.
The fbllowlng described actions were taken
by the- Committee at a meeting held In Wash-
ington. D.C.. on December 18 and 17, 1976.
Item A-l of the agenda was a proposal by
OPSO to revise i 192.455. External corrosion
control. By an affirmative vote of 12-1 the
Committee found that the following lan-
guage for i 192.455 Is technically feasible.
reasonable, and practicable.
(The language suggested Is adopted In the
flnal rule except as discussed in the "Dis-
cussion ot Comments Section" above.)
PRINCIPAL AUTHORS
Ralph T. Simmons. Regulations Soe-
cialist. Georee Mocharko, Staff En-
gineer, and Robert L. Beauresard. Attor-
ney, Office of the General Counsel.
In consideration of the foregoing.
i 192.455 of Title 49 of the Code of Fed-
eral Regulations is amended bv amend-
ing paragraph (a) and adding a new
paragraph (f) to read as follows:
§ 192.455 External corrosion control:
buried or submerged pipelines in-
stalled after July 31,1971.
(a) Except as provided in paragraphs
(b). (c>, and (f) of this section, each
buried or submersed pipeline installed
after July 31. 1971. must be protected
against external corrosion, including the
following:
• • • • •
(f) This section does not apoly to
electrically isolated, metal alloy fittings
in plastic pinelines if—
(1) For the size fitting to be used, an
ooerator can show by tests, investiga-
tion, or experience in the area of appli-
cation .that adequate corrosion control
is provMud h" n.Uova»e:
(2) The fitting is designed to prevent
leakage caused by localized corrosion
pitting; and
(3) A means is provided for identifying
the location of the fitting.
(49 USC 1672: 49 CFR 1.53 (a).)
Issued in Washington. D.C., on July
1-. 1977.
ALAN A. BCTCHMAN,
Acting Director. Materials
Transportation Bureau.
[PR Doc.77-19421 Filed 7-8-77:8:45 am)
346
-------
the Notice but feels that It is within the
broad scope and Intent of the Notice.
and therefore it is appropriate to include
it in the final rules. However, in keeping
with MTB's policy to ensure that the
public has full opportunity to participate
in the rulemaUing process, MTB is delay-
ing the effective date of 5 192.313 (a) (4)
(B) and 1 19S.212(b)(3)(B) until No-
vember 3, 1977 to permit any interested
person the opportunity to comment be-
fore the rule becomes effective. If no ad-
verse comment is received that raises
substantial doubt as to the desirability of
the amendment, it will become effective
November 3. 1977 as written.
RCFOKT or TXC TECHNICAL PXTEUNX
SAFETY STANDARDS COMMITTED
Section 4O» of the Natural Gas Pipe-
line Safety Act of 1968 requires that all
proposed standards and amendments to
such standards pertaining to gas pipe-
lines be submitted to the Committee and
that the Committee be afforded a rea-
sonable opportunity to prepare a report
on the technical feasibility, reasonable-
ness. and practicability of each- proposal.
Ibis amendment to Part 192 was sub-
mitted as Item A-2 in a list of two pro-
posed amendments at a meeting in
Washington, D.C.. on December 16 and
17. 1976. On January 12. 1977. the Com-
mittee filed the following favorable re-
port* A Tnfajmi'lt^ report was not ftT^fl
Thl» communication is the official report
of the Technical Pipeline Safety Standards
Committee concerning tb* Committee '» ac-
tion on two amendment* to 48 cm Part 183
propoied by the Office of Pipeline Safety Op-
erations and other matteri which the Com-
mittee decided should be brought to the at-
tention of the Department of Transporta-
tion.
Tb* following described action* were
taken by the Committee at a meeting held
in Washington. O.C. on December 18 and 17.
1878.
Item A-2 wa* a proposal by OPSO to re-
vise 1 182.313 (a) (4), Bend* and elbow*. By
an affirmative vote of 13-1 the Committee
found that the following language for I 193.-
313(a) (4) If technically feasible, reasonable.
and practicable.
• • • • •
(The language suggested is adopted In the
final rule M diaeimed In the "Discussion of
Comment* Section" above.)
After additional discussion* of agenda Item
A-3, by an affirmative vote of 13-1, the Com-
mittee further recommended that I 183.313
be further modified to provide that for pipe
with a D/t ratio less than 70. the location of
the longitudinal seam may be at the discre-
tion of the operator.
PMWOTAI AUTHORS
Ralph T. Simmons. Regulations Spe-
cialist, and Robert L. Beauregard, Attor-
ney Office of the General Counsel.
In consideration of the foregoing.
Parts 192 and 195 of Title 49 of the Code
of Federal Regulations are amended as
follows:
1. Section 192.313(a><4> is amended
to read as follows:
§ 192-313 Bend* and elbow*.
(a) * ' '
(4) On pipe containing a longitudinal
weld, the longitudinal weld must be as
near as practicable to the neutral axis of
the bend unless—
(i) The bend is made with an Internal
bending mandrel; or
(11) The pipe is 12 inches or less ih"out-
side diameter with a diameter to wall
thickness ratio less than 70.
(See. S. Pub. L. 80-481. 83 Stat. 731. 48 T7SO
1672: for offshore gathering lines. Sec. IDS.
Pub. b. 83-833. 88 Stat. 21S7. 48 USC 1804: 40
TB 43801.48 CPU 1.53.)
2. Section 195.212 (b) (3) is amended
to read as follows:
8195.212 Bending of pipe.
• • • • •
(bJ ' • •
(3) On pipe containing a longitudinal
weld, the longitudinal weld must be as
near as practicable to the neutral axis of
the bend unless—
(i) The bend is made with an internal
bending mandrel; or
(11) The pipe is 12 inches or less in out-
side diameter with a diameter to wall
thickness ratio less than 70.
• • • • •
(See. 8. Pub. L. 89-670, 80 Stat. 937. 48 U.S.C.
1655: 18 U.S.C. 831-835; 40 PR 43901. 49 CFR
1.S3.)
JOHN J. FEARNSIDES.
Acting Director.
Materials Transportation Bureau.
[PR Doc.77-24303 Piled 8-24-77:8:45 amf
348
-------
DEPARTMENT OF TRANSPORTATION
MATERIALS TRANSPORTATION 3U8EAU
WASHINGTON. O.C 20390
CHAPTER I—MATERIALS TRANSPORTA-
TION BUREAU. DEPARTMENT OF
TRANSPORTATION
suaoumft o nnutn swcrv
[Atoota, iS3-» ua.13: OookM Mo.
Taere wen six person* who responded
and suamitted written comments to No-
tice 75-i Tarea won from EU dlambu-
tton companies sad three -we from
trade mmrntlOTM. A *<««M«i««q of the
comments aad the reeom-
PART 193—TRANSPORTATION OP
NATURAL AND OTHER OAS 8Y PIPELINE
PART 136—TRANSPORTATION OF
LIQUIDS 3Y PIPELINE
lonejuidlnei Seems In Plpa-Benda
AGENCY: **>***tnli Ttaasportaaaa
ACTION: Fmalruift.
beads of steel
pipe to be placed other than near the
mandrel is used or when bending pipe of
12 inches or leu m outtttde diameter that
baa a diameter to wall fM* (3) (B) do
not beeooM efiiettra anal November 3.
13TT.
flBrir*ny to con*
meat oa Section 19Z313(am> or
Section lS5-2ia(b)(3) (B> snonld com-
seat la wiiuiic to*
Dtreetor. Qfle* of TIpamw Safety Op-
endoBi. Department of Traasportaaan.
noo Second Street. 3.W, Waiam«toa.
D.C. 20890.
Comments win be avmUabl* at Docket
Room 3SOO. 2100 Seeoad Street, S.W..
Waabiaiton. O.C.
An of tae coauaeBten aad *^^ T?SSC
supported the proposal as published la
the Notice. Tin* reasons wen that the
particularly wita thtt use of **w lateraalr
bending mandrel, have made the resale-
is, a b^tut uaaacessary. Ibey concluded
that operators aad carriers should be
allowed to utilize this Improved teca-
to produce a high quality pipeline aad
shown the old requirement to be obsolete.
MTB n gr lies wita the eommenters aad
tae TFSSC. that operators should be al-
lowed to take full advantage of improved
«eidm« tad bendiag technology that is
not *F»"»«-teat with pipeline safety.
tton, MTB la aot aware of any failures
in the '""r*"^"-* weld seam of pipe
weld seam placed oth*r than near the
neutral axis. *•<'"*"—"r MTB is of the
aura ta I! 19X313 ""1 198J12 are sof-
aelent to ensure that say pipe wita a
damaged wvid seam would be detected
and rejected before being placed la serv-
ice. Tae edvaaeea la pipe maaufaccur
TOR P
TACT:
IOTOHMA33OK CON-
(202) 428-2392.
SDPP12MENTAKT
Toe Matertiilt Transportation Bureau
(MTBX lamed a node* of proposed nue-
maktai; Node* No. T8-3 (41 PR 4««3.
October 21, 1978), proposing to amead
i 19Z313(a> (4) of tae ?adenl gas pipe-
line safety standards and ! 13i212(b> (3)
of toe Federal liquid pipeiia* safety
standards to permit tne field beadtac of
steel pipe with lonattudJnal -wins -*»tn-
oat p«^*n»f; tae loncttodmal weld n^ir
tae neutral aids of tne bend If aa inter-
nal bendrns mandrel is used. Interested
person* were invited to peraetpate la
rulemaklai action by
make the i smilre
meat for piaclag the longitudinal wvid
la a neutral axis when bending wita aa
internal bending mandrel uaaeeessex*
Tae rrtaTaBnn
_
One ^*t>*l'tl*lf'*T agreed witb tae pro*
2CXB •rTnf'But lt» tnvestigaUoa to sub-
stantiate tag need fop tag reQuiremeat
^^ a longitudinal weld be placed near
tae neutral axis during bending when
aa Internal >«t»»«ny mandrel Is not used.
T&e reason given was that the proposal
wul provide the operator with a choice
of methods for sett bending of pipe.
MTB win continue tta investigation
tton from inowledgeable sources. Such
information will be considered by MTB
for future rttlemaJdag proceedings oa
pipe beadiac.
Three eommenters aad the t?SSC
suggested that aa internal ^"t'tlT'g man-
drel la ^^*rftyrrrffrtatfe for bendiag small
pipe, aad use of the mandrel should not
be adopted sa a condition to not placing
the Tungitudmal seaax n^ti* the neutral
axis. Their argument waa that for large
aa internal bending mandrel is not un-
reasonable because latemal n^n^^g
mandrels an required to obtain accept-
able field bends. However, for small dl-
ametar pipe, particularly 12 tnchy ****
t^Ha^ with a diameter to wall thickness
(D/t) ratio of less than 70. internal bend-
Ing ********* an aot needed to achieve
acceptable beads. Taey farther stated
that, when using electric resistance weld-
ed pipe that has been weathered, cleaned.
and coated, ft la very difficult to locate
the '""T**1"""*1 weld seam.
available information. MTB believes that
safe beads &x steel pipe 12 laches or
lesa la outside diameter with a D/t ratio
of leas than 70 can be made without using
fchfwyK rt^ loagltttdiaal ^^m is not
placed near taa neutral axis of the bead.
Farther. MTB baa aot jeeelved any re-
ports of failure of beat pipe of 12-lach
diameter or less with a D/t ratio of lesa.
than 70 that can ba attributed to the
was aot used or that taa location of the
Irnigltncltnal weld seam la bending waa
a contributing factor.
Therefore, la view of the favorable m-
fftrmalilTfi *"*t ^^ aheencti of aay mfor—
marton to tae contrary. MTB is c-f the
opiaioa fhat omittiag the proposed coa-
'littftn fhat »^ lateraal bendiag niaadrel
be used whea bending pipe of 12 Inches
or less la outside diameter with a D/t
ratio leas, than 70 as aa alternative to
placing the weld seam near the neutral
a^jfl jg OQ( contrary to the public inter-
est nor inconsistent with, pipeline safety.
For the foregoing reasons. MTB has
further amended M l92J13(a><4) and
19B.212(b><3) by adding to each section
a aew subdivision (B> to allow the field
bending of small diameter steel pipe with
a longttndiaal seam without placing the
seem near the neutral axis liTeapeutive
of whether a h*"'<<''g maadrel is used.
UTS is cognizant of the fact that this
Issue wea not specifically addressed la
written data. Ttews. or arguments aot
later than JTovenber 8. 1978.
347
-------
DEPARTMENT OF TRANSPORTATION
MATERIALS TRANSPORTATION BUREAU
WASHINGTON, D.C 20390
[Amdts. 182-29; 195-12; Docket No. OPSO-38]
PART 192—TRANSPORTATION OF
NATURAL AND OTHER GAS BY PIPELINE
PART 195—TRANSPORTATION OF
LIQUIDS BY PIPELINE
Longitudinal Seams in Pip* Bends;
Correction
AGENCY: Materials Transportation Bu-
reau. DOT.
ACTION: Correction.
SUMMARY: This document corrects a
final rules document that appeared at
page 42865 in the FEDERAL REGISTER of
Thursday, August 25, 1977 (FR Doc. 77-
24303).
EFFECTIVE DATE: November 3.1977.
FOR FURTHER INFORMATION CON-
TACT:
Peggy Hammond, 202-426-0135.
SUPPLEMENTARY INFORMATION:
By Amendments 192-29 and 195-12, new
{{ 192.313(a) (4X11) and 195.212(b><3>
(ii) were added, respectively, to Parts 192
and 195 to provide t-**frt the longitudinal
seam of steel pipe need not be placed
near the neutral axis during bending
if—
"The pipe is 12 inches or less In outside
diameter with a diameter to wall thickness
ratio less than 70."
As stated in the preamble, the ra-
tionale for adopting this provision was
that "safe bends in steel pipe 12 inches or
less in outside diameter with a D/t (di-
ameter to thickness) ratio of less than
70 can be made without using an inter-
nal bending mandrel even though the
longitudinal seam is not placed near the
neutral axis of the bend." This rationale
purportedly was based on comments re-
ceived on Notice 76-2 (41 FR 46463, Oct.
21, 1976), which proposed to remove the
requirement for placement of the longi-
tudinal seam near the neutral axis when
a bending mandrel is used. Recently,
however, several interested persons have
pointed out that both the final rule and
the rationale incorrectly reflect the writ-
ten comments in the docket and the po-
sition of the Technical Pipeline Safety
Standards Committee (TPSSC). These
persons have stated that the view of com-
menters and the TPSSC was that pipe
12 inches and under in diameter can be
bent safely without a mandrel and with-
out placing the longitudinal seam near
the neutral axis, irrespective of the D/t
ratio. In addition, they stated the record
shows that any size pipe with a D/t ratio
of less than 70 can likewise be bent
safely.
After thoroughly reviewing the mat-
ter, it appears that Amendments 192-29
and 195-12 are in fact inconsistent with
the record as the interested persons have
stated.
Accordingly, the following corrections
are made:
1. Section 192.313side diameter or has a diameter to wan
thickness ratio less than 70.
* • * * *
(Sec. 6, Pub. L. 89-670, 80 Stat. 937. 48 USC
1655; 18 USC 831-885; 49 CPR 1.53.)
Issued in Washington. D.C.. on Novem-
ber 18, 1977.
It. D. SAMTMAH,
Acting Director,
Materials Transportation Bureau.
[PR Doc.77-33914 Filed 11-23-77:8:45 am]
349
-------
DEPARTMENT OF TRANSPORTATION
RESEARCH AND SPECIAL PROGRAMS DIRECTORATE
WASHINGTON. D.C. 2O59O
into
CHAPTER I— MATERIALS TRANSPOR-
TAT1ON BUREAU, DEPARTMENT OF
TRANSPORTATION
SWCHAFTB D-miM SAftlY
Umdtt, 193-92,198-14: Docket Wo. 77-10]
PART 192—TRANSPORTATION OP
MATURAL AND OTHER GAS BY
P1PEUNE
PART 195—TRANSPORTATION OP
LIQUIDS BY PIPELINE
Qualification and D«*ia.n of Stad
Pip*
AGENCY: Material* Transportation
Bureau.
ACTION: Final rale.
SUMMARY: This amendment updates
the existing incorporation by refer-
ence of API Standard 5LS. "API Speci-
fication for Spiral-Weld Line Pipe."
and API Standard 5LX. "API Specifi-
cation for High-Test Line Pipe." to in-
clude in Part 192. the March 1976 Sup-
plement and the 1977 edition of each
document and in Part 195. the 1977
edition of each document.
DATE: This amendment •becomes ef-
fective June 1.1978.
FOR yutmmK INFORMATION
CONTACT:
Frank E. Fulton. 202-426-2082.
SUPPLEMENTARY INFORMATION:
This amendment TTIP^M Parts 192 and
198 conform with recent developments
in the manufacture and design of steel
pipe. These subjects are now regulat-
ed, in part, through an incorporation
by reference of API Standard SIS and
API Standard 5LX. At present, the
1975 editions are the latest applicable
editions of-API 5LS and SIX listed in
Parts 192 and 195. This amendment
updates the lists to include the 1977
editions in both parts and the March
1976 Supplements in Part 192.
Of particular importance is that by
referencing the March 1976 Supple-
ments and the 1977 editions of API
5LS and 5LX, pipeline operators will
be permitted to use Grade X-70 pipe
In the transportation of gas. Grade 3C-
70 is more economical for certain uses
than other available grades of steel
pipe because of its high strength.
which permits the use of thinner
walled pipe. It is projected for use in
the pipeline approved under the
Alaska Natural Gas Transportation
Act of 1976 (15 U.S.C. 719) to trans-
port gas from the North Slope to the
lower 48^States.
The Office of Pipeline Safety Oper-
ations proposed adoption of the later
editions of API 5LS and 5LX in a
Notice of Proposed Rulemaking
(Notice 77-7) issued on December 7,
1977 (42 PR 62397, Dec. 12. 1977). In-
terested persons were invited to par-
ticipate in the rulemaking proceeding
by submitting written data, views, or
arguments by January 12,1978. In ad-
dition, in accordance with Sec. 4(b) of
the Natural Gas Pipeline Safety Act of
1968 (49 U.S.C. 1673
-------
an immediate need to pursue the
matter further. It is recognized, how-
ever, that under certain conditions of
high stress and low temperature, the
potential for fractures may increase in
thin walled pipe. Under these condi-
tions, operators are already required
by the general design requirements of
Parts 192 and 195 to take additional
precautions (see §§ 192.53 and 195.102).
Further consideration will be given to
this problem in a future rulemaking
proceeding on pipelines operating in
low temperature environments.
Several commenters suggested that
the introductory language in Section
II of Appendix A and Section I of Ap-
pendix B to Part 192 and in § 195.3(a)
be amended to permit the use of com-
ponents which provide a comparable
level of safety but do not comply with
any of the listed editions of the docu-
ments incorporated by reference.
Since the safety standards were adopt-
ed, the use of items in stock or the
reuse of salvagable items has been per-
mitted only if the items meet the re-
quirements of Part 192 or Part 195. as
the case may be, and where applicable.
the requirements of a listed edition of
a referenced document. Although this
requirement may be too Inflexible in
certain situations, it was not proposed
to be changed in Notice 77-7 and thus
cannot be changed in the final rules.
However, the problem will be given
further attention in the future when
action is taken on a petition for rule-
making filed by the Interstate Natural
Gas Association of America. This peti-
tion proposes that criteria be estab-
lished for the use of materials that do
not conform with any listed edition of
a listed document.
REPORT OP THE TECHNICAL PIPELINE
SAFETY STANDARDS COMMITTEE
Section 4(b) of the Natural Gas
Pipeline Safety Act of 1968 requires
that all proposed standards and
amendments to such standards per-
taining to gas pipelines be submitted
to the Committee and that the Com-
mittee be afforded a reasonable oppor-
tunity to prepare a report on the tech-
nical feasibility, reasonableness, and
practicability of each proposal. This
amendment to Part 192 was submitted
as Item A in a list of items before the
Committee at a meeting in Washing-
ton. D.C.. on January 17 and 18, 1978.
On March 10. 1978, the Committee
filed the following favorable report. A
minority report was not filed.
This communication is the official report
of the Technical Pipeline Safety Standards
Committee concerning the Committee's
action on one amendment to 49 CFR Part
192 proposed by the Office of Pipeline
Safety Operations, on revisions of Subpart I
of Part 192, as proposed by Committee
members, and on other matters the Com-
mittee decided should be brought to the at-
tention of the Department of Transporta-
tion.
The following described actions were
taken by the Committee at a meeting held
In Washington. D.C.. on January 17 and 18.
1978.
A. PROPOSAL BY OFSO TO AMEND THE UQVXXZ-
MZHTS Of RESPECT TO QUALIFICATION AND
DESIGN OP STEEL PIPE
OPSO proposed to amend the require-
menu of Appendix A and Appendix B of
Part 192 pertaining to qualification and
design of steel pipe as published In Notice
77-7, Docket No. 77-10. By a unanimous af-
firmative vote of the nine member* present,
the Committee found the following lan-
guage to be technically feasible, reasonable
and practicable.
[The language suggested is adopted in the
final rules.]
NOTE.—It has been determined that this
document does not contain a major regula-
tion requiring preparation of a Regulatory
Analysis under DOT procedures or Execu-
tive Order 12044.
In consideration of the foregoing.
Parts 192 and 195 of Title 49 of the
Code of Federal Regulations are
amended as set forth below.
1. Section n of Appendix A to Part
192 is amended to read as follows:
APPENDIX A—INCORPORATED BT REFERENCE
IL Documents Incorporated by reference.
Numbers in parentheses indicate applicable
editions. Only the latest listed edition ap-
plies except that an earlier listed edition
may be followed with respect to pipe or
components which are manufactured, de-
signed, or installed in accordance with the
earlier edition before the latest edition is
adopted, unless otherwise provided in this
part.
A.***
(5) API Standard 5LS "API Specification
for Spiral-Weld Line Pipe" (1967, 1970. 1971
plus Supp. 1. 1973 plus Supp. 1. 1975 plus
Supp. 1. and 1977).
(6) API Standard 5LX "API Specification
for High-Test Line Pipe" (1976, 1970, 1971
plus Supp. 1. 1973 plus Supp. 1, 1975 plus
Supp. 1. and 1977).
2. Section I of Appendix B to Part
192 is amended to read as follows
APPENDIX B—QUALIFICATION or PIPE
I. Listed Pipe Specifications. Numbers in
parentheses Indicate applicable editions.
Only the latest listed edition applies except
that an earlier listed edition may be fol-
lowed with respect to pipe or components
which are manufactured, designed, or in-
stalled In accordance with the earlier-edi-
tion before the latest edition Is adopted.
unless otherwise provided in this part.
351
-------
API 5LS. Steel pipe (1967, 1970. 1971 plus
Supp. 1. 1973 plus Supp. 1, 1975 plus Supp.
1. and 1977).
API SLX. Steel pipe (1967. 1970. 1971 plus
Supp. 1. 1973 plus Supp. 1. 1975 plus Supp.
1. and 1977).
(See. 3. Pub. L. 90-481. 82 Stat. 721. (49
UJS.C. 1872): for offshore gathering lines.
see. 105. Pub. L. 93-633. 88 Stat. 2157. (49
U.S.C. 1804); 49 CFR 1.53 and App. A to
PartU
3. In §195.3. paragraphs (a) and
(c)U) (Iv) and (v) are revised to read as
follows:
5 195.3 Matter incorporated by reference.
(a) There are incorporated by refer-
ence in this part all materials referred
to In this part that are not set forth in
full in this part. These materials are
hereby made a part of this regulation.
Applicable editions are listed in para-
graph (O of this section in parenthe-
ses following the title of the refer-
enced material. Only the latest listed
edition applies, except that an earlier
listed edition may be followed with re-
spect to components which are manu-
factured, designed, or installed in ac-
cordance with the earlier edition
before the latest edition is adopted,
unless otherwise provided in this part.
• * *
(I)"*
(iv) API Specification 5LS "API
Specification for Spiral-Weld Line
Pipe" (1969.1975, and 1977).
(v) API Specification 5LX "API
Specification for High-Test Line Pipe"
(1969,1975. and 1977).
(Sees. «. Pub. L. 89-670. 80 Stat. 937. (49
U.S.C. 1655): <18 D.S.C. 831-835V. 49 CFR
1.53 and App. A to Part 1.)
Issued In Washington. D.C., on April
25. 1978.
L. D. SANTMAW,
Acting Director,
Materials Transportation
Bureau.
352
-------
available for inspection in the Materials
Transportation Bureau, Washington,
D'.C. In addition, materials incorporated
by reference are available as follows:
(1) American Petroleum Institute
( API). 1801 K Street, N.W., Washington.
D.C. 20006, or 300 Corrigan Tower Build-
ing. Dallas, Texas 75201.
(2) The American Society of Mechani-
cal Engineers (ASME). United Engineer-
ing Center, 345 Bast 47th Street. New
Vork. N.Y. 10017.
(3) Manufacturers Standardization
Society of the Valve and Fittings In-
dustry (MSS), 1815 North Fort Myer
Drive. Arlington, Va. 22209.
(4) American National Standards In-
stitute (ANSI). 1430 Broadway. New
York. N.Y. 10018. (Formerly the United
States of America Standards Institute
(USASI). All current standards issued
by USASI and ASA have been redesig-
nated as American National Standards
and continue In effect.)
(5) American Society for Testing and
Materials (ASTM). 1916 Race Street
Philadelphia. Pa. 19103.
(c) The full title for the publications
incorporated by reference in this part
are as follows:
<1) American Petroleum Institute:
API Standard 6D "API Specifica-
tion for Pipeline Valves," which may be
obtained from the Dallas office (1968.
1974).
(lit API Standard 1104 "Standard for
Welding Pipe Lines and Related Facil<-
Ues" (1968. 1973).
(ill) API Specification 5L "API Spec-
ification for Line Pipe" (1969,1975).
API Specification 5LS "API Spec-
ification for Spiral-Weld Line Pipe"
(1969. 1975).
(v) API Specification 5LX "API Spec-
ification for High-Test Line Pipe" (1969,
1975).
<2) ASME Code is the American So-
ciety of Mechanical Engineers BoUer
and Pressure Vessel Code. Section Vm.
"Pressure Vessels. Division 1" (1968.
1974>.
< 31 Manufacturers Standardization
Society of the Valve and Fitting Indus-
try:
(i) MSS Standard practice SP-48
"Steel Butt-Welding Fittings <26 inch
and larger)" 11969).
Ui> MSS Standard Practice SP-63
"High Strength Wrought Welding Fit-
ting" H969).
"Specification for High-Test Wrought
Welding Fittings" (1973).
(4> American National Standards In-
stitute:
(i) ANSI B16.9 "Factory Made
Wrought Steel Butt-Welding Fittings"
(1964. 1971).
(ii) ANSI B31.4 "Liquid Petroleum
Transportation Piping Systems" (1966.
1974).
(5) American Society for Testing and
Materials:
i i) ASTM Specification A53 "Standard
Specification for Welded and Seamless
Steel Pipe" (1968.1973).
(ii> ASTM Specification A106 "Stand-
ard Specification for Seamless Carbon
Steel Pipe for High-Temperature Serv-
ice" (1968, 1972a).
(iiii ASTM Specification A134 "Stand-
ard Specification for Electric-Fusion
i Arc)-Welded Steel Plate Pipe. Sizes 16
in. and Over" (1968. 1973).
(iv) ASTM Specification A135 "Stand-
ard Specification for Electric-Resist-
ance-Welded Steel Pipe" (1968. 1973a).
(v) ASTM Specification A139 "Stand-
ard Specification for Electric-Fusion
(Arc) -Welded Steel Pipe, (Sizes 4 in. and
Over)" (1968, 1973).
(vi) ASTM Specification A155 "Stand-
ard Specification for Electric-Fusion-
Welded Steel Pipe for High-Pressure
Service" (1968, 1972a).
(vii) ASTM Specification A211 "Stand-
ard Specification for Spiral-Welded Steel
or Iron Pipe" (1968. 1973).
(vui) ASTM Specification A333
"Standard Specification for s*^m'"f«
and Welded Steel Pipe for Low-Tem-
perature Service" (1968. 1973).
(ix) ASTM Specification A381 "Stand-
ard Specification for Metal-Arc-Welded
Steel Pipe for High-Pressure Transmis-
sion Systems" (1969, 1973).
140 FR 43901, 49 CFR 1.53) |34 PR 15473.
Oct. 4. 1969. as amended by Amdt. 195-2.
35 FR 17184. Nov. 7. 1970: Amdt. 195-9. 41 FR
13592. Mar. 31, 19761
§ I95.-1 Acceptable petroleum comtnod
ilir*.
No carrier may transport any petro-
leum or petroleum product unless the pe-
troleum or petroleum product is chemi-
cally compatible with both the pipeline.
including all components, and any other
commodity that it may come into contact
with while in the pipeline.
353
-------
pipeline in Interstate and foreign com-
merce of Hazardous materials that are
subject to Parts 172 and 173 of this chap-
ter, petroleum, and petroleum products.
This sort does not apply to—
n*PMirfflvynt
equal to 42 U.S. standard gallons.
"Carrier" means a pipeline carrier
subject to sections 831-435 of title IS.
United States Code.
"Commodity" means a hazardous ma-
terial that is subject to Parts 172 and
173 of this chapter, petroleum, and
petroleum products.
"Component" means any part of a
pipeline which may be subjected to pump
pressure including, but not limited to.
pipe, valves, elbows, tees, flanges, and
closures.
"Line section" means a continuous run
of pipe between adjacent pressure pump
stations, between a pressure pump sta-
tion and terminal or working tankage.
between a pressure pump station and a
block valve, or between adjacent block
valves.
"Nominal wall thldmMi1* means the
wall thickness listed In the p*pe
specifications.
"Offshore" means beyond the line of
ordinary low water along that portion
of the coast of the United States that
is in direct contact with the open seas
and beyond the line marking the sea-
ward limit of inland waters.
"Pipe" or "line pipe" means a tube.
usually cylindrical, through which a
commodity flows from one point to
another.
"Pipeline system" or "pipeline" means
all parts of a carrier's physical facilities
through which commodities move In
transportation that Is subject to this
part, including, but not limited to. line
pipe, valves and other appurtenances
connected to Une pipe, pumping units.
fabricated assemblies associated with
pumping units, metering and delivery
stations and fabricated assemblies there-
in, and carrier-controlled breakout
tankage.
"Secretary" means the Secretary of
Transportation or any person to whom
he has delegated authority in the matter
concerned.
"Specified minimum yield strength"
means the muViuim yield strength, ex-
pressed in pounds per square inch, pre-
scribed by the specification under which
the material is purchased from the
manufacturer.
"Stress level" means the level of
tangential or hoop stress, usually ex-
pressed as a percentage of specified
minimum yield strength.
"Surze preuure" means pressure pro-
duced by a change in velocity of the
moving stream that results from shutting
down a pump station or pumping unit.
closure of a valve, or any other blockage
of the moving stream.
{34 FR 15*73. Oct. 4. 1989, u amended by
Amdt. 195-5. 38 FR 2977. Jan. 31. 1973)
§ 195.3 Matter incorporated by refer*
ence.1
'a) There are incorporated by refer-
ence in this part all materials referred
to in this part that are not set forth
in full in this part. These materials are '
hereby made a part of this regulation.
Applicable editions are listed in para-
graph ic' of this section in parentheses
fallowing the title of .the referenced ma-
terial. Only the latest listed edition ap-
plies, except that an earlier listed edition
may be followed with respect to compo-
nents which were manufactured, de-
signed, or installed before July 1. 1975.
unless otherwise provided in this part.
• MOTT: Incorporation by reference provi-
sions approved by the Director at *he Fed-
eral Register. March 28. 1978.
354
-------
(b) AU incorporated materials are
available for inspection in the Materials
Transportation Bureau. Washington.
D.C. In addition, materials incorporated
by reference are available as follows:
a) American Petroleum Institute
(API). 1801 K Street. N.W.. Washington.
D.C. 20006. or 300 Corrigan Tower Build-
ing. Dallas. Texas 75201.
12) The American Society of Mechani-
cal Engineers (ASME). United Engineer-
ing Center. 345 East 47th Street. New
Vorle. N.Y. 10017.
(3) Manufacturers Standardization
Society of the Valve and Fittings In-
dustry (MSS). 1815 North Fort Myer
Drive. Arlington. Va. 22209.
(4) American National Standards In-
stitute (ANSI). 1430 Broadway. New
Vorfc. N.Y. 10018. (Formerly the United
States of America Standards Institute
lUSASI). All current standards issued
by USASI and ASA have been redesig-
nated as American National Standards
and continue in effect.)
(5) American Society for Testing and
Materials (ASTM), 1916 Race Street
Philadelphia, Pa. 19103.
American Petroleum Institute:
(i) API Standard 6O "API Specifica-
tion for Pipeline Valves." which 'may be
obtained from the Dallas office (1968.
1974).
Hi) API Standard 1104 "Standard for
Welding Pipe Lines and Related Facili-
ties" '1968, 1973).
'iii> API Specification 5L "API Spec-
ification for Line Pipe" < 1969. 1975).
i iv> API Specification SLS "API Spec-
ification for Spiral-Weld Line Pipe"
11969. 1975).
(v> API Specification 5LX "API Spec-
ification for High-Test Line Pipe" (1969.
1975).
12) ASMS Code is the American So-
ciety of Mechanical Engineers Boiler
and Pressure Vessel Code. Section VIII.
"Pressure Vessels. Division 1" ' 1968.
1974).
' 3 > Manufacturers Standardization
Society of the Valve and Fitting Indus-
* rv *
U> MSS Standard practice SP-48
"Steel Butt-Welding Fittings '26 inch
and larger) " < 1969).
MSS Standard Practice SP-63
"High Strength Wrought Welding Fit-
ting" i1969).
liii) MSS Standard Practice SP-75
"Specification for High-Test Wrought
Welding Fittings" (1973).
(4) American National Standards In-
stitute:
a) ANSI B16.9 "Factory Made
Wrought Steel Butt-Welding Fittings "
(1964. 1971).
(ii) ANSI B31.4 "Liquid Petroleum
Transportation Piping Systems" (1966,
1974).
(5) American Society for Testing and
Materials:
U) ASTM Specification A53 "Standard
Specification for Welded and Seamless
Steel Pipe" '1968. 1973).
(ii) ASTM Specification A106 "Stand-
ard Specification for Seamless Carbon
Steel Pipe for High-Temperature Serv-
ice" (1968. 1972a).
(iiii ASTM Specification A134 "Stand-
ard Specification for Electric-Fusion
(Arc)-Welded Steel Plate Pipe. Sizes 16
in. and Over" (1968, 1973).
(iv> ASTM Specification A135 "Stand-
ard Specification for Electric-Resist-
ance-Welded Steel Pipe" '1968. 1973a).
(v> ASTM Specification A139 "Stand-
ard Specification for Electric-Fusion
'Arc) -Welded Steel Pipe. (Sizes 4 in. and
Over)" (1968. 1973).
i vii ASTM Specification A155 "Stand-
ard Specification for Electric-Fusion-
Welded Steel Pipe for High-Pressure
Service" (1968. I972a>.
(vii) ASTM Specification A211 "Stand-
' ard Specification for Spiral-Welded Steel
or Iron Pipe" '1968. 1973).
(viiti ASTM Specification A333
"Standard Specification for Seamless
and Welded Steel Pipe for Low-Tem-
perature Service" '1968. 1973).
<«) ASTM Specification A381 "Stand-
ard Specification for Metal-Arc-Weided
Steel Pipe for High-Pressure Transmis-
sion Systems" <1969. 1973).
140 FR 43901. 49 CFR 1.S3) 134 TO 15473.
Oct. 4. 1989. u "amended by Amdt. 195-2.
35 FR 17184. Nov. 7. 1970: Amdt. 195-9. 41 PR
13592. Mar. 31. 1976!
$ 195.1 Acceptable petroleum romrnod.
iliro.
No carrier may transport any petro-
leum or petroleum product unless the oe-
troleum or petroleum product is chemi-
cally compatible with both the pipeline.
including all components, and any other
commodity that it may come into contact
with while in the pipeline.
355
-------
(13) Part G. Item I. State the com-
monly used name of the commodity, sucb
as fuel oil. regular gasoline, liquefied
petroleum gas. It the commodity name
Is one not commonly used, state the name
here and give a brief description of it
under "Account of Accident by Respon-
sible Official of Carrier."
(14) Part G. Item 3. State the year
facility was installed or the best estimate
possible. Pipe is excluded as the year of
installation Is required In Item 4 of
PartH.
(19) Part H. Mark appropriate boxes
and state Information required In all
items of ***« part only if the accident oc-
curred In line pipe. If the accident oc-
curred In any other part of the pipeline
system, omit this part.
(16) Part 1. Mark appropriate boxes
and state Information required In all
Items of this part if the accident was
caused by corrosion In any component of
the pipllne system. In Item 4. state the
length of time between the type of tests.
such as pipe-to-soil potential, stated In
Item 5.
117) Part J. Complete all three items
only If the accident was caused by equip-
ment rupturing the pipeline. In Item 2.
all the information stated on the closest
line marker must be shown.
(b) In addition to the requirements of
paragraph (a) of this section. In the
space provided after Part J. the carrier
shall enter an account of the accident
containing the most reliable Information
to which the carrier has access at the
time of reporting, sufficiently detailed
and complete to convey an understand-
ing of the accident. This account may be
continued on an extra sheet of paper If
more space is needed.
(c) At the bottom of the back of DOT
Form 7000-1. the carrier shall state the
name and title of the pipeline official
responsible for compiling and flllng the
report along with the telephone number
at which this official can be reached, and
the date the report was completed.
5 195.38 dinner* in nr n«lililion» to or.
ciJcnl report.
Whenever a carrier receives any
changes In the information reported or
additions to the original report'on DOT
Form 7000-1 tt shall immediately flle a
supplemental report with the Director.
Office of Pipeline Safety. Department of
Transportation. Washington. D.C. 20590.
[34 FH 15473. Oct. 4. 1969. as amended by
Amdt. 195-5. 38 7R 2978. Jan. 31. 19T31
§ 195.60 Carrier uuulance in investiga-
tion.
If the Department of Transportation
Investigates an accident, the carrier In-
volved shall make available to the rep-
resentative of the Department all rec-
ords and Information that In any way
pertain to the accident, and shall afford
all reasonable assistance in the investi-
gation of the accident.
$ 19S.62 Supplies of accident report
DOT Form 7000-1.
Sach carrier shall maintain an ade-
quate supply of forms that are a facsimile
of DOT Form 7000-1 to enable It to
promptly report accidents. The Depart-
ment will. upon request, furnish speci-
men copie* of the form. Requests should
be addressed to the Director. Office of
Pipeline Safety. Department of Trans-
portation. Washington. D.C. 20590.
[34 PR 15473. Oct. 4. 1969. as amended by
Amdt. 195-5. 38 PR 2978. Jan. 31. 1973)
Subpart C— Design Requirements
i 195.100 Scope.
This subpart prescribes minimum de-
sign requirements (or new pipeline sys-
tems constructed with steel pipe and for
relocating, replacing, or otherwise chang-
ing existing systems constructed with
steel pipe. However, it does not apply to
the movement of line pipe covered by
i 195.424.
§ 195.102 Design temperature.
Material for components of the system
must be chosen for the temperature en-
vironment In which the components will
be used so that the pipeline will maintain
Its structural integrity.
§195.104 Variations in pressure.
If. within a pipeline system, two or
more components are to be conaected at
a place where one will operate at a higher
pressure than another, the system must
be designed so that any component oper-
ating at the lower pressure will not be
overstressed.
§ 195.106 Internal «lesi<:n pressure.
(a) Internal desi?n pressure Tor the
pipe In a pipeline is determined In ac-
cordance with the following formula:
Ps Internal design pressure la poundj per
square Inch gauge.
356
-------
§ 195.O Transportation of certain com-
modities.
(a) Except for petroleum, petroleum
products, natural gasoline, and liquefied
petroleum gases, no carrier may trans-
sort any commodity n«i*«f the carrier
notifies the Secretary in writing, with
the information listed in paragraph
>b) of this section, at lean 90 days be-
fore the date the transportation is to
begin. If the Secretary determines
that the transportaion of the commod-
ity in the manner proposed would be
unduly hazardous, he will, within 90
days after receipt of the notice, order
the carrier. In writing, not to transport
ihe commodity in the proposed manner
until further notice. As soon as practi-
cable after Issuance of such an order.
the Secretary will initiate appropri-
ate action to determine whether and
tn a hat manner the commodity may be
transported without undue hazard.
The notice submitted to the Ad-
ministrator by the carrier must state the
chemical name, common name, hazard
classification determined in accordance
with Pan 173 of this chapter, properties.
and characteristics of the commodity to
be transported. It must also Include
design specifications, including mate-
rials used in construction of the pipeline
and the maximum operating pressures
for the pipeline through which the com-
modity is to be transported.
[34 FR 15473. Oct. 4. 1969. a* amended by
Amdt. 196-1. 35 FR 5333. Mar. 31, 1970: Aradt.
195-3.38 FR 2978. Jan. 31.1973 ]
3 105.8 Trn importation of ronnnodiliei
in pipeline! constructed with other
than steel pipe.
No carrier may transport any com-
modity through a pipe that Is con-
structed after October 1. 1970. of mate-
rial other than steel unless the carrier
has notified Che Secretary in writing
at least 90 days before the transporta-
tion is to begin. The notice must state the
chemical name, common name, hazard
classification (if any) determined in ac-
cordance with Pan 173 of this chapter.
properties, and characteristics of the
commodity to be transported and the
material used In construction of the
pipeline. If the Secretary determines that
the transportation of the commodity in
the manner proposed would be unduly
hazardous, he will, within 90 days after
receipt of the notice order the carrier, in
writing, not to transport the commodity
in the proposed manner until further
notice.
[Amdt. 195-1. 3S F.R. 5333. Mar. 31. 1970.
as amended by Amdt. 195-2, 36 F.R. 17184.
Nov. 7. 1970: Amdt. 195-5. 38 FR 2978. Jan. 31.
19731
§ 195.10 Rc»pon»ibililY of carrier for
compliance with ihu Part.
A carrier may make arrangements with
another person for the performance of
any action required by this part. How-
ever, the earner is not thereby relieved
from the responsibility for compliance
with any requirement of this part.
Subpart B—Accident Reporting
5 195.50 Scope.
This suupart prescribes roles govern-
ing the reporting of any failure in a pipe.
line system subject to this pan In which
there is a release of the commodity trans-
ported resulting tn any of the following:
(a) Explosion or fire not intentionally
set by the carrier.
(b) Loss of 50 or more barrels of
liquid.
(c) Escape to the atmosphere of more
khan five barrels a day of liquefied petro-
leum gas or other liquefied gas.
(d) Death of any person.
i e) Bodily harm to any person result-
ing tn one or more of the following:
(l> Loss of consciousness.
(2) Necessity to carry the person from
the scene.
<3> Necessity for medical treatment.
(4) Disability which prevents the dis-
charge of normal duties or the pursuit
of normal activities beyond the day of
the accident.
a) At the earliest practicable mo-
ment following discovery of a release of
the commodity transported resulting in
an event described in 3 195.30. each car-
rier shall give notice, in accordance with
paragraph 'b> of this section, of any
failure that—
11) Caused a death or a personal in-
jury requiring hospitallzation:
(2) Resulted in either a Ore or explo-
sion not intentionally set by the carrier:
'3) Caused estimated damage to the
property of the carrier or others, or both.
of a total of SS.OOO or more;
357
-------
strength in pound* p*r square
inch determined in accordance with
paragraph (b) of this station.
tsNomlnal wall tblcsness of to* pip* in
Inch**. If tali Is unknown. It Is deter-
mined in iHW^ft^nc^ with paragraph
Tne yield strength to be used in
determining internal design pressure us*
der paragraph (a) of this section is the
specified "'*Tl*'T'"rn yield strength. If the
specified minimum yield strength is not
known, the yield strength ia determined
by performing all of the tensile test* at
either API Standard 5L. SLS. or 5LX on
randomly selected test specimens with
the following number of tests:
Pip* tut ATwnocr of tot*
U**i than 8 laches in One test lor each
outside diameter. 200 lengths.
4 laches through 12% On* test for esar>
inches in outside 100 lengths
diameter.
Larger Chan 13% One test tor eaeb
inches in outside JO length*.
diameter.
U the average yield-tensile ratio exceeds
0.85. the yield strength of the pipe is
taken as 24,000 PJX If the average yield-
tensile ratio is 0.83 or less, the yield
strength of the pipe Is taken as the lower
of the following:
(1) Eighty percent of the average
yield strength determined by the tensile
tests.
(2) The lowest yield strength deter-
mined by the tensile tests.
(c) If the nominal wall thickness to
be used in determining internal design
pressure under paragraph (a) of this
section Is not known, it Is determined by
measuring the thickness of each piece of
pipe at quarter points on one end. How-
ever. If the pipe is of uniform grade, size.
and thickness, only 10 individual lengths
or S percent of all lengths, whichever is
greater, need be measured. The thickness
of the lengths that an not measured
i2> class designation or the maxi-
mum working pressure to which the
valve may be subjected.
<3> Body material designation (the
end connection material. if. more than
one type is used).
14> Nominal valve size.
(40 PR 43901. 49 CFR 1.33) (34 PR 15473.
Oct. 4. 19T9. as amended ay Anult. 199-2. 35
PR 17186. ITov. 7. 1970; Amdt. 195-3, 41 PR
13592. Mar. 31. 19781
§ 195.118 Fittings.
There may not be any buckles.
dents, cracks, gouges, or other defects In
> he fitting that might reduce thr
strength of the fitting.
(o The fitting must be suitable for
ihe Intended service and be at least as
strong as the pipe and other fittings In
the pipeline system to which It la
Attached.
140 FR 43901. 49 CPU 1.33) [34 PR 15473.
Oct. 4. 1989. as amended by Amdt. 195-9
41 PR 13592. Mar. 31. 1978)
S 105.120 Clumge* in ilirmiim: Provi-
sion for intenwl ptuwugr.
Each component of a main line sys-
tem, other than station and terminal
manifolds, that change direction within
the pipeline system must have a radius
of turn that readily allows the passage
of pipeline scrapers, spheres, and in-
ternal Inspection equipment
§ 195.122 Fabricated Itranrlt connw-
tions.
Each pipeline system must be designed
so that the addition of any fabricated
branch connections will not reduce the
strength of the pipeline system.
§ 195.124 Closures.
Each closure to be installed in a pipe-
line system must comply with the ASMS
Boiler and Pressure Vessel Code. Section
VHI, Pressure Vessels, Division l. and
must have pressure and temperature rat-
ings at least equal to those of the pipe
to which the closure is attached.
I4f '"R 43901. 49 CFH 1.53) [Amdt. 195-9.
..-•,« .».. ,, ,0-Tfil
359
-------
(4> Resulted In pollution of any
stream, river, lake, reservoir, or other
similar body of water that violated ap-
plicable water quality standards, caused
a discoloration of the surface of the
water or adjoining shoreline, or deposited
a sludge or emulsion beneath the surface
of the water- or upon adjoining shore-
lines : or .
< 5) In the judgment of the carrier.
was significant even though tt did not
meet the criteria of any other subpara-
sraph of this paragraph.
>t» Reports made under paragraph
'a> of this section are made by telephone
to area code 202, 426-0700 and must
include the following information:
1 1) Name and address of the carrier.
(2) Name and telephone number of
the reporter.
'3) The location of the failure.
(4) The time of the failure.
'5) The fatalities and personal in-
juries. If any.
(6) All other significant facts known
by the carrier that are relevant to the
cause of the failure or extent of the
damages.
(38 PR 7121. Mar. 18. 19731
S 1 1.".." I Accident reporting.
Each carrier that experiences an acci-
dent that is required to be reported
under this subpart shall, as soon as prac-
ticable but not later than 15 days after
discovery of the accident, prepare and
flle an accident report, on DOT Form
7000-1 or a facsimile, with the Director.
Office of Pipeline Safety, Department of
Transportation. Washington. D.C. 20590.
The carrier shall flle two copies of each
report and shall retain one copy at its
principal place of business.
[34 PR 13473. Oct. 4. 1909. u amended by
Amdt. 195-3. 38 PR 2978. Jan. 31. 1973 1
tnntntctinnn foe prvpncing DOT
Form 7000-1.
Each carrier shall prepare each
report of an accident on DOT form
Tnoo-l or a facsimile, in accordance with
the following instructions:
(1) General. Each applicable item
must be marked or filled in as fully and
as accurately as information accessible to
the carrier at the time of filing the report
will permit.
(2) Part A. Enter name as it Is filed
with the Interstate Commerce Commis-
sion. If the carrier's name Is not filed
with the Commission, enter the complete
corporate name of the carrier. Enter the
address of the carrier's principal place
of business Including zip code.
(3) Part S. Item l. Eater the data the
accident occurred or was discovered. If
the accident was not discovered on the
date It occurred, state this fact on the
back of the form.
<4) Part B, Item 2. Enter the exact
time la hours and minutes (La, 10:19) if
known or a time range 'i.e.. 10:11) if
exact time Is not known. If the accident
was not discovered on the date it oc-
curred, enter the time It was discovered
and state this fact, on the back of the
form as in Pan B. Item 1.
(5) Port B. Item 3. Eater all three
names. State, county, city, or town, la or
near which accident occurred.
(8) Part B. Item 4. Mark the appro-
priate box. If "other" is marked, state
clearly oa form what part of the pipe-
line system.
(7) Part B, Item S. If the accident oc-
curred in an uninhabited area, such as
woods, cultivated field, swamp, etc.. so
itate clearly oa the form under Item S.
If not. attach a sketch to the form show-
lag the part of the pipeline system where
the accident occurred, and the location
of the accident as related to significant
landmarks. Each Item shown on the
sketch must be clearly and distinctly
marked to identify It. Approximate dis-
tances from accident location to all land-
marks shown on the sketch must be
indicated.
(8) Part c. Mark the appropriate box.
or boxes. If applicable, mark more than
one box. If "other" is marked, state
clearly on form the exact origin of the
release of commodity.
(9) Part D. Mark the appropriate box.
If -other" Is marked, clearly state the
cause of the accident.
(10) Part S. Indicate a number under
each heading Including "0" If none. Re-
port deaths, even if previously reported
in accordance with } 195.52.
(11) Part r. Items 1 and. 2. Report
only material In the pipeline system that
was actually damaged such as pipe.
valves, or fittings. Do not Include cost of
commodity which was lost due to the
accident or fittings used during repair
which became permanently attached to
the system. The dollar value of damage
should be based on replacement at pres-
ent day costs.
<12) Part F, Items 3 and 4. This Is
damage to property other than that of
the carrier. Dollar value must be actual
or the best estimate available.
358
-------
41 PR 34040. Aug. 12. 1978. effective Aug. 1.
1977. For tne convenience of the user, the
superseded text is set out below:
r=A design (Mtor of 0.73. except that a
design actor of 0.54 U uaed for pipe)
that oae beea cold worked to meet
the «peeifled mlninmm yield strength
and is subsequently betted, other
than br welding, to 400* P. or mere.
S 195.108 External preMure.
Any external pressure that will be ex-
erted on the pipe must be provided tor in
designing a pipeline system.
§ I9S.110 External lowi*.
i
a) Anticipated external loads (e.g.),
earthquakes, vibration, thermal expan-
sion, and contraction must be provided
(or in designing a pipeline system. In
providing for expansion and flexibility,
section 419 of ANSI B31.4 must be fol-
lowed.
The pipe and other components
must be supported In such a way that
the support does not cause excess local-
ized stresses. In rf*««gm"g attachments
to pipe, the added stress to the wall or
the pipe must be computed and com-
pensated for.
:40 PR 43901. 49 CPB 1.S3) [34 PR 15473.
Oct. 4. 1909. ae amended by Amdt. 195-9.
41FH13S92. Mtr. 31. 1978 1
5 195.112 New pip*.
Any new pipe Installed in a pipeline
system must comply with the following:
(a) The pipe must be made of steel of
the carbon, low alloy-high strength, or
alloy type that Is able to withstand the
internal pressures and external loads and
pressures anticipated for the pipeline
system
' b> The pipe must be made In accord-
ance with a written pipe specification
that sets forth the chemical requirements
for the pipe steel and mechanical tests
for the pipe to provide pipe suitable for
the use intended.
Each length of pipe with an outside
diameter of 4 Inches or more must be
marked on the pipe or pipe coating with
the specification to which it was made.
the specified minimum yield strength or
grade, and the pipe size. The marking
must be applied In a manner that dees
not damage the pipe or pipe coating an and the following:
(a> The pipe must be of a known spec-
ification and the seam Joint factor
must be. determined In accordance with
I !9S.l06 or There may not be any—
(l) Buckles:
< 2) Cracks, grooves. Rouges, dents, or
other surface defects that exceed the
maximum depth of such a defect per-
mitted by the specification to which the
pipe was manufactured: or
(3) Corroded areas where the remain-
Ing wall thickness Is less than the mini-
mum thickness required by the toler-
ances in the specification to which the
pipe was manufactured.
However, pipe that does not meet the
requirements of subparagraph (3) of
this paragraph may be used if the oper-
ating pressure Is reduced to be commen-
surate with the remaining wall thickness.
134 P.R. 15473. Oct. 4. 198*. a* amended by
Amdt. 195-3. 38 P.R. J71SS. NOT. 7. 19701
5 19S.11* Vulvr*.
Each valve installed In a pipeline sys-
tem must comply with the following:
(a) The valve must be of a sound
engineering design.
Materials subject to the Internal
pressure of the pipeline system. Including
welded and flanaed ends, must be com-
patible with the pipe or fittings to which
the valve Is attached
d> Each valve must be both hvdro-
statically shell tested and hydrostatically
seat tested without leakage to at least
the requirements set forth in section 5 of
API Standard 6D.
>e> Each valve other than a check
valve must be equipped with a means for
clearly indicating the position of the
valve 'open, closed, etc.).
>t i Each valve must be marked on the
body or the nameplate, with at least the
following:
' 1> Manufacturer's name or trade-
mark.
360
-------
<2> Class designation or the maxi-
mum working pressure to which the
valve may be subjected.
<3> Body material designation (the
end connection material, it more than
one type is used).
14 > Nominal valve size.
(40 PR 43901. 49 CFR 1.53) [34 PR 13473.
Oct. 4. 19T9. aa amended sy AmUt. 195-2. 35
PR 17185. Nov. 7. 1970: Aradt. 195-9. 41 PR
13592. Mar. 31. 1978)
§195.118 Fittings.
ia) Butt-welding type fittings must
meet the marking end preparation and
the bursting strength requirements of
ANSI B18.9 or MSS Standard Practice
SP-75, except that fittings manufac-
tured, designed, or installed before July
1. 1976; may meet the requirements of
MSS Standard Practice SP-48 or MSS
Standard Practice SP-83.
There may not be any buckles.
(tents, cracks, gouges, or other defects In
the fitting that might reduce the
strength of the fitting.
The fitting must be suitable for
ihe Intended service and be at least ai
strong as the pipe and other fittings In
the pipeline system to which It U
attached.
(40 PR 43901. 49 CPR 1.53) [34 PR 15473.
Oct. 4. 1909. a* amended by Amdt. 195-9
41 PR 13592. Mar. 31. 19781
§ I OS. 120 Quiit ~e» in ilirmioni Provi-
sion for internal pannugr.
Each component of a main line sys-
tem, other than station and terminal
manifolds, that change direction within
the pipeline system must have a radlu*
of turn that readily allows the passage
of pipeline scrapers, spheres, and in-
ternal Inspection equipment
§ 195.122 Faliricaleil liranrli connec-
tions.
Each pipeline system must be designed
so that the addition of any fabricated
branch connections will not reduce the
strength of the pipeline system.
§ 195.124 Closures.
Each closure to be installed in a pipe-
line system must comply with the ASME
Boiler and Pressure Vessel Code. Section
Vin. Pressure Vessels, Division 1. and
must have pressure and temperature rat-
ings at least equal to those of the pipe
to which the closure is attached.^
140 PR 43901. 49 CPR 1.53) (Amdt. 195-9.
41 FR 13592. Mar. 31. 19161
§ 195.126 Flange connection.
Each component of a flange connec-
tion must be compatible with each othsr
component and the connection as a
unit must be suitable for the service in
which it is to be used.
§ 195.128 Station piping.
Any pipe to be installed In a. station
that Is subject to system pressure must
meet the applicable requirements of this
subpart.
5195.130 Fabricated auemblies.
Each fabricated assembly to be In-
stalled in a pipeline system must meet the
applicable requirements of this subpart.
§195.132 Above ground tank*.
Each above ground tank must be de-
signed to withstand the internal pres-
sure produced by the commodity to be
stored therein and any anticipated ex-
ternal loads.
Subpart 0—Construction
§ 195.200 Scape.
This subpart prescribes minimum re-
quirements for constructing new pipe-
line systems with steel pipe, and for
relocating, replacing, or otherwise
changing existing pipeline systems that
are constructed with steel pipe. However.
this subpart does not apply to the move-
ment of pipe covered by 5 195.424.
§ 195.202 Compliance with «pccific«-
tiona or stannania.
Each pipeline system must be con-
structed in accordance with comprehen-
sive written specifications or standards
that are consistent, with the requirement;
of this part.
§ 195.204 Inspection—general.
Inspection must be provided to ensure
the installation of pipe or pipeline sys-
tems'in accordance with the require-
ments of this subpart. No person may
be used to perform inspections unless
that person has been trained and is
qualified in the phase of construction
he is to inspect.
§195.206 Material inspection.
No pipe or other component may be
installed in a pipeline system unless it
has been visually inspected at the sit?
of installation to ensure that it is not
damaged in a manner that could im-
pair its strength or reduce Its service-
ability.
361
-------
§ 195.208 Welding of support* and
braces.
Supports or braces may not be welded
directly to pipe that will be operated at
a pressure of more than 100 pjj.gr.
§ 195.210 Pipeline location.
(a) Pipeline right-of-way must be
selected to avoid, as far as practicable.
areas containing private dwellings. In-
dustrial buildings. and places of public
assembly.
(b> No pipeline may be located within
50 feet of any private dwelling, or any
industrial building or place of public
assembly in which persons work, congre-
gate, or assemble, unless it is provided
with at least 12 inches of cover In addi-
tion to that prescribed in 3 195.248.
§195.212 Bending of pipe.
(a) Pipe must not have a wrinkle bend.
(b) Each field bend must comply with
the following:
(1) A bend must not impair the serv-
iceability of the pipe.
(2) Each bend must have a smooth
contour and be free from buckling.
cracks, or any other mechanical damage.
(3) On pipe containing a longitudinal
weld, the longitudinal weld must be as
near as practicable to the neutral axis of
the bend.
(c) Each circumferential weld which
is located where the stress during bend-
ing causes a permanent deformation in
the pipe must be nondestructively tested
either before or after the bending
process.
(40 FR 43901. 49 CFR 1.53) (Amctt. 195-10.
41 FR 26018. June 24. 1976)
§ 195.214 Welding: General.
(a) Welding must be performed In
compliance with this section and
5f 195.218 through 195.234.
• b> Welding must be performed in
accordance with established written
welding procedures that have been tested
to assure that they will produce sound.
ductile welds that comply with require-
ments of this subpart. Detailed records
of these tests must be kept by the ear-
ner involved.
§195.216 Welding: miler joints.
A miter joinc is not permitted mot in-
cluding deflections up to 3 degrees that
are caused by misalignment).
(40 FR 43901. 49 CFR 1.53)
41 FR 26018. Junt 24. 19781
I Amdt. 195-10.
§ 195.218 Welding! Seam offset.
Seams on adjacent pipe lengths must
be offset.
§ 195.220 Weld.: Filler metal.
Filler metal must be at least equal In
strength to the highest specified mini-
muni yield strength of the pieces being
welded and must fuse the pieces together.
§195.222 Welders: Testing.
Each welder must be qualified in ac-
cordance with one of the following edi-
tions of Section 3 of API Standard 1104:
(a) The 1973 edition, except that a
welder may be qualified by radiography
under subsection 3.51 without regard for
the standards in subsection S.9 for depth
of undercutting adjacent to the root bead
unless that depth is visually determined
by use of a depth measuring device on
all undercutting along the entire circum-
ference of the weld: or
(b) If a welder is qualified before
March 20. 197S. the 1968 edition, ex-
cept that a welder may not requalify
under the 1968 edition.
[Amdt. 195-3. 40 FR 10183. Mar. 5. 197S. aa
amended by Amdt. 19S-3A. 40 FR 27233.
Juna27, 19751
§ 195.224 Welding: Weather.
Welding mutt be protected from
weather conditions that would impair
the quality of the completed weld.
§ 195.226 Welding: Are burn*.
(a) Each arc burn must be repaired.
(b) An arc burn may be repaired by
completely removing the notch by grind-
Ing, if the grinding does not reduce the
r»m..
-------
in subsection 6.9 for depth of undercut-
ting adjacent to the root bead apply
only if—
(l) That depth is visually determined
by use of a depth measuring device on all
undercutting along the entire circumfer-
ence of the weld: and
(2) Visual determination of internal
undercutting is made in all pipe of the
same diameter in a pipeline, except
where unpractical at tie-in welds.
(Amdt. 19S-8A. 40 FR 27323. Jun* 27. 1973)
§ 195.230 Weld*: Repair of defect*.
(a) Except as provided in paragraph
of this section, a weld that is found
unacceptable under § 199.228 may not be
repaired unless*-
H) There are no cracks in che weld:
(2) The segment of the weld to be re-
paired was not previously repaired: and
(3) The weld is inspected after repair
to assure its acceptability.
(t» In the case of offshore pipelines, a
weld on a pipeline being installed from
a pipeiay vessel may be repaired if the
repair is made in accordance with es-
tablished written welding procedures
that have been tested under 3195.214 to
assure that they will produce sound
ductile welds.
(40 Pit 43901. 49 C7B 1J3) jArndt. 195-11
41 PR 34040. Aug. 12. 19781
§ 195.232 Weld*: Removal of defects.
Except for offshore pipelines being in-
stalled from a pipeiay vessel, a cylinder
of the pipe containing the weld must be
removed and the ends rebeveled when-
ever—
(a) The weld contains one or mom
cracks:
(b) The weld is not acceptable under
3195.228 and is not repaired: or
The weld was repaired and the re-
pair did not meet the requirements of
§ 195.228.
I 40 PR 43901. 49 CFR 1.53) |Amdt. 193-11.
41 FR 34040. Aug. 12. 19761
§195.234 Welds s Nondestructive test-
ing and retention of testing record*.
(a) A weld may be nondestructlvely
tested by any process that will clearly
indicate any defects that may affect the
integrity of the weld.
(b) Any nondestructive testing of
welds must be performed—
(1) In accordance with a written set
of procedures for nondestructive testing;
and
(2) With personnel that have been
trained is the established procedures
and la the use of the equipment employed
In the testing.
During construction, at least 10
percent of the girth welds made by each
welder during each welding day must
be nondestructlvely tested over the en-
tire circumference of the weld.
(e) In the following locations, 100 per-
cent of the girth welds must be non-
destructlvely tested:
(1) At any onshore location where a
loss of commodity could reasonably be
expected to pollute any stream, river.
lake, reservoir, or other body of water.
and any offshore area unless impractica-
ble, in which case only 90 percent of each
day's welds need be tested.
<2> Within railroad or public road
rights-of-way.
(3) At overhead road crossings and
within tiirtntf'a
(4) At pipeline tie-ins.
(5) Within the limits of any incorpo-
rated subdivision of a State government.
(6) within populated areas, including
but not limited to. residential subdivi-
sions, shopping centers, schools, desig-
nated commercial areas. Industrial
facilities, public institutions, and places
of public assembly.
When installing used pipe. 100 per-
cent of the old girth welds must be non-
destructlvely tested.
<«> A record of the nondestructive
testing must be retained by the carrier
who Is Involved. Including (if radi-
ography is used) the developed film with.
to far as practicable, the location of the
weld. This record must be retained for
3 rears after the line Is placed In
operation.
(40 PR 43901. 49 CPR 1.33) |34 PR 13473,
Oct. 4. 1969. u amended by Amdt. 195-1.
33 FR 5335. Mar. 31. 1970; Amdt. 193-11. 41
FR 34040. Aug. 12. 1978|
§ 193.236 Kxtcrnul corrosion protec-
tion.
Each component in the pipeline sys-
tem must be provided with protection
against external corrosion.
§ 195.238 External coating.
(a> No pipeline system component may
be buried or submerged unless that com-
363
-------
ponent has an external protective coat-
ing that—
(1) Is designed to mitigate corrosion
of the buried or submerged component;
<2) Has sufficient adhesion to the
metal surface to prevent underfllm mi-
gration of moisture:
(3) it sufficiently ductile to resist
cracking;
(4) Has enough strength to resist
damage due to handling and soil stress:
and
(5) Supports any supplemental ca-
thodlc protection.
In addition. If an insulating-type coating
is used It must have low moisture ab-
sorption and provide high electrical
resistance.
(b> All pipe coating must be inspected
just prior to lowering the pipe into the
ditch or submerging the pipe, and any
damage discovered must be repaired.
(40 PR 43901. 49 CFR 1J3) [34 PR 15473.
Oct. 4. 1969, a* uatnded by Amdt. 190-11.
41 PR 34040. Aug. 12. 1978)
§ 195.242 Calhodic protection iriiem.
(a) A cathodic protection system must
be installed for all burled or submerged
facilities to mitigate corrosion that
might result in structural failure. A test
procedure must be developed to deter-
mine whether adequate cathodic protec-
tion has been achieved.
i b> A cathodic protection system must
be Installed not later than 1 Tear after
completing the construction.
(40 FR 43901. 49 CFR 1.S3) |34 FR 1S473.
Oct. 4. 1969. H amended by Amdt. 193-U.
41 FR 34040. Aug. 12. 19781
§ 195.244 Test Icada.
'a) Except for offshore pipelines.
electrical test leads used for corrosion
control or electrolysis testing must be
Installed at Intervals frequent enough
to obtain electrical measurements Indi-
cating the adequacy of the cathodic
orntectlon.
(b) Test leads must be installed as
follows:
i'l) Enough looping or slack must be
provided to prevent test leads from being
unduly stressed or broken during back-
filling.
< 2) Each lead must be attached to the
pipe so as to prevent stress concentra-
tion on the pipe.
<3> Each lead Installed la a conduit
must be suitably Insulated from the
conduit.
§ 195.246 Inslallalion of pipe in a
ditch.
(a) All pipe installed in a ditch must
be installed in a manner that minimizes
the introduction of secondary stresses
and the possibility of damage to the
Pipe.
amended by Amdt. 195-11.
41 PR 34040. Aug. 12. 1976]
Zmcnvz DAT*: In i 196.246. the existing
text wt* designated at paragraph Less cover than the minimum re-
quired by paragraph (a) of this section
and $ 195.210 may be used if—
(1) It Is Impracticable to comply with
the minimum cover requirements; and
364
-------
(2> Additional protection la provided
that la equivalent to the inHttmnm re.
quired cover.
(40 FR 43901. 49 CFR 1.53) 134 FR 1S4T3.
Oct. 4. 1969. as amended by Amdt. 196-11.
41 PR 34040. Aug. 12. 1978)
DAT* NOTE: la i 199.248. para-
graph lai was revised by Amdt. 195-11 at
41 PR 34040. Aug. 12. 1978. effective Aug. 1.
1977. For the convenience of the user the
superseded test a an out below.
i at Unless specifically exempted in this
subpart. all pip* must be burled so that it Is
below the level of cultivation. Except as pro-
vided in paragraph end railraedf
Amy atfter we*.
M
30
M
It
' Rack acavation is any •seavatlan thai raqutfe*
MeMlns er raooval hy eoulvalent meanii.
5 IQS.250 Clearanrr hrtvern iiipr »n
underground .•trurturr*.
Any pipe Installed underground must
nave at least 13 Indies of clearance be-
careen the outside of the pipe and the
extremity of any other underground
structure, except that Tor drainage tile
the minimum clearance may be less than
12 Inches but not less than 2 inches Row-
ever, where 12 inches of clearance is Im-
practicable, the clearance may be re-
duced If adequate provisions are made
for corrosion control.
S 195.252 rUekiillinc.
Backflning must be performed In a
manner that protects any pipe coating
and provides firm support for the pipe.
3115.254 Abow ground romponmtn.
'a) Any component may be Installed
above ground In the following situa-
tJons. If the other applicable require-
ments of this pan are complied with-
a> Overhead crossings of highway*
railroads, or a body of water.
(2) Spans over ditches and gullies.
(3) Scraper traps or block valves.
<4> Areas under the direct control ol
the carrier.
15) In any area Inaccessible to the
pubUc.
fb> Each component covered by this
section must be protected from the
forces exerted by the anticipated loads.
5 195.256 Crnming of railroad* .and
highways.
The pipe at each railroad or highway
crossing must be Installed so as to ade-
quately withstand the dynamic forces
exerted by anticipated traffic loads.
5 105.253 VnKf*: Crf-twiil.
i at Each valve must be installed in a
location that is accessible to authorized
employees and that is protected from
damage or tampering.
< b) Each submerged valve located off-
shore or in inland navigable waters must
be marked, or located by conventional
survey techniques, to facilitate quick lo-
cation when operation of the valve is
required.
(40 FR 43901. 49 CFR 1.531 [34 FR 13473.
Oct. 4. 1989. as amended by Amdt. 195-11.
41 FR 34041. Aug. 12. 1978)
Emcnvx OATS NOTE: In $ I93.2S8. the ex-
isting text was designated as paragraph ia»
and paragraph* •. b I was added by Amdt. 193-
11 at 41 FR 34041. Aug. 12. 1978. effective
Aug. 1. 1977.
S 193.260 Vnl'rv: Lorn lion.
A valve must be installed at each of
the following locations:
(a) On the suction end and the dis-
charge end of i pump station In a man-
ner that permits Isolation of the pump
station equipment In the event of an
emergency.
'b> On each line entering or leaving
a tank farm in a manner that permits
Isolation of the tank farm from other
facilities.
On each mainline at locations
along the pipeline system that will mini-
mize damage or pollution from acci-
dental liquid discharge, as appropriate
tor the terrain in open country, for off-
shore areas, or for populated areas.
On each lateral takeoff from a
crunk line In a manner that permits
shutting off the lateral without Inter-
rupting the flow In the trunk line.
On each side of a water crossing
'.hat is more than 100 feet wide from
365
-------
high-water mark to high-water mark
unless the Secretary finds in a particular
case thac valves are noc justified.
On each side or a reservoir hold-
Ing water Tor human consumption.
140 FB 43901. 49 CFR 1.23) [34 FR 15473.
Oct. 4. i960, as amended by Amdt. 195-3.
38 FR 2973. Jan. 31. 1973: Amdt. 195-11.
41 FB 34041. Aug. 12. 19761
EFFCCOTK DAT* MOTS: In S 195.280. para-
graph id was revised by Amdt. 195-11 at
41 PR 34041. Aug. 12. 1978. effective Aug. 1.
1977. For the convenience of che user, toe
superseded text is sec out Below:
. • • . •
The following must be provided la
each pump station:
f 1) Safety devices that prevent over-
pressuring of pumping equipment. In-
cluding the auxiliary pumping equip-
ment within the pumping station.
(2) A device for the emergency shut-
down of each pumping station.
• 3) If power is necessary to actuate
the safety devices, an auxiliary power
supply.
Each safety device must be tested
under conditions approximating actual
operations and found to function prop-
erly before the pumping station may b*
used.
fd) Except for offshore pipelines
pumping equipment may not be In-
stalled—
' 1 > On any property that will not be
under the control of the carrier: or
<2> Less than SO feet from the bound-
ary of the station.
'e> Adequate fire protection must b*
Installed at each pump station. If the
flre protection system installed require*
the use of pumps, motive power must be
provided for those pumps that is sep-
arate from UK power that operates thr
station.
S 195.264 Above ground lank*.
(a) A means must be provided for
containing liquids In the event of spillage
or tank failure.
Tankage areas must be adequately
protected against unauthorized entry
(c> Normal and emergency relief vent-
Ing must be provided for each tank.
§ 195.266 Construction records.
A complete record that shows the fol-
lowing must be maintained by the carrier
Involved for the life of each facility:
(a) The total number of girth welds
and the number nondestructively tested.
Including the number rejected and the
disposition of each rejected weld.
(b) The amount, location, and cover
of each size of pipe installed.
(c) The location of each crossing of
another pipeline.
(d) The location of each buried utility
crossing.
(e) The location of each overhead
crossing.
(f) The location of each valve.
weighted pipe, corrosion test station, or
other Item connected to the pipe.
Subpart E—Hydrostatic Testing
AUfHomrr: The provisions of this Subpart
E Issued under sees. 831-835. Title 18. United
States Code: tees. 8 («)(4), (f)(3)(A). De-
partment of Transportation Act (49 U.S.C.
1855 (e><4). (DOHA)): 5 l.-Md) (8). Regu-
lations of the Office of the Secretary of
Transportation.
3ouxot: The provisions of this Subpart K
are contained In Amdt. 195-3. 35 VA 17185.
Nov. 7, 1970. unless otherwise noted.
§ 195.300 Scope.
This subpart prescribes minimum re-
quirements for hydrostatic testing of
newly constructed steel pipeline systems
and for hydrostatic testing of existing
steel pipeline systems that are relocated.
replaced, or otherwise changed. However,
this subpart does not apply to the move-
ment of pipe covered by 3 195.424.
§ 195.302 General requirements.
'a) Each new pipeline system, each
pipeline system in which pipe has been
relocated or replaced, or that part of a
pipeline system that has been relocated
or replaced, must be hydrostatically
tested in accordance with this subpart
without leakage.
(b) The test pressure for each hydro-
static test conducted under this section
366
-------
must be maintained for at least 24 hours
throughout the part of the system that
is being tested.
§ 195.304 Testing of component*.
(*) Each hydrostatic test under
319S.302 must test all pipe and attached
fittings, including components, unless
otherwise permitted by paragraph A component that is the only item
being replaced or added to the pipeline
system need not be hydrostatically
tested under paragraph of this sec-
tion if the manufacturer certifies that
either—
(1) The component was hydrostati-
cally tested at the factory: or
(2) The component was manufactured
under a quality control system that en-
sures each component is at least equal
in strength to a prototype that was hy-
drostatically tested at the factory.
9 19&306 Test medium.
ta) Except as provided in paragraph
(b) of this section, water must be used
as the test medium.
(b) Except for offshore pipelines, liquid
petroleum that does not vaporize rapidly
may be used' as the test medium if—
(1) The entire pipeline section under
test is outside of cities and other popu-
lated areas:
(2) Each building within 300 feet of
the test section is unoccupied while the
test pressure is equal to or greater than a
pressure which produces a hoop stress of
50 percent of specified minimum yield
strength:
(3) The test section is kept under sur-
veillance by regular patrols during the
test: and
<4> Continuous communication is
maintained along entire test section..
(S«c. 8. Pub. L. 89-870: 40 PR 43901. 49 CFR
1.53) [Amdt. 195-2. Nov. 7. 1970. u
amended by Amdt. 199-11. 41 FR 43152.
Sept. 30. 1978)
§195.308 Testing of tie-ins.
Pipe associated with tie-ins must be
hydrostatically tested, either with the
section to be tied in or separately.
§ 195.310 Records.
(a) A record must be made of each
hydrostatic test and that record must
be retained as long as the facility tested
is in use.
(b) The record required by paragraph
fa) of this section must inciude the re-
cording gauge charts, dead weight tester
data, and the reasons for any failure
during a test. Where elevation differ-
ences in the section under test exceed
100 feet, a profile of the pipeline that
shows the elevation and test sites over
the entire length of the test section must
be included. Each recording gauge chart
must also contain—
. (1) The carrier's name, the name of
the person responsible for making the
test, and the name of the test company
used, if any:
(2) The date and time of the test:
(3) The minimum test pressure:
(4) The test medium:
<5> A description of the facility
tested: and
18) An explanation of any pressure
discontinuities that appear on any chart.
Subpart F—Operation and
Maintenance
§ 195.400 Scope.
This subpart prescribes minimum re-
quirements for operating and maintain-
ing pipeline systems constructed with
steel pipe.
§195.102 General requirement*.
(a) Each carrier shall establish and
maintain current written procedures:
(1) To ensi're the safe operation and
maintenance of Its pipeline system In
accordance with this Part during normal
operations.
(2> To be followed during abnormal
operations and emergencies.
(b) No carrier may operate or main-
tain its pipeline systems at a level of
safety lower than that required by this
subpart and the procedures It Is re-
quired to establish under paragraph (a)
of this section.
fc) Whenever a carrier discovers any
condition that could adversely a.Toct the
safe operation of Its pipeline system it
shall correct it within a reasonable time.
However, if the condition Is of such a
nature that It presents an Immediate
hazard to persons or property, the car-
rier may not operate the affected part
of the system until it has corrected the
unsafe condition.
No carrier may operate any part
of a pipeline system upon which con-
struction was begun after March 31.1970.
or in the case of offshore pipelines lo-
cated between a production facility and
a earner's trunkline reception point, af-
367
-------
ter July 31. 1977, unless it was designed
and constructed as required by this part.
(40 PR 43901. 49 CTR 1.53) [34 PR 15473.
Oct. 4, 1963. as amended by Amdt. 195-1 1.
41 PR 34041. Aug. 12. 1976)
§ 195.-I04 Maps and record*.
(a) Bach carrier shall m«ft«faHn cur-
rent maps and records of its pipeline
systems that include at least the follow-
ing information:
(l) Location and Identification of all
major facilities.
<2) All crossings of public roads, rail-
roads. rivers, buried utilities, and. foreign
pipelines.
(3) The maximum operating pres-
sure of each pipeline.
(4) The diameter, grade, type, and
nominal wall thickness of all pipe.
(b) Each carrier shall maintain dally
operating records that indicate the dis-
charge pressures at each pump station
and any unusual operations of a facility.
The carrier shall retain these records
for at least 3 years.
(o) Each carrier shall also maintain
for the useful life of that part of the
pipeline system to which they relate, rec-
ords that include the following:
(1) The date, location, and descrip-
tion of each repair made to its pipeline
systems.
(2) A record of each Inspection and
each test required by this sunpart.
(34 P-R. 15473, Oct. 4. 1909. as amended oy
Amdt. 195-1. 35 PJL 5333. MmT. 31. 1970:
Amdt. 195-2. 35 KB. 17180, Nov. 7, 1970)
9 195.406 Maximum operating pressure.
(a) Except for surge pressures and
other variations from normal operations.
no carrier may operate a pipeline at a
pressure that exceeds any of the
following:
(1) The internal design pressure of
the pipe determined in accordance with
! 199.108.
(2) The design pressure of any other
component of the pipeline.
'3> Eighty percent of the test pres-
sure for any part of the pipeline which
has been hydrostatically tested under
Subpart E of this part.
•4> Eighty percent o£ the factory test
pressure or of the prototype test pressure
for any individually installed component
which is accepted from testing under
5 195.304.
(b) No carrier may permit the pres-
sure in a pipeline during surges or other
variations from normal operations to
exceed 110 percent of the operating pres-
sure limit established under paragraph
(a) of this section. Each carrier must
provide adequate controls and protective
equipment to control the pressure within
this limit.
[Amdt. 195-3. 35 PJL 17180. NOT. 7. 1970]
§ 195.408 Communication*.
Each carrier shall have a communi-
cation system that insures the trans-
mission of information required for the
safe operation of its pipeline systems.
§ 195.410 Lin« markers.
(a) Except as provided in paragraphs
(b) and of this section, each carrier
shall placs and maintain line markers
over each buried "«• in accordance with
the following:
(1) Markers must be located at each
public road crossing, at each railroad
crossing, and In sufficient number along
the remainder of each buried line so
that its location Is accurately known.
(2) The marker must state at least
the following: "Warning" followed by the
words "Petroleum 'or the name of the
commodity transported) Pipeline" Une markers are not required In
heavily developed urban areas such M
downtown business centers where—
(1) The placement of markers Is Im-
practicable and would not serve the pur-
pose for which markers are Intended:
and
'2) The local government maintain.
current substructure records.
(c) Line markers that have been In-
stalled before April 1. 1970. may be used
until Anrtl 1.1973.
td> Each carrier shall provide line
marking at locations where the Une is
above ground In areas that are acces-
sible to the public.
368
-------
3 105.412 Inspection of righu-of-way
»nd crmeinfcs umler nuvifable w»ler».
(a> Each carrier shall, at Intervals not
exceeding 2 weeks, inspect the surface
conditions on or adjacent to each pipe-
line right-of-way.
i b) Except for offshore pipelines, each
carrier snail, at Intervals not exceeding
5 yean. Inspect each crossing under a
navigable waterway to determine the
condition of the crossing.
5 195.414 Cullimlir prelection.
After March 31. 1973. no carrier
may operate a pipeline that has an ex-
ternal surface coating material, unless
that pipeline Is cathodicaUy protected.
This paragraph does not apply to tank
farms and buried pumping station piping.
ibi Each carrier shall electrically In-
spect each bare pipeline before April l,
1975. to determine any area* In which
active corrosion Is talcing place. The car-
rier may not Increase Its established
operating pressure on a section of bare
pipeline until the section ha* been so
electrically Inspected. In any area*
where active corrosion Is found, the car-
rier shall provide cathodlc protection.
Section 199.418 and 'g> applies to all
corroded pipe that Is found.
(e> Each carrier shall electrically In-
spect all tank farms and burled pumping
station piping before April 1. 1973. as to
the need tor oathodJc protection, and
cathodlc protection shall be provided
where necesnary.
(d> Notwithstanding the deadlines for
compliance in paragraphs (a), 'b), and
ic> of this section, this section does not
apply to offshore pipelines located be-
tween a production facility and a car-
rier's trunkiine reception point until Au-
gust l, 1977.
(40 ?R 43901. 49 CTR 1.53) [34 PR 15473.
Oct. 4. 1969. aa amended by Amdt. 195-2. 35
PR 17188. Nov. 7. 1970: Amdt. 195-11. 41 PR
34041. Aug. 12. 19781
EFTTCTTVT DATX NOTE: In s 195.414. para-
graph id) was added by Amdt. 195-11 at
41 FR 34041. Aug. 12. 1978. effective Aug. 1.
1977.
§195.416 External rorrcMton control.
(a) Each carrier shall, at Intervals
not exceeding 12 months, conduct tests
on each underground faculty in its pipe-
line systems that Is under cathodlc
protection to determine whether the
protection is adequate.
(b) Each carrier shall maintain the
test leads required for cathodlc protec-
tion In such a condition that electrical
measurements can be obtained to en-
sure adequate protection.
(c> Each carrier shall, at Intervals
not exceeding 2 months. Inspect each of
Its cathodlc protection rectifiers.
Each carrier shall, at Intervals
not exceeding 5 years, electrically in-
spect the bare pipe In Its pipeline system
that Is not cathodlcally protected and
must study leak records for that pipe to
determine If additional protection Is
needed.
'e) Whenever any buried pipe is ex-
posed tor any reason, the carrier shall
examine the pipe for evidence of external
corrosion. If the carrier finds that there
Is active corrosion, that the surface of
the pipe Is generally pitted, or that cor-
rosion has caused a leak. It shall investi-
gate further to determine the extent of
the corrosion.
(f) Any pipe that la found to be gen-
erally corroded so that the remaining
wall thickness Is less than the minimum
thickness required by the pipe specifica-
tion tolerances must either be replaced
with coated pipe that meets the require-
ments of this part or. If the area Is small.
must be repaired. However, the carrier
need not replace generally corroded pipe
If the opera tlr.g pressure Is reduced to be
commensurate with the limits on operat-
ing pressure specified In this subpart.
based on the actual remaining wall
thickness.
(g> If Isolated corrosion pitting Is
found, the carrier shall repair or replace
the pipe unless—
(I) The diameter of the corrosion nits.
Is less than.the nominal wall thickness
as measured at the surface of the pipe,
of the pipe: and
f2> The remaining wall thickness at
the bottom of the pits Is at least 70 per-
cent of the nominal wall thickness.
fh> Each carrier shall clean, coat with
material suitable for the prevention of
atmospheric corrosion, and. maintain
this protection for. each component In Its
pipeline system that Is exposed to the
atmosphere.
§195.118 Internal corrosion control.
(a) No carrier may transport any
commodity that would corrode the pipe
or other components of Its pipeline sys-
tem, unless It has Investigated the corro-
369
-------
sive effect of the commodity on th» sys-
tem and hma taken adequate steps to mit-
igate corrosion.
(b> If corrosion Inhibitors are used to
mitigate Internal corrosion the carrier
shall use Inhibitors In sufficient quantity
to protect the entire pan of the 'system
that the Inhibitors are designed to pro-
tect and shall also use coupons or other
monitoring equipment to determine their
effectiveness.
The carrier shall, at Intervals not
exceeding 8 months, examine coupons
or other types of monitoring equipment
to determine the effectiveness of the In-
hibitors or the extent of aoy corrosion
(d) Whenever any pipe Is removed
from the pipeline for any reason, the
carrier must inspect the internal surface
for evidence of corrosion. If the pipe la
generally corroded such that the remain-
Ing wail thickness Is less than the mini-
mum thickness required by the pipe
specification tolerances, the carrier shall
Investigate adjacent pipe to determine
the extent of the corrosion. The cor-
roded pipe mutt be replaced with pipe
that meets the requirements of this
part or. based on the actual remaining
wall thickness, the operating pleasure
must be reduced to be commensurate
with the limits on operating pressure
specified in this subpart.
134 PJL 15413. Oct. 4. 1909. u saonded by
Amdt. 196-1. 33 ML 8333. MM. 31. 1010]
8 195.420 Vnlv* nuintrnnnr*.
(a) Bach carrier shall maintain each
valve that Is necessary for the safe opera-
tion of Its pipeline systems in good work-
Ing order at all times.
(b) Kach carrier shall, at Intervals not
exceeding 8 months. Inspect each main
line valve to determine that it is function-
Ing properly.
ic) Each carrier shall provide protec-
tion for each valve from unauthorized
operation and from vandalism.
§ 19S.422 Pipeline repair*.
(a) Each carrier shall. In repairing ito
pipeline systems. Insure that the repairs
are made In a safe manner and are made
so as to prevent damage to persons or
property.
(b) No carrier may use any pipe, valve.
or fitting, for replacement In repairing
pipeline facilities, unless U Is designed
and constructed as required by this part
§ 195.424 Pipe
(a) No carrier may move any line pipe.
unless the pressure In the line section In-
volved Is reduced to not more than 50
percent of the maximum operating
pressure.
(b) No carrier mar move any pipeline
containing liquefied gases where mate-
rials in the line section involved are
joined by welding unless—
(1) Movement when the pipeline does
not'contain liquefied gases is Impracti-
cal:
(2) The procedures of the carrier
under 5195.402 contain precautions to
protect the public against the hazard in
moving pipelines containing liquefied
gases, including the use of warnings.
where necessary, to evacuate the area
close to the pipeline: and
(3) The pressure in that line section is
reduced to the lower of the following:
(1) Fifty percent or less of the maxi-
mum operating pressure: or
(11) The lowest practical level that will
maintain the commodity in a liquid state-
with continuous flow, but not lest- than
50 pj±t. above the vapor pressure of the
commodity.
(c) No carrier may move any pipeline
containing liquefied gases where mate-
rials in the line section involved are not
joined by welcUng unless—
(1) The carrier compiles with para-
graphs (b) (1) and (2> of this section:
and
(2) That Hn^ section is isolated to pre-
vent the flow of commodity.
[Amdt. 195-2. 39 PR 17185, Xov. 7. 1970. u
amended by Amdt. 185-7. 39 PR 18781. June
4. 1874]
§ 195.426 Semper and uphere ficilities.
No carrier may use a launcher or re-
ceiver that Is not equipped with a relief
device capable of safely relieving pres-
sure In the barrel before Insertion or
removal of scrapers or spheres. The car-
rier must use a suitable device to Indi-
cate that pressure has been relieved In
the barrel or must provide a means to
prevent insertion or removal of scrapers
or spheres If pressure has not been re-
lieved in the barrel.
9 195.428 Overpressure safety devices.
(a) Except as provided In paragraph
(b) of this section, each carrier shall.
370
-------
at intervals not exceeding 12 months, or
8 months in the case of pipelines used
to carry liquefied gases. Inspect and test
each pressure limiting device, relief
valve, pressure regulator, or other item
of pressure control equipment to deter-
mine that it Is functioning properly, is
tn good mechanical condition, w^ is mie
quate from the standpoint of capacity
and reliability of operation for the serv-
ice in which it is used.
(b> In the case of relief valves on
pressure storage vessels containing liq-
uefied gas. each carrier shall test each
valve at intervals not exceeding 3 years
I Amdt. 195-1.37 F.B. 18733. Sept. 18.1979]
§ 195.430 Firefighting equipment.
Each carrier shall maintain adequate
flrefighting equipment at each pump sta-
tion, terminal, and tank farm. The
equipment must be—
(a) m proper operating condition at
all times:
(b) Plainly marked so that Its Identity
as flrenghting equipment is clean and
(c) Located so that it is easily acces-
sible during a flre.
§195.432 Storage renal*.
Each carrier shall, at Intervals not ex-
ceeding 12 months, inspect each storage
vessel '<""i"rf*"g atmospheric ?nfl pres-
sure tanks).
§19&434 Sign*.
^sflli carrier *^*^ WWJM+^JM ffgtiit visi-
ble to foi public around each pumping
station, terminal, or tank farm. Each
sign must contain the name of the car-
rier and an emergency telephone number
to contact.
§ 195.436 Security of facilities.
Bach carrier shall provide protection
for **"h pumping station, terminal, and
tank farm and other exposed facility
(such as scraper traps) from vandalism
and unauthorized entry.
3 195.438 Smoking or open flame*.
Each carrier shall prohibit smoking
and open flames tn each pump station
area and each terminal or tank farm
area where there is a possibility of the
leakage of a flammable commodity or of
the presence of "•"""*hl* vapors.
371
-------
A. 2 FOREIGN - TRANSPORTATION OF LIQUIDS BY PIPELINE
Reference list of ligislation and regulations, standards, technical
requirements, codes of practice for design construction and operation of
oil pipelines in Western Europe80.
372
-------
TRANSPORTATION OF LIQUIDS BY PIPELINE (FOREIGN REGULATIONS)
CO
~-J-
CO
government legislation/regulations
- Law/Decree/Application order
= Pei mil or approval required
- Law ol 1976.07 3 on transport ol pioducu by pipe-lines
- Trade Rights Peimil (Oeslerreichische Gewerbeordnung) from
Ministry ol Trade
= Water flights Permit (WasseirechlsgeseK 1969. revised in I960)
from Provincial Authority lor each Province crossed
- Law ol 1965 04.12 on transport by pipus ol gaseous pioducls
and others
Royal Decree ol 1967.06. IS dealing with transportation by
pipeline ol liquid and/or liquefied hydrocarbons other than
those cited in the 1965 Law
- Royal Ducree of 1967.07. IS specilying security measures
to be taken during construction and operation ol installations
ol transportation by pipeline ol products affected by the
above decree.
- Operating peimil hom special inspectorate alter its
cifi tilication ol the completed installation
Pipelines are normally built in accordance with a declaration ol
"National Interest." according to:
• Finance Law of 1958.03 supplemented by
- Decree ol 1959.06 16 (and Ministerial circular dated
1961 09.14) which sels up Hie code lor "national interest"
pipelines
— Decree ol 1959.08.14 on salely regulations lor pipelines lor
liquid liydiocarbons or liquefied hydrocarbons under pressure
- "Anile" dated 19S9.10 I and modifying "arretes" of
1961 OB 11.1962 07 2. and 1966 1130 which sets
the salely code for liquid pipelines and liquefied petroleum gas
pipelines
Oecievol 1961 OH 1 modified by decree of 1967.12.10
lor the protection ol water catchments and location ol pro
lected areas
- Ministerial circulai dated 1970.06.29 on changing salely
category during operations
- Approvals Irom "Direction des Carburanls" (DICA), "Service
des Mines" and "Piefels" (local councils) lor design and
operations
Rel.
A1
B I
B2
B3
f-l
F2
F3
F4
F6
F6
standards
techn. requirements/code of practice
"Austrian Pipeline Code" issued by the
Austrian Association for the Mineral Oil
Industry, based on IP Coda, but not
acknowledged by the aullioriiies (Regeln
lur Bau und Betrieb von Ferntuitungen lui
Erdol und llussige Eidolprodukle 1964)
Minimum design standards, allowable stress, specilic limits for con
slruclion near lo water catchment areas embodied in Decree of
1967.07
"Rules and Regulations lor pipelines carrying liquid hydrocarbons •
and hydrocarbons liquefied under pressure", til 1968. by Ministry
of Industry. "DuecliondesCarburants" (DICA)
Tills document specifies the negociating piocuduies as well us the design
and construction criteria incoiporaled in the deciees and "arreles"
menliorMid
Common ptescr iptions apfilicaltle to lite
contracts ol public winks signed by the
government: "Fascicule 72 — Oil and Gas
Pipeline" put into ellect by decree dated
1968 1024
They desciibc the rules ol an generally
agreed by the pipeliners
Rei.
A2
F7
F8
-------
CO
>
c
E
j.
o
-
t
•o
it
|
z
government legislation/regulations
- Law/Decree/Applicalion order - Permit or approval required
* "Planning approval" lor *ach "Land" concerned (Verordnung
ganehmigungsbedurtlige Anlayen 4. August 1960) according lo
Chapter 16 and 24 of the Industrial Code (Gewerbeordnungl
« Permit requited lor pipelines transporting crude oil, gasoline.
diesel oil and fuel oil and other water endangering liquid or
gaseous substances
(Wasserhaushallsgeseu - WHC, 2nd amendment of 1964.08.6
' Water endangering substances as specilied by regulation
(Verocdnuna uber wasseigiilaludenda Siolte bei der tUldrderung in
Rohrleilungen. vom 19, Pezember 1973, BGB1I. vom 22. Dezem-
ber 1973 p. 1946)
'Water Right Permit (Wasseihaushallsgeseu • WHG
issued by "Land" authorities
No specific Law
- General approval Irom the Mimuy ol Economic Allairs
- Technical appioval from each ol the provincial authorities and
the local Councils (poldeis, dykes, etc.)
flel
0-1
02
D3
ilandardi
DIN 2413 10.6)
Sleet pipes, for-
mula lor calcula-
ling thickness of
pipes subjected
to internal pies-
stir* 1966 06 re
vised in 1970
and IMI iuuad
in 1972.06
DIN 17172 (0.6)
Steel pipes lor
pipelines for com-
bustible liquids
and gases, technical
specifications.
1966.10
techn.requuemanu/code of practice
Guidelines for pipelines lor lite trans-
portation of hazardous fluids:
a) "Richilinien liir Fernleitungen
lum belordern gefiihrdender
Fliissigkeilen" (REF), published
on 1968.12.6. This document was
revised and issued on 1971.109 22
asTRuFMI (see 0.4b|
b| "Technische Regeln liir brennbare
Fliissigkeilen" (JRbF 301) issued on
1971.10.22 as part of the technical
regulations telatud to combustible liquids;
TflbF issued in 1970 06
Amended by 1973 04 and 1974.02
Pipeline Code 1972 lor the construction
and operation ol pipelines lor the Hans
ponalion of gases and liquids with le-
quiremenls pul for walet protection (pijp
leidingcode 1972) published by the Provin-
ical Authorities ol South Holland,
1972.01.
Guidelines lor oil pipelines (Leidraad
voor Oliepijpleidingenl published in 1973
and prepared by a national comiuilltc on
storage ol dangerous substances (COGS).
National Pipeline Code for dyke crossing
under study by TAW (Technische Adviev
comrniisie voor de Walerkeringen)
Ref.
04
04
NL
NL
-------
GO
~~J
en
Pemui ut approval iec|uiied
government legislation/regulations
LuvWDecieti/AtHititaliuti oitlei
Nu specific Law
- Miimteiial Dcciee I9G6 07 12. revised on 1971.02.23
on technical standards tot pipelines carrying liquids and gas
acioss and parallel 10 railways, uamways and branch lines
- Pei mil loi construction and operation Irum Ministry of
Tiade and Industry on basis of a general decree of 1934 07.31,
"Rules loi Ihe Input, Refining. Storage and Distribution of
Mineral Oils"
Federal Law ill 1963 10.4, "Pipeline Installations lor the
.Tiamporlaliun of Liquid o< gaseous Fuels"
Application Order dated 1968.09. 1 1 of the above Law
- "Arrete" uf the Federal Council ol 1968.09. 1 1 on the
technical control of the installations ol pi|ieline
transput laliun
Ordinance til 106607.1 on safely rules lor the installation
ol pipeline lianspoilahon
- F edei at concession to build and opei ale a pipeline under the
1963 Fedei al Law subjected to Hie above I960 Ordinance on
salely lules
Pipe line! Act 1962 which empowers the Secietary of Slate
lor Energy to control all pipeline construction and operation.
other than thuse ol the Statutory Undertakings.
Land Drainage Act 1961
The Petroleum and Submarine Pipe lines Act 1975 empowers
the Secietary ol Stale for Energy to control the construction
and use ol pipelines in territorial and continental shelf waters,
other than a pipeline which has neither initial nor terminal
point wrilnn those waters
Coast Protection Act 1949
Continental Shell Act 1964
Town and Country Planning Act 1962, for that part of a
submarine pipeline above sea level ILWMOST). provided it is less
than 10 miles in length
del
F I
CHI
CH2
CH3
CH-4
UK I
standards
teclin. requirements/code ol practice
Design standards to be discussed with the authorities lui each piojeci
Specific technical standards embodied in Decree ol 1966 07 ANSI
B 31 A are commonly recognised.
"Regulations on the pipeline installations tor Hie transportation ol
liquid or gaseous fuels" dated 1971.04 30 Federal Board ol
Energetic Economy.
This document brings together the procedures and regulations
incorporated in the mentioned Fedcial legislation
British Standard Coda ol Practice No. CP 2010
"Pipelines" Pans 1 and 2
Institute ol Petroleum Model Code ol Sale Practice
Petroleum Pipelines • Part 6
BS 4616. Specification loi held welding ol caibon
steel pipelines
Ret
CH6
UK 2
-------
DEPARTMENT Of TRAMIPORTATIOM
PIPaiNE CARRIER ACCIDENT REPORT
tnstruc-
tions
A Carrier
nfomtiqr
B
Fine and
Location
of
Accident
i Origin oi
.iguid or
apor
te lease
) Cause of
Accident
E Death
or |n>ry
F
prcoerty
GGereral
nfonaticn
instruc-
tions — »
H
Occurred
Li* .
DIM
MBCET tunCAU «.
004R56ni
Complete ia duplicate. If ike apace provided (or ••)> qucalion ia net adequate, ellack aa additional
akccl. Definition of a reporuble accident ia elated ia ike Code of Federal HcguUlionn, Title 49,
dopier 1. Pert 195. File balk copie* of tkt* report oitkin IS dora after discover,, of ike accident
vitk ike Adaiiaialralor. Federal Railroad Adminiatraiion, Department of Trananonalion. Kaakiagloa.
D. C. 20591 (liefer: Sec. 19S.S4).Oeuiled iaatruciinaa for preparing tkia form are found ia Part 195
Specimen copica of ikia. form trill be xipplicd gpoa rcqiieal oilkoul ckarte. Additional copiea may
be reproduced uaing tka aanto formal an. conrietMAiiON AT POINT
n siiAicMr n «Ae
10. COVER, ir BELOW CHOUNO
NON-CMPLOYCES
• ITEMS 0«»ICCO
•* ITEMS OAtuCCO
I. ESTIMATED LOSS CUE 1' YEAH
ro ACCIDENT INSTALL
•Ao*n e
-<, » ,*., .„„ ,. ,». p,
»s *',-£,"' "s
G3ct"" H '•••• ^..u.i
r^ M.T /-.i.fii rn«*--.
SURE AT TIMC tLKAIICn 11. HO TiiME BICN A P4CS
ICNT Sfl HSI ON SYitC-1
TION OF '«• MAIIMJ4 !'• OAIE OF LAICST '1ST
IEST PKEUUU
NI« r«le
DOT form 7000-1 (8-69)
Figure A-l. DOT 7000-1 (Page 1).
376
-------
&w?£d by
terra* ion
Tauiumt
Kiiotirins
Fiselinr-
>• nrrc or CCMWKICX
a '
ST LINC MMKCft
a«.
^TTieiLif* IMM.II
r>Txjoic notccTiONl.
CJ ttt
O..
conation TUTS
i- IVfL U lei! i,,^
i- LtNCIM 0' 1IVI U.lM.i.fl
PAnOL ON itCIICH
or «ccioo.r or HCSKMSIO.I ornci-u. or OUMIU
J*t AM3 TITLE Of CMflltft
OFflCIM. FILING THIS UKMT
TTLtPnOwC NO- ('•^LU*K
UCA C**C|
CAtt
Figure A-2. DOT 7000-1 (Page 2)
377
-------
R«f
Austria A-l Sund*sges*tz von 3. Juli 1975 ub*r di* gcwerbsmaszige Seforderung von Gutern in Rohrlaitungen
(Rohrleitungsgesetz).
Ausgegeben.un31.Juli 1975-Nr. 411 p 1759- 1771
A-2 Fachv*rband d*r Erdblindustrie Oesterreichs.
"Regeln fur Bau und Betrieb von Ftrnleitungen fur Erdol und Flussige Erdolprodukte • 1964"
Belgium B-1 Loi du 12 Avril 1965 relative au. transport de produits gazeux tt autres par canalisations - Moniteur
Beige du 7 Mai 1965.
3-2 Ministere des Affaires Economiques et Ministere des Transports et PTT.
a. Deem Royal du 15 Juin 1967 Monittur Beige 137:118. 22 Juin 1967. pp. 6753-6754.
Extension d* certain** dispositions d* la loi du 12 Avril 1965 r*lativ* au transport da produits
gazeux tt autres par canalisations, au transport par canalisations d'hydrocarbures liquid** et/ou
d'hydrocarbures liquefies, autres que ceux vises par ('article ler, littera a, de cette loi.
b. Oecret Royal du 25 Juillet 1967 Moniteur Beige 137:169, S Septembre 1967, pp. 9312-9323.
Determination des mesures d* leeurite a prendre lors de I'ttablissement et dans Sexploitation des
installations de transport par canalisations d'hydrocarbures liquides tt/ou d'hydrocarburcs
liquefies, autres qu* ceux vises par ('article ter, littera a, de la loi du 12 Avril 1965, relative au trans-
port de produits gazeux « autrn par canalisations.
Franc* F-1 Loi d* Finance no. 58-336 du 29 Mars 1958 (article II).
Journal Official (J.O.) du 1 avril 1958 p. 3170.
F-2 Oecret nr. 59 645 du 16 Mai 1959 J.O. du 21 Mai 1959 p. 5178-5132. modifie par decret no. 66-550
du 25 Juillet 1966 (art 7 et 33) tt Circulate Ministerielle du 14 Septambre 1961 nr. 2.905
F-3 Oecret nr. 59-998 du 14 Aout 1959 J.O. du 23 Aout 1959 p. 3412.
F-4 Arrete du ter Octobre 1959 J.O. du 3 Octobr* 1959 p. 9SS7 tt arretes modificatifs du 11 Aout 1961
(art 24 liquides), 2 Juillet 1962 (art 49. liquides; art. 47, liquefies) et 30 Novembre 1965 (art 7,
18 tt 48. liquid**; art 10 *t 14, liquifies).
F-5 Oecret nr. 61-859 du 1 Aout 1961 J.O. du 5 Aout 1961 modifi* par d*cr*t nr. 67-1093 du 15
Oecembre 1967 J.O. du 10 Oectmbrt 1967.
F-6 Cireulair* Ministtricil* du 29 Mai 1970 (minister* du Oeveloppement Industrie! et Scitntifiqut,
Direction des Carburants) nr. 3145 en application du decrtt nr. 59-998 du 14 Aout 1959.
F-7 Minister* d* I"Industrie. Direction des Carburants "Legislation et Regtementation des Pipelines
i hydrocarburn liquid** ou liquifiit sous pression". Imprimerie National*. Paris, 1968, pp. 1-106.
F-3 March* d* CEtat March* d*s Travaux Publics.
Cahiw das prescriptions commune) "Fasciculi nr. 72: Oltoducs — Gazoducs" mis tn application
par decret no. 68.1003 du 24 Octobre 1968.
Germany 0-1 Gcwerbtordnung (GtwO) § 16 indtr Neufassung vom I.Juni 1960.
0-2 Vtrordnung ub*r di* Errichtung und den Bttritb von Anlagtn zur Lagtrung, Abfullung und
3cford*rung brcnnbarsr Flussigkaiten zu Land* (Vtrordnung ubtr brtnnbare Ftusjigkeiten -
VbF vom 5. Juni 1970 (BG8I. IS. 689). S 9 Abs. 1 nr. 4 und Abs. 2 und 13 Abs. 1.
0-3 Ge*etz zur Ordnung des Wasserhaushatts (Wassarhaushaltsgtsetz - WHG) vom 27. Juli 1957 (8G8I
1 S. 1110). zuletzt gtindtrt durch da* Gtsetz vom 6. August 1964 und vom 23. Juni 1970 (BGBI.
1 S. 305). § 19 a ff.
0-4a 8und*sminist*rium fur Arbeit, Bonn.
RFF: Richtlini* fur Ftrnleitungen zum Befordern gtfShrdtnder Flussigkeiten.
Bek. des 8MA vom 6. Oezember 1968.11 Ib4-3893.016-4940/68. Arbeitsschutz nr. 12/1963. pp.
347-365.
1- ^tfensnct 30
378
-------
0-4b Tacnnische Regain fur brennbare Flussigkeitan — TRbF - aufgestellt vom 0«utichen Aunchuts
fur brennbare Ftussigkeiten (DAbF) und veroffentticht vom Bundesminister fur Arbeit und
Sozialordnung im Bundesarbeitsblan, Fachteil "Arbeitsschutz" (nacfi der Allgemeinen
Verwaltungsvoncnnft zu § 8 dtr Verordnung ubtr brennbara Flussigkaiten— VbF-vom 12. Mai 1970).
TrbF 301 Richtiinie fur Ftmleitungan zum Befordem gefahrdender Flussigkeiten (RFF) Ausgafae
September 1971. Revised on 1973.04.9 and 1974.04.1.
0-5 DIN 2413 Stahlrohre. Berechnung dar Wanddicka gegen Innandruck. in dar Faming vom Juni 1972
OK 621.843.23: 669.14-462.
0-6 DIN 17 172 Stahlrahra fur Famlaitungan fur brannbara Fluaigkaitan und Gate. Technischa
Lieferbedingungan. Oktobar 1966.
Italy- 1-1 Oecreto Ministerial* 12 luglkj 1968 — Norm* Tecniche per gli attraversamanti ed i parallelismi di
condotta di liquidia a gaa eon linaa farroviaria, tranviaria at eon binari di raceordo. Gazetto
Ufficiala nr. 221 del 6 sattambra 1966. pp. 3-15.
Raviiad 23 faobraio 1971 - Gazatto Uffieiala dal 7 maggio 1971.
NatnarlandiNL-1 Provinciate Watantaat in Zuid-Holland. "Pliplaidingeoda 1972". Ijanuari 1972 • revuie 3. 1 januari
1974) eitan ta statlan aan pijplaidingan voor net transport van gassan an vlotutorfen mat batrakking tot
da Watamaatkundiga vailighaid.
Studiagroap Pifplaidingan voor gattan en vloaiitorfan.
NL-2 Commmia Optlag Gavaartijka Scoffan (COGS).
"Uidraad voor Oliapijplaidinoan" - 1973 publisnad by Ministry of Social Affairs (Directoraat-
Ganaraat van da Arbatd van hat Ministaria van Soeiala Zakan, Voorburg).
Swnzariand CH-1 Loi Fadaraladu4Avril 1969surlaiiratallationsdatran>portpareonduita$dacombustibl«ou
carburants liquidaf ou gazaux (loi sur In installatiora da tramport par conduitat). RO. 1964 95
CH-2 Ordonnancad'exacutiondu 11 Saptamora 1968 da la loi fadarala sur IM installations da transport par
cooduitas da combustibtai ou carburana liquidas ou gazaux.
RO. 196811621404
CH-3 Arrata du Contail Fadaral du 11 Saptambra 1968 concamant la survaillanca tachnigua das
installations da transport par conduitas. RO. 1968 1185.
CH-4 Ordonnanca du 1ar Juillat 1966 concamant las prescriptions da sacurita our las installations da
transport par conduitas. RO. 1966 497.
CH-5 Offtaa Ftdtr^l da I'Economia Enargiqua.
Prescriptions sur las installatiora da transport par conduitas da combustibles ou carburants
liquidas ou gazaux. Etat la 30 Avril 1971 pp. 1-71.
United UK-1 Her Majesty ^Stationary Office. London. Pipelines Act. 1962. 10 & 11 Eliz 2. CH 58. pp. 1-66
Kingdom
UK-2 British Standards Institution (BSD London. Coda of Practice for Pipelines. CP 2010.
Part 1 "Installation of pipelines in land" - 1966. pp. 1-22
Part 2 "Design and construction of steal pipelines in land" 1970. pp. 1-S6.
USA (For information)
ANSI: American National Standards Institute.
ANSI 8 31.4 "Liquid Petroleum Transportation Piping Systems".
API: American Petroleum Institute. New York.
API-SI; Specification for Line Pipe
API-5LX: Specification for high-test Line Pipe
API-SLS: Specification for spiral welded Line Pipe
API-1104: Specification for Field welding of pipelines
API-1105: Recommended Practice on construction of steal pipelines
Code of Federal Regulations
"Minimal Federal Safety Standards for Liquid Pipelines" related to transportation of
liquids by pipeline. (Part 195, Title 49 of ttie Code).
379
-------
APPENDIX B
PIPELINE MILEAGE DATA
ptp«lUtn» activity La ch« Ualud Seaui,
I, 1974 n JMMIT I. 1977
(Mil..)
Seme*
p|
Wyoming
Total
Total
In pi*c«
Jan. 1, 1974
I 759
124
I 352
Z 997
10 183
2 ISO
&
273
1 386
633
11 405
3 951
2 326
354
220
£/ 272
£/ 2 369
3 389
& 928
2 906
3 283
198
108
r/ 453
5 927
I 939
900
I 741
r/ 20 762
673
17
642
707
r/ I 048
'77
334
760
942
6,397
£/ 223,535
?i3
10
j.1
~ 16
597
24 , 006
Tocai
la olac*
Jan. 1, 1977
;<»3
3 071
10 352
2 396
3
2 024
633
10 914
4 552
4
-------
F«en»Uu» ptp,Unin« «rtvtey in ch. Unit.d Sucu
January 1, 1971 Co J.«a.ry 1, 1974
CMtU.)
State
Tool
Total
la plaea
Jan. 1, 1971
1 237
87
I 071
2 397
r/ 9 358
1 756
92
3
87
1 728
640
r/ 11 096
4 495
3 389
16 013
2 311
7 956
353
219
242
1 744
2 955
3 058
6 295
3 054
3 341
328
108
568
5 941
1 673
834
1 664
6 909
22 308
689
3 291
17
635
640
629
65 259
I 042
177
322
762
3 612
942
6.644
r/ 218,671
Mpe
H«v
421
35
272
565
717
275
213
184
6
1 254
283
376
500
3
1 296
94
156
107
435
562
127
149
189
2
1 139
74
70
63
420
1 401
11
87
71
78
1 436
39
3
129
41
644
13,957
laid
Second-
hand
101
4
9
408
760
236
3
4
72
635
1 310
834
1
1
11
297
106
78
336
188
182
2
38
1
223
247
113
123
292
12
162
37
1
3 429
504
11
3
548
1
136
12.326
?tp«
Cakatt
up
2
373
1 152
87
27
30
13
221
314
1 241
1 503
1 295
268
69
182
265
563
389
321
38
99
1 376
55
4
99
487
3 454
39
502
37
35
1
4 652
744
7
134
661
1
597
22,599
Total
In placa
Jan. 1, 1974
1 759
124
1 352
2 997
10 133
2 180
92
5
273
1 386
633
11 405
4 &29
3 951
15 907
2 326
3 791
354
220
347
3 929
3 099
3 389
6 928
2 306
3 283
198
108
472
5 927
1 939
900
1 741
6 965
20 547
" 673
17
669
642
707
65 472
1 341
177
334
760
3 540
942
6.897
Z2Z.3SS
381
-------
Petroleum pipelining activity in ch« United States,
January I, 19«8 to January 1, 1971
(Miles)
Seat*
Total
In place
Jan. 1, 1968
Pip* laid
Second-
hand
taken
up
Total
IB place
Jan. 1, 1971
1,121
Alaska .............................. 74
Arizona 1,064
Arkansas 2,334
California 9,336
Colorado 1,739
Connecticut ......................... 91
Delaware 3
Florida ............................. 35
Georgia 1,567
Idaho 639
IlUnol 10,707
Indiana 4,309
Iowa 3.169
Kansas 13,486
Kentucky 2,219
Louisiana 7,373
Mala* 544
Maryland and District of Columbia ... 235
Massachusetts ....................... 239
Michigan 3,797
Minnesota 2,909
Mississippi 2,356
Missouri 6,434
Montana 2,671
Nebraska 3,114
Nevada 331
Wev Hanpahire 109
New Jersey 545
Nev Mexico 5,333
Sew York 1,368
North Carolina 333
North Dakota 1,723
Ohio 7,168
Oklahoma 22,250
Oregon .««....«...«.....««••...«...«. 402
Pennsylvania ........................ 3,943
Rhode Island 17
South Carolina 567
South Dakota 575
Tennessee ...............•.....•••.•• 519
Taxas 60,316
Utah 1,362
7eraont 177
Virginia 307
Washington 672
Uest Virginia 3,714
Wisconsin S94
Wyoming 5.883
Total 209,478
258
641
153
1
2
165
1,262
386
753
1,753
93
1,015
3
562
46
758
112
497
422
2
304
23
1
37
687
1,313
286
212
74
65
112
6,978
45
18
155
99
346
957
22
20
9
43
402
125
50
129
1
91
23
3
236
6
322
8
1
28
129
14
5
162
22
3
27
329
68
5
6
81
392
1
171
1
1
1
2,306
6
1
147
2
225
12
2
238
711
261
133
1,041
223
33
1,462
107
954
202
17
26
744
70
236
276
217
11
1
6
1,023
286
3
157
1,027
1,647
1,035
1
7
3
4,841
371
66
348
421
87
1,071
2,397
9,368
1,756
92
3
87
1.728
640
11,019
4,493
3,889
16,013
2,511
7.95*
353
219
242
3,744
2,953
3,058
6,295
3,054
3,341
328
108
548
5,941
1,673
834
1,664
6,90*
22,308
60*
8,291
17
635
640
S29
65,259
1,042
177
322
7«2
3,512
942
5.644
20,748
6,630
18,252
218,604
382
-------
Petroleum pipelining activity in Che United States,
January 1, 1974 to January 1, 1977
(Miles)
Size
(inches)
3
4 I/
6 11 .-
3
10
12
14.
16 ;
18
20......
22
24
Over 24. .......................
total
Gathering Lines
Nev pip*
laid
793
571
1,550
321
486
120
130
4
7
2
2
6
4,492
Secondhand
pipe laid
416
551
1,250
529
414
192
252
" 5
5
42
3,656
Pipe
taken up
2,131
1,890
3,105
1.133
1,018
177
54
12
27
9,597
Crude-oil trunklines
New pipe
laid
6
4
153
435
381
773
257
198
17
386
14
723
1,063
4,910
Secondhand
pipe laid
6
13
265
462
699
123
207
7
250
34
58
414
51
96
2,690
Pipe
taken up
28
33
502
1,047
2,701
578
491
16
141
33
165
33
1
59
5,878
Size
(inches)
2.
3,....
4 l/
5 2/
g ..
10
14
16
18
20
22
24
Over 24
Total
Products trunklines
New pipe
laid
7
48
276
2,350
2,673
1,623
703
255
157
59
139
209
8,499
Secondhand
pipe laid
10
11
235
535
304
947
660
295
106
15 .
31
23
68
3,290
Pipe
taken up
48
117
436
2,156
3,113
1,224
672
519
140
49
4
3
8,531
Total all pipelines
New pipe
laid
806
623
1,979
3,606
4,040
2,516
1,090
259
362
76
527
16
723
1,278
17,901
Secondhand
pipe laid
432
580
1,750
1,576
1,417
1,262
1,119
307
361
49
39
414
74
206
9,636
Pipe
taken up
2,257
2,040
4,093
4,336
6,832
1,979
1,217
535
281
132
131
33
1
39
24,006
I/ Includes a small amount of 5-inch pipe in trunklines.
2/ Includes a small amount of 7-inch pipe in erunklines.
383
-------
-Petroleum pipelining activity in the United States,
January 1, 1971 to January 1, 1974
(Miles)
Size
(inches)
3 ......................
4 i/
6 1l
8 ......................
10 .....................
12
16
18 .....................
20 .....................
22 .....................
24 .....................
G
New pipe
laid
488
423
1 287
1,1.01
505
337
97
185
2
4
1
1
4
3 334
*thering line
Secondhand
pipe laid
1 024
1 028
2 305
336
910
66
• 10
1
.
^
5 680
*
Pipe
taken up
2 428
1 597
3 674
1 899
817
95
363
_
7
—
10 880
Cru
New pipe
laid
16
54
I T e
689
717
167
718
136
103
46
157
28
3
130
3 079
de-oil trunkl.
Secondhand
pipe laid
Q
290
•J^O
4O£
1 im
155
9f)A
120
44
6
SI
32 .
3 120
Lnes
Pipe
taken up
62
207
9AA
1 027
1 149
837
109
185
1
in«
57
26
59
5 092
Size
(inches)
4 i-/
6 2/
12
14
16 .....................
18 .....................
22
24 .....................
Over 24
Total
Products trunklines
New pipe
laid
8
298
136
1,133
2,539
1,034
509
358
263
260
172
334
7,544
Secondhand
pipe laid
16
63
290
553
474
660
30
156
269
110
905
3,526
Pipe
taken up
22
201
322
1,850
2,425
450
914
169
142
2
116
14
6,627
Total all pipelines
New pipe
laid
512
775
1,538
2,327
3,593
1,298
1,412
496
370
306
330
29
3
968
13,957
Secondhand
pipe laid
1,049
1,381
2,867
1,485
2,691
881
246
156
390
44
116
83
937
12,326
Pipe
taken up
2,512
2,005
4,240
4,776
4,063
1,694
2,114
278
327
3
431
57
26
73
22,599
_!/ Includes a small amount of 5-inch pipe in trunklines.
2j Includes a small amount of 7-inch pipe in trunklines.
384
-------
•Petroleum pipelining activity in the United States,
January 1, 1963 to January 1, 1971
(Miles)
Siza
(inches)
3 l/
4 f/ :::::::::::::
6 3/
12 ...............
16 ...............
20
Over 24
Total
G
Hew pip*
laid
696
580
1 664
573
99
38
9
37
.
3,746
•athering line
Secondhand
pipe laid
32
259
1 605
139
370
19
184
1
_
2,659
a
Pin.
taken up
1,633
1 653
3,394
1 448
595
31
50
43
^
— .
.
9,397
Cru
Hew pipe
laid
106
71
908
1 380
348
558
790
18
342
336
5
7
1.646
7,015
de-oil tnrafcl
Secondhand
pipe laid
53
40
451
513
445
113
225
22
17
11
36
2 '
3
9
1,990
ines
Pipe
taken up
12
48
344
1-355
1,549
1 002
197
17
70
1
147
2
3
17
4,764
Size
(Inches)
2 ................
3 I/ .............
4 2/
6 3/ .............
14 ...............
16
22
24 ...............
Total ..........
Products txunklines
New pipe
laid
42
31
553
2,012
2,791
1,622
1,590
211
465
95
91
434
9,987
Secondhand
pipe laid
128
121
237
183
714
118
59
106
110
23
4
178
1,981
Pipe
taken up
90
221
438
1,465
693
142
106
5
413
136
263
119
4,091
Total all pipelines
New pipe
laid
344
732
3,125
3,965
3,738
2,268
2,389
229
344
95
427
5
7
2.080
20,748
Secondhand
pipe laid
263
420
2,293
835
1,529
250
468
123
128
34
90
2
3
187
6,630
Pipe
taken up
1,735
1,922
4,676
4,268
2;837
1,225
353
22
525
137
410
2
3
136
18,252
II Includes a. small amount of 2-inch pipe in trunklines.
y Includes a small amount of 5-inch pipe in crunklines.
T/ Includes a small amount of 7-inch pipe in trunklines.
385
-------
•Mileage of gathering lime .In ch« United Statee M of January 1, 1971
(Hllee)
State
Total Jan. 1, 1971 ....
Total Jan. 1, 1968 ....
Size (Inches)
2
Z
239
78
22
653
224
748
923
393
33
121
91
12
67
310
11
991
2,639
2,039
2,368
2,187
72
14.463
13,318
3
90
180
19
1,134
331
1,377
318
89
174
39
177
10
268
113
91
391
2,197
632
2,672
I
330
91
11.166
11,980
4/
18
437
396
101
1,360
202
2,707
466
612
266
257
209
99
2,125
7
266
333
4,339
197
12,237
43
239
609
27.769
28,394
6 y
9
48
1,001
113
232
26
677
201
440
48
82
270
206
387
12
39
143
2,084
27
4,317
43
194
479
11.280
12,016
8 I/
11
10
486
96
67
495
34
305
11
52
16
61
229
7
1
668
1
1,884
22
3
157
4.716
4,842
10
1
204
29
35
2
135
2
•
12
110
325
9
8
872
846
12 3/
•
<*
27
1
•>
61
311
2
1
5
•
274
73
5
32
794
611
Over
12 -
2
3
I
45
13
8
72
117
Total
Jan. 1,
1971
40
843
2,574
334
3,496
783
6,100
2,145
2,330
532
388
764
388
3,293
19
432
407
1,363
12,331
2,916
24 ,086
125
3,173
1.548
71.132
-
Jan. 1,
1968
18
776
2,722
346
3 ,720
916
6,934
2,198
2,493
1,027
466
746
581
3,224
550
482
1.854
12,544
3,419
23,704
290
3,275
1.639
—
74,124
I/ Ineludaa a mall Mount of 3-lnch pip*.
2/ Ineludaa a null amount of 7-Inch plpa.
I/ Ineludaa a sail nount of 11-inch pip*.
386
-------
of lathartai llaaa U tha Daltad Itaeaa aa ot
OU.lt.)
I, 197*
staca
Wymlnt
Total January 1, U74 «...
Tocnl January I, 1971 ....
lUa (lath**)
2
2
•
284
131
6
164
164
751
319
306
35
102
7i
5
133
169
11
1,001
2,234
2.048
2.3S1
2,104
49
13,547
14 ,'>63
3 .
2
118
220
60
998
275
1,429
445
111
207
49
187
17
312
US
94
384
2,060
616
2,615
1
S40
165
11,020
11,166
: *v
28
4
588
545
155
1,146
180
2,713
423
788
400
221
260
100
2,063
6
278
323
1,644
193
12,660
48
218
703
27,687
27 ,7(9
«_a/
22
4
61
878
118
3
203
17
719
405
60
57
322
177
12
537
82
146
1,395
27
4,227
47
174
509
10,222
11,280
«2/
11
•
10
457
65
6
26
484
161
315
26
14
13
51
7
206
13
1
414
1
2,534
21
1
265
5,146
4,716
10 */
•
23
•
1
202
4
29
30
31
133
2
12
133
•
305
9
2
940
872
12
*
24
5
1
61
144
2
1
5
260
86
5
32
•26
754
Ov«r
12
•
•
3
1
1
41
12
•
16
78
112
Total
Jan. 1,
1974
65
23
8
1,062
2,460
434
13
2.967
636
6,207
1,880
2,247
728
459
861
350
19
3,288
490
478
1,855
10 ,.162
2,883
24,794
131
3,019
1,725
69,266
-
Jan. 1,
1971
40
•
*
943
2,574
154
3,496
783
6,100
2,145
2,330
332
588
764
368
19
1,291
412
407
1,861
12,331
2,916
24,066
123
3,173
1,548
—
71,132
IiicluUui t niMll umme of 5-lncli nlna.
2l Iiicluuim a ttwill amaunc of 7*inuh iiipo.
T/ Ineiuila> a null mount at 9-lnch pip*.
4/ Includai « nail uount of 11-laeh plpa.
387
-------
Mllaaia of lUhMloc llM* In MM Uoltad SUM* •• of January 1, 1977
(MllM)
Seat*
local January 1, 1977...
Tocal January I, 1*74...
Slia (lacuna)
2
342
2M
26
45*
126
561
749
300
33
111
49
5
111
277
11
810
l.MO
1.913
2,439
1,MS
56
12.S7S
13,347
3
127
230
73
902
226
1,337
410
134
316
40
129
17
312
46
63
241
1,906
461
2,637
1
364
170
10.232
11,020
4V
19
566
566
167
1,269
171
2,819
393
739
463
190
301
too
2,129
7
304
249
3,163
173
12,111
44
209
760
27,362
27 ,667
«!/
21
53
696
121
9
210
18
818
539
82
11
319
176
319
94
106
1,432
17
4,189
60
119
574
10,423
£'
10,210
«!/
21
474
66
6
31
630
118
468
47
50
46
32
221
13
42
497
1,877
21
'3
268
5.021
£5.11,
10 y
182
4
29
38
208
43
2
56
73
423
9
2
1,075
940
12
11
10
1
151
336
20
2
3
41
229
88
3
31
934
626
Over
12
3
2
2
10
25
•11
37
112
78
Total
Jan. 1,
1977
40
21
1,090
2,691
490
19
2,898
541
6,400
1,692
2,776
1,037
421
846
330
3,615
330
507
1,311
9,226
2,566
24,023
138
2,683
1.863
67,796
-
Jan. 1,
1974
65
23
. 8
1,062
2,460
414
13
2,967
636
6,207
1,880
2,247
728
439
861
330
,.JL
490
478
1,853
10,162
2,885
24,794
131
3,039
1.725
_
69.247
lacludna a Mall aanune ot 5-lnch pip*.
Incluoaa a anall aaount of 7-Lnch pip*.
I/ Include* a anall aaoune of 9-iaeh plpa.
4/ lacludaa a Mail anount of 11-Inch pipa.
11 taviaad.
388
-------
AUb-.
T><|>M .%»•••••>•»••«•«••••«•••••• •••
JoUnn** w« MMrtw *4 CaliiMi ...
""""""" •
•M VMk *••••*•••*•••*»•••*••••••*••
itorth CoMllM **..*..*...•*.«.•.....
MMffc Dvtoc* •••*•••••••••••*•••••*••
OM* • ••on ••••••••• •••••••• ••
foMwvlmiU •••••••••••**•••*••••*••
SflMh talWW ••••••••••••••••••••••••
t»«il J«M«*y 1. I9tt
i> t^u^ » ~u .•MM .* i.uar
I/ lMl*«M • Mil II !•»! W 7-tMk
4
-
-
-
.
»
*
•
1
*
It
I
>
u
•
M
Ul
Hn>
m*
»V
•
Ul
-
u
9
1
Ml
M
1*
•
I
11
I
11
Ul
w
•
1
1
- ...
1,4 It
*v
1*
m
31
*M
rt
«
i«
1.4H
MT
jSfc
It
IM
ts«
i»
Itt
' u
in
Mt
Ul
11
•M
,.,«
5*4
It
54
It?
U Til
It. Ml
•
M
Ml
Jf
Ml
U
34*
1.009
I. IS*
m
»
t»
471
Mi
M
X.UJ
nt
»
in
141
131
l,J«3
4tff
l.M*
54
ISS
„ 4)^
il.ui
I*
u
IM
US
4
3?
Itt
T*
454
III
|
Ul
•
m
•u
ti
in
IN
1H
TM
Wl
as
i«
tu
l.M*
I
1]
U
tot
, ,„
1,111
U
»«I
a*
9U
IN
K
1«
100
IM
tn
M
u
IM
III
tu
1
41
71
U
)St
4»
IM
10
11
t.JTt
1
10*
H
41
1 712
1.109
Mo (
U
-
•
ITS
•
140
Ml
.
^
-
.
•
»
M
IM
M
1
no
lot
JOS
no
Ul
.
I Ul
1,1»
UOMt
u
1
1
it
•
•
.
IM
H
.
IM
U
uo
u
4«
1
U*
.
•
u
14
111
71
I 401
1.441
U
110
•
m
"
11
!
Ul
-
Ill
t
»
»
,
tu
.
•
H
»
.
.
„
.
fit
«7
»
•
m
•
•
.
m
Ul
•
"
70
-
H
.
77
.
•
ft
.
.
.
.
90?
1.9M
11
-
•
.
•
•
.
-
,
.
•
*
•
•
.
m
m
•
.
•
.
9
.
.
.
*j
9
H
(•«
•wr»
190
-
m
-
i
111
.
Ml
10
too
II
14?
17!
m
170
110
110
.
2.171
1.410
T.
M. 1,
im
l.Ul
»K
Ml
l.Ht
4M
11
1
17
1.710
440
1.J11
1.147
M
i.ni
IM
IM
Ml
1.410
l;m
1.110
IM
Ht
i.ai
•»
410
1.J1
1,41
M<
4,011
17
41
440
14i
ll.OH
11
»
74
«44
trll
72.404
Ul
J~. t.
I MO
1,041
4H
Ml
1,40)
SOI
(I
1
11
I.J47
411
2,111
1,101
4f
l.OM
in
in
in
1.271
111
1.021
m
Ml
t.uo
I1J
401
1.J11
1,100
401
4,017
17
147
17J
US
10.400
400
Ml
4M
7
444
I.Mt
w.m
389
-------
Mta«M •> infcil rtnllftm to H» MUM IMm. M •€
(llllMl
IU» (IllHil)
4V
•V
m, I,
19M
Maw* .
rteu* ..
iMlilim ............
MlM .....•.•...••...
l»l|ll«« •* HKMM
HtnlMtffl .
miMM ....
1.1»
i,«i
1,177
47
IM
M
171
m
197
100
It
i
IN
4T>
n
701
000
II
1.14,
I
lit
1,111
n
n
in
i
71
n
t
M
M
Mt
7U
m
1.J00
i.itt
1,491
1.441
M
n
140
I.M
Ul
174
1
U0
IM
79
4U
l»
111
1.117
441
IM
710
409
•11
U
U
,.».
I.4U
It
Mt
1.077
1.9M
919
It
I
m
1.0H
ID
4,199
1,171
1,191
1.J17
100
t.m
in
no
»7
i.iw
i.m
}'.m
MO
7,791
IM
III
1,101
1.140
900
477
l.JOl
4.011
4n
1.M9
17
MO
Ml
Ul
11.100
Ml
IM
m
»
1.141
I
17
1,710
1.444
1,310
1.M7
5.970
m
lit
74t
1,410
1.771
1,111
1,110
l.Otl
t.l»
in
Mt
1.391
1,1*0
IM
410
1.111
1,491
4,0»
17
111
440
Ml
11.0M
111
in
711
•
J"
J™
1,090
1/141
u,;n
7I.IM I/ 9.791
I.7W
l,4tl
f 1,171
17, JM
tnteM • <«ll i
390
-------
of product pip«Un*s in the Unit** State*. •• of January L, 197?
Sc»ta
Maryland ad District of Colu^ia..
2*~v*
UT°-lnt
Total January 1. 1977
Total January 1, 1974
Sin (Inchai)
2
12
1
2
8
1
1
1
Z
2
41
54
123
lit
}
44
272
11
2
40
1
2
7
]
24}
2
1
930
«•.
4 I/
5
34
103
12
6
•0
22
133
3*
267
21
14
4
17
t
1
107
17
14
41
J21
2
63
1.275
2
I
60
11
2,895
EZ.»70
6 2/
'3*
t
173
38
403
447
22
112
197
277
396
1,331
1,4*2
41
516
123
60
17«
407
337
t
lit
82
1,044
90
tw
3M
3M
143
82
S19
7M
61
1,326
14
»
329
3.649
9
55
156
249
71
527
17,565
r/
nt,7«»
t
95
2
242
56
945
87
1
712
55*
1,370
746
1,643
2,931
10
571
24
9
459
•77
1,431
399
1 ,03»
141
41
7»4
390
237
194
1,377
1.894
343
1,223
240
91
249
4,441
299
135
174
lit
172
692
27,193
«|7.»
10
30
74
403
470
162
7
123
320
79
646
617
314
1,306
1
493
167
109
1,526
443
39
13
163
197
109
220
70S
516
329
104
19;
1,789
5
13
14
109
171
11,939
r/
~10,612
12
402
2
292
249
323
64
254
667
236
923
713
315
37
24
229
291
522
299
152
2
37
69
19
609
901
213
10
22
32
1,521
2
109
23
40
9,394
£8.703
14
19
263
149
370
110
295
I
44
79
94
169
94
1
6
299
102
395
209
141
2,817
2,796
It
2
3
1
78
4
200
302
84
249
1
111
24t
77
62
34
12
55
to
149
76
54
126
72
2,077
£(.,54
18
310
260
12
39
13
110
312
2
114
10
1,202
1,177
20
1
297
log
195
44
4
104
70
51
34
103
131
76
1.239
r/
1,072
22
-
9
9
9
24
(and
ovar)
593
16
3
365
233
19
405
99
455
294
96
194
333
155
203
521
220
4,193
3,896
Total
Jan. 1,
1977
1,463
90
967
1,095
2,859
969
94
3
235
2.024
633
3.917
2.696
4,539
6.734
99
2,822
123
219
242
1,309
1,447
1,496
3,927
930
2,330
275
494
1,699
1,117
896
496
3.739
4.706
414
4,012
17
669
642
475
14,130
306
924
713
426
4t4
1.403
81,296
-
Jan. 1,
1974
1,462
19
967
1,077
2,909
839
92
6
232
1,886
633
4.159
2.671
3,892
r/ 6,013
109
2,804
125
220
272
1,490
£/ 1,475
1,579
3,711
618
2,293
199
453
1,193
1,148
900
477
3,581
I/ 4,250
673
3,949
17
669
642
443
I/ 312
834
696
338
466
1,212
.
!/
78.039
I/
I/ tneludaa a
11 Includaa a
.all aaount of 5-Inch pip*.
«11 amount of 7-inch pipa.
391
-------
•Mtluc* •< «•<• cmkllm u en* OUM4 tueu «• «f Juury 1, 1*71
CMllM)
Jt«t
•ntk tekm .....
Jm»ry I, 1971
JM«T 1, !»»»
D»fcr
4
10
I
U
1
3
1
12
1
30
10
14
131
130
7
40
471
11*
«y
3
31
31
115
11
10*
20
111
1*7
M
93
4
14
17
24
114
172
1,314
7
1
1*
I.OIO
2,075
•V
171
4*1
2*0
21*
127
(IS
11
41)
lit
»7
M
n
37
73
IM
71*
1*1
" 31
4U
71*
VN
I,NT
-.,
30
21
155
1,711
93
241
1*5
(1*
1
4H
111
241
1
1*7
34
3*2
371
2,OO
121
' 11
11
1.4*1
W.26)
1I.S2S
10
4
)
(M
242
904
310
(41
117
1
333
117
117
9*
13
1,101
11
1,3*1
414
til
11.1*7
ll.lt*
11
1
21
517
(7
947
207
25
1)5
311
7]
1
11
1,14)
4*0
11
1*
*4
2*
171
311
3*4
1,311
2
3*
(17
10.10*
*.nf
14
14
Ul
41
14
It
(4
M
2
2
t)
62
371
541
IU* (tMt
1*
147
30*
12
(1
to
1
14
411
1*1
115
1
11
too
41*
404
1*
3*1
1
1,(*0
411
5.630
1.J41
U
Ul
11
23*
It
217
(4
71
2*1
35
21
1
4*
(5)
3*
11
2.001
l.ttl
M)
10
41
2t*
200
10
421
205
I*
401
577
It
4
451
S
Ul
10
1,1(3
t
2M
3.040
4,7*5
21
(5
3*5
Ul
in
340
7
IM
311
37
t
131
141
114
174
•
. 2.M4
2,tl)
24
4
13
2
30
7*
114
34
1
24*
111
3)
1.304
1,4)7
2*
20*
1
211
21
3
301
U
t.Ol)
110
21
V
-
.
.
30
intf _
(
4
227
(3
31
T4
1
It*
211
21*
21
110
2
430
2.370
Ml
Tttll
J««. 1,
1*71
34
7*
377
631
4,431
• 904
4,07*
1,134
41
3,tl7
31*
3,3*7
21*
1,102
1,1*1
1,347
3,177
1,2*7
640
too
1,441
11)
1,313
(,*«*
1,3(1
2(4
21.11*
604
177
411
47*
75.0tt
.
1*1*'
34
74
3H
(37
4,411
01
3.11*
1,25*
66
3,962
271
3,011
21*
1,4»)
1.150
*M
3,413
tst
(17
10)
1,47)
Ul
7*3
1,911
(,***
1.4*7
154
2t,004
314
177
(4
412
130
3.233
.
70,123
£/ tIMfttfd** • KMll OTalMt *f 7-lM* piM*
392
-------
•MtlM(« «f
ennkllMi l« tta O.lt.4 Ititn u •«
0«Ui>
I, MM
5t««
HldttfM ••••••••••*•
Total JMU I, 1974.
fetal J«. I, 1971.
2
.
j
7
2
-
1
25
I
MM
v
3
.
ft
14
17
1
31
7
7
1
479
4lf
*V
1
28
72
fti
tu
42
303
174
99
u
1 t§4
7
ft
71
3,344
X/ 5,»l
«y
37
371
3W
237
234
11
•94
273
9)
27
74
180
3 414
3J
44)
7M
l,«4|
I/ »,*"
«i/
}X
I*
9
111
1.253
93
I
491
307
1
3tl
1(1
M
I.S37
20.424
i/ 19,221
10
5
19
4H
247
121
1
ISt
17^
4 MS
431
IH
U,OM
11.M7
. IX
102
t
21
11
412
(1
937
374
t
11
1 14f
451
3(
91
111
184
621
2
jf
621
10, l«
£/ 10,094
14
74
•
mi
41
If
"
a
94
2
f
f?
S9t
571
Sit
u
37
347
321
12
18
39C
lil
31
100
404
39
20
m
421
3,H8
3,430
I (iMfa
18
-
•
191
to
143
72
283
2fl
3f
u
1,091
2,001
•)
20
45
298
200
30
18
(49
978
1
44
m
288
4;f72
I/ 5,117
22
-
•
(5
7
381
271
,
_
.
l,M4
I/ 2, *10
24
.
•
134
^
.
1,483
$/ 1,508
28
.
•
208
2|
U
1,034
1,039
30
IM'
it tncl«4«« • Mall Marat o( t-tMh f If*.
«/ frl« » ItT* li ' '
393
-------
ut* »«
tt» o«ui< lout •• «c
t, un
SUM
IMll J~. I, 1M7...
t«t»l Jw. I, V17»...
i/ i£££! I MI! -
x
4
W
12
I
«4
100
me «
wtic »
iwiC oi
.
2J
1
B
t
i»
m
i
tu
4?»
S-iMll
1-Ud
1
I
47
34
144
91
144
u
19
194
191
1,434
M
3.240
3,344
1
37
.
302
204
147
394
9)
91
2g
93
74
132
904
*02
3,274
SO
*n
9.31i
1,444
22
19
20
123
2 122
93
131
410
234
309
31
324
14
491
2.293
94
1.911
91
1.441
19.303
20,424
10
ft
3
19
545
244
290
327
344
167
M
127
99
*i
1,002
310
4.743
447
27t
11.391
11,040
1
21
11
343
(•
204
29
679
339
73
..
1 246
ill
jg
84
91
170
24S
624
13
3,200
39
613
10.154
10,103
24
.
^
LS4
B
14
9
f
4
94
_
2
-
90
41
309
590
StM (I*
37
347
328
12
11
441
100
409
329
12
630
8
1.707
39
27
421
3.973
5,644
eh«t)
so
227
203
39
*•
m
44
407
13
2.039
2,09t
20
m
100
279
89*
2n
5.251
4,972
22
207
116
143
317
3,059
1,644
24
m
34
^
249
1.014
2,254
1,411
24
-
a
.
^
21
j
-
474
t.M*
I.IW
10
».c)
a
20
7
647
3.367
t.SQZ
T0M
M. 1,
1977
190
1 647
770
I 275
* 77S
1.319
27.811
674
3.M*
77.972
.
1
M. 1,
1974
232
907
IS
4 123
1 394
640
100
1.456
301
786
1,329
6,390
1.204
2*4
27.490
605
177
64
3.960
.
»,zv>
394
-------
ri*«UjM mi In
i. in*
u a» tmu*t seam.
i, mi
Jim, I,
in*
Jafe I,
un
te. t,
1*74
Hit
'«•. t,
an
10
u
I
71
•30*
74
21*
34
tn
114
4«J
5
in
n
i, tit
3.12J
a
120
271
1U
131
M
343
U3
5M
3
410
34
M
1,114
in
jl 2*1
5,955
1.541
St
1.470
»34
4,0>7
401
J.HI
4,7>I
1.120
3,127
70]
1.047
200
i,oa
us
M3
1,175
3.M1
17.7(4
30t
10)
M
2,440
2.354
4*2
2.31*
r/ S.n?
1.411
50
l.tU
l;Ht
S/ 1,377
l.lli
1.00*
371
1,047
170
1,030
21
*I3
1,177
4,032
1.239
110
217
13
2,440
2.121
in
141
447
773
3,47*
471
4,171
1.373
I*
4.341
1;OM
i,in
403
4,017
4,7*1
1.171
1,10
101
1,107
s
1,401
m
1.2M
3,017
20,n3
137
2*7
100
204
2.440
2,434
40
in
711
1,03*
30
4.27*
1.0*4
4.3*3
37*
I/ 4,010
S/ 3.377
3,171
1.10*
43*
1,134
171
3
1.440
1.017
1,171
3.14*
1.213
ff n.477
331
2*7
ai
2,440
2.31*
4.24*
11
71?
MS
1.37*
U*
31
21
tl
2,41]
1,00*
1,417
1.J11
2,1*3
U
I.M4
14
311
7*
US
2,3*7
2,41*
Ul
n
41*
m
44*
i.m
111
1.4M
Z.03*
240
2,120
1
111
147
4,171
10*
1.311
3
247
303
rl 4,231
311
1*7
if 1,10*
107
S3
14
31
2,2*0
40
1,94*
1,303
1.3M
2,402
10
3,411
73
311
31
;40
401
1.1U
1,310
430
74*
413
401
1.10*
121
1,4(1
1.M7
217
2,22*
1
1,131
144
144
5,414
10*
1.137
30*
2
247
n*
7,113
7,M4
7t,U»
71 .Ml
77.114
41.773
£/ 42,272
395
-------
tlfflimm till tor p»ml«i» »t»*Ua» *» to* 0»lt»« iucu. liaurr L, 1977
rr.1.)
Jnury 1, 1>7*
sun
T«*l
Gutari
JM. 1,
1977
117
m
15*
56
107
^
421
|
92
1,042
7$
299
«,OI1
kat !!•••
Jm. 1,
1174
1A4
^
(4
52
M
^
r/
u
4f
1 lift
12
271
X/ 7 .SIS
Cl»<» »11 t
Jm. 1.
1*77
50
1 725
421
4 Mt
4 M2
3 111
3 Iff
791
2M
1 4fS
77
OT4
4,354
479
21 9f9
113
2 434
2.3U
71,514
XMUiMC
JM. I.
1974
*409
4 7*2
3 120
)'ll7
703
20g
1 029
132
MS
3 Ml
234
LOB
Z 4*0
2,35*
71, IS*
Tvul en
J-. 1.
1977
1 142
4 MX
3 1*7
3 999
IM
2*0
1 91*
as
94*
$,394
597
IIS
2 434
1,443
M.M9
•*• 1UM
JM. 1,
1974
4 344
HI
*/
145
991
5 097
101
2 4*0
2,U4
?*,977
m*
JM. 1.
1977
* fi
I*
310
297
423
55,4*4
«C limtt
JM. I.
1974
* 11
7$
£/ 543
224
£/'lO*
500
72
247
343
r/ 50,121
396
-------
K»>Ua« fill tor »•«•!*•• vif»llj>*t la Urn I*lu4 SCUM.
l. 1971 •** J—««rr 1. 194*
tamli)
Stan
KttMMky •••*••••••»*•»•••••*•»••**•••
mrylMrf ••* QUtttac *< C*!M*U ....
IttMlniBpi ••••••••••••*•**••*••*•••*
MMCMift ••••*•••••»•»•*•••••••••••••••
MfcVUltt ***•**••••*>•••*«••••••••••••*
NMff MVHliW •••••••••••••••••••••••••o*
ftocefc Canliw ...*......*....••......
Mwdi OfliMn ••••*••*«•••**••••••*•••*
GidMrt
JM. 1.
1*71
7
—
SO
543
47
—
.
—
2(2
42
643
133
33*
434
64
IS
4t
]
410
12
34
M
1,114
n
.
m
l.JOO
a
.
121
717
6,904
•( liM«
J«. 1.
1*M
1
^
54
647
101
f
^
^
us
ss
741
133
323
too
42
77
M
—
424
17
32
H
1,41*
112
.
^
2,744
41
.
IM
2«4
«,303
e*mit HI
JM. 1,
im
33
12*
444
442
2,314
604
_
f
4,310
1,4(1
50
3,413
313
3,»27
374
3,»44
2.3M
3,112
3, (04
371
l.OM
17*
1,030
22
N3
1,177
4,032
273
.
—
1,233
II.3M
310
2*7
>3
2,440
2.328
64,714
umkllM
J~- 1,
1*41
33
122
443
Ml
2,737
34*
^
—
9
3,441
1,1(0
61
3.3*2
343
2,M*
371
1,M3
3.1W
123
3.41*
443
1.033
1*0
1.032
42
1*3
1,330
4,040
330
^
—
337
17,944
300
2*7
in
S3
337
2.03V
94,603
T»Ul a
3tm. I.
1*71
40
12S
444
722
3,03*
673
^
—
4,772
1.323
30
4,274
71«
4 343
374
4,402
2.JM
3,171
3.804
634
1, 113
ITS
5
1.440
34
1,017
1,271
5,1*4
344
7r
_
1.235
H .8**
331
297
212
2,440
3.045
1
73,642
•4* ll»u
JIB. 1.
1*4*
34
122
443
717
3,444
(72
3,744
1.2U
(1
4,333
67*
3 3*4
371
3,013
3.19*
8*1
3,8**
340
1,12*
1*0
1,434
7*
M3
1.424
3.43*
442
.
w
337
20,70*
3d
2*7
10*
217
537
2.333
64,910
Fndu
J«u 1,
1971
2,13*
2
321
8*7
81*
107
53
14
32
2.240
(0
1,944
1,303
1,34*
2,402
10
2,411
n
311
32
7M
401
1,11*
1,310
430
(44
»7
744
415
401
1.10*
' 122
1,443
1.147
227
2,22*
3
1,131
144
144
5,434
101
1,337
30*
2
247
29«
39,904
M llou
J-. t.
194*
2 120
322
8*7
834
10*
54
1A
XI
1 433
227
t (*(
1,333
1,179
1,772
10
2 3*0
61
313
32
M*
44*
r/ 1,004
1.4U
3*2
3(1
N
944
330
430
1,230
174
1,23*
1,147
130
2,201
3
til
12*
144
4,31*
422
1,321
3*4
1
244
289
r/34,701
397
-------
APPENDIX C
SUMMARY OF LIQUID PIPELINE ACCIDENT REPORTS ON DOT FORM 1000-1
COMPILED BY THE OFFICE OF PIPELINE SAFETY FOR YEARS 1969-1976
i n, i**t
±fc
"••'"
In lirtitri
•""*"»«;
(1) IMlMM Ml Mtt«M »l«
(» I*clo44> MttMM* Ota Ft.
(J) IMlMM MtMMM «tU
•f m.OOO, MJ.OM, IM.OM M.OO*.
(«) mtrtu «M MctiMC ifltk IM.OM ,nn*n I»M«»
f4| lAcl^aa MB MBU«lt With I1S.OM »IM**CV 4
II) iMtMM MUMMHttt ,t4m *-M.T.< (M.«M, W..OW ^ 1100,00..
(I) UUMM M« MOMM OlCk >IM1H> MMM •< dLOM.
(I) IMlMM M> MtMM OtU UM •( If.ltO Mmtl.
(10) IMlMM M> «KUM< .lit UM .C •.«! MmU.
(11) lMta4M M> MtUMt otck UM •< 7.UI t«ml..
1. INI. »raM> OMMMl 11. IfM
en* Offln «f PtMilM S*(Kr
11, if»
398
-------
- It COMMPBm UVOtYta
CO
lO
IO
UUIMUUlIt
)PEHATIOMS ACCIDENTS ,'
:t«4. on v
"...oil,,, v
1C k
'ucl Oil
I1...I Fu.1 /
tat Fu.1 f
Uhyl.t*
tahydroii* AMunU*
?ond*n**t* /
..ro.ln.
Natural Caaolln*
Tran* Hln
TOTALS - BUllMC OtEIA-
TIOHS
TEST ACCIDENTS
Crud* Oil
|u«l Oil
fOTALS - DUIIHC TESTS
NO. or
ACCIDENTS
««
62
* "
1
1 •
1
40)
I
7
tor
TOTAL
»
1
1
i
i
t
I
1
100
M
14
100
LOSS
(IAUELS)
174.»40
100
" rBrtrrt DAHACE <»
CAMin
811,5
(,{
:»,i
I,
tk>
H
100.
-1
(4)
1
(*)
S
»
4
w
UM.1J7
M5
72)
1,401
OTHEM
144 7JO
r
(
i
1 C
(
i.
i I
(( »)
J(»)
1
-ff-
»5».621
ISO
TOTAL
1. 176. 240
1 •!!'
ii ,fir
" i.j*
i 9
2. 1
100.0
-0-
»1.7»5,7»0
17)
1 2.1M
X OF
TOTAL
66
(
2
0
1
-5-
100
17
100
DEA
CAUin
EMPLOYEES
1
2
)
0
RS
NON
2 '
2
0
INJUtlES
CAUIU
EMTLOTEES
f
1
0
NON
EMTLOtEES
1
1
0
(>) U.« than 1.0 parcant.
(1) Includ.. 5 .ccld.ot. whar* loaa waa J.OOO harrala or o»«r.
(2) Inclu4.a accUanta with lo.aaa at M12, 7641, 7227, an* 6750 harrala.
(1) IncluiUa ona acc|il«nt at (70* harrala.
(4) Inclu4aa on* accUant with 4*M|* at 1750,000.
(1) Includ.. on* accUant with 4a«|* at 190.000.
(«) Includ.* ana with 151,000 uul on* with IM.OOO •*•*!*.
(7) Includaa aecldanta wtth4»M|*a of 1225,000, 125,000 and »19,«5J.
(I) )^tlud*a accldrata with daugaa of IJ7.000 and (20,000.
(9) loclud.. ona with d».|. of $65.000.
PtfAHTMENT Or TMNSrOJITATIQN
NptltiM >ccU»t> turn DOT fan 7000-1
January 1, 1969. through 0*»«bir It, !>»»
CoBpllnl hy th« Offle* of rtp«lU< tiltiy
Fcbruir; U, K70
-------
tumour - K oomooiw INVOLVED
O
O
GOHMOOm
QPBtuYTIGMS KCCIOEHTfl
Crude Oil
3*
S21.S4*
t or
TOTAL
7
4
n
f
i
0
100. 0
PROPERTV DA IAGE (f)
CARRIE*
111 71»
{•,212
44.402
{,4tt
j, ?•'
I,»!
" " if
\.iH
J.4oi
20
4»J,OU
OTHERS
7* »07
7,
321 ,<
•i*
2 .
1,
20
J
H
T
n'i
01
46
Ji
n
4K.212
TOTAL
411, 7S«
;
2^ *i
JiJ
«
V
ii
,50'
i
1
2j
t!
ii
Si
4,SS(
20
(91.22I
1 OP
TOTAL
4C.O
M
14.
",
«,
0,
,
too.o
PEA
CARRIER
1
1
HS
NON
EMPLOYEES
1
2
'
IHJ
CARRIER
EMPLOYEES
1
1
' 2
4
BUS
BoH
EMPLOYEE!
5
12
17
at Tc»t>«patt»tloo
pat
frc
Flpclln* •ccden* frctt DOT Pom 7000-1
January 1. If 70, through tecaabar 11, 1*70
CwplUd by U»« otflc* of »l(«Xln» Sktaty
April 1, 1171
-------
nUMI MXIMUt MMUM - Jwuiy I. UN, TWOKV MttMU II, ItN
P«B«Ct»«llt at
IIr*U** MclWb Koi terror. ]••*-!
i, HJ«, i*««i9» BtcMlxc II. ttn
GOWlt»4 fc» MM OlflM Of
l«rll 1.
-------
uquu rim.ii> ICCIMIK MMUII . JM»MT I. ••'». TCMUOI MCINM* 11, IIM
O
ro
P«c«rt»«nt
Mpiil.. iccu ^'t&T-roo. 7000-}
0«u.ty I. 1*1*. thromh McwbM II. U10
. .
k« UM olllc* •! HP»UA« >•(•(>
I. itll
-------
- n COKMMT* IMVM,VIP
o
co
COMMODITY
OPERATIONS ACCIMNTS
Crude Oil
UlolilM
£&
1l*l Oil
klcicl Fuel
1*1 fuel
Uthydroui AIUKKII*
:aro«tn«
utural Gaioltn*
Propyi en*
rOTAlS - DURING
OPERATIONS
HO. or
ACCIOCNTS
21*
• I
*
i
147
toru.
(2.2
I
!
i
.00.0
i.3»u,
111 KO
t.
. 1
1 ]
, 1
J 1
!
, 1
r
1
II
S21.04*
t 01
TOtl
71
!
a
&
.0
LOO.O
tKfinv DI *« in
CMUUM
ni,
(1
11
j
!
(
71»
IV
41
i Si
' 1
! )
1
i
7!
44
2
I
44J.OU
OTHERS
7».»07
^'
V '
J '
. '
, '
1
1
L '
i
ii
i
A
41*. 212
TOTM.
411.7SC
7t,152
ill f4S
1' |^
{ ,! i
'
-------
1 riKllKC MXIMtt IWMUI - MMIUH I, H7I. IMOUCII UCtHltl II. l»l
-p.
O
CMISC Of ACC1UCNT
op«r»(ia*t 4ccldffi(l
:..rfa»tun - C«i«^tfl
E•*•{ lueturlRA Llfif
LffrcHYt fttf tin — ~r~
lacorctct OBI rat la* »y
Cffflff f«r«xiiut
HI •(•) |AA«OI||
Rupmrt* «r U«fc|»|
LUiktf
|tu«(wrt4 *r l*tMf| !*•!
InknaiA
tuftwr*4. l*4fclM|, Of
MalliMCfloa at V»lv«
iiipttirt of Frtvloutly
DM>M*<| tlo«
rulfiMctloft of Control or
K*tt«f t*MtM*p|
:«ld u.*th*r
>*f«c«i«* cittk u«f4
[»r**4f »ifl.».4 or Icoht*
PIMW pfcfcui r»iiwr*
V*ml»Ilw
l»Kl'!«l«B
FUTAL
or
ucmeni
Itl
f)
11
Jl
11
i
t
1
4
1
>
1
1
Ml
or
OtAl
)>•)
II •'
n.i
1,1
LI
} 0
1-0
l-i
!•}
i.i
IP
|.i
1,9
100.0
^!
C1IIIII
«
1)
1
a
4
>
«
0
i)
0
I
0
»
a
Hrunui
«
<
• '
a
t
•
I
«
•
V
i
0
*
1
CURl4A
uirutlli
I
*
«
^
|
0
«
1
t
1
1
*
«
1
sm2i£is
•
t
•
i
t
<
•
•
•
•
i
(
«
CAIIICI
11.10
Sl.«lf(»
1.141
u.4>e<»
i.iif
u
KO
».«?!
).U«
I.HM
Ma
If
l.»t
»?•
»
w
!0».«»l*>
HO. »4
OWf
M.IM
ttl!lOj"»
»».)« .
4. DM
l.tlf
W
10
t'tM,ti '
l,?°9
».ooo<"
Iff
US
fOO
IH
t.OH
J.OOO
0
»4.i)l
I«T«l
M.H?
Ml. Ill
ll.^t
11. WO
10 IM
in
IM
ll.D?
I.UO
».ioa
»w
lit
1.4U
I7»
!.«»
».0)0
IOJ.JOO
u>.»»
— — TJ~M — i
comMiin
(tAPICLI)
n.fii
M.HI
H.m"?
!•.«•"«
IB.JU«">
t Hi
I.MI
!!.»>"'•
'•?•»
».«•<»>
ll.lll«'*>
f.lM
II*
JJO
HJ
M«
ll«
VOW
14J.OJ?
>i
1»JO-
l»5l
II
?>•
»
.
1
1
I
_
1
,
.
.
i
1
42
IMO- lit:- • ::::
in* :;•-. i.,:i
_ 1
il : - '
•
i - :
i -. . i
1 :
I
t
1
I
.
. j
1
II : . :
(I) luluibi 4CC|4»» uf 1)0,000 ml 111.000.
(1) l«clu«i> MU Mclfau «l IM.OOa.
(1) l«lti<«i m. Mcll»t el IISO.OOO.
(4) l«cluJi< l HO.000 tut til.too.
(i) lucludti ucl44 110.000.
(I) Uclufei DM ICE I Jot al US,000.
(t)
(I)
(10)
(II)
Ill)
(II)
(U)
ulck lo» at t.«>< k«rc«l«.
« lc<> •! I.SM k.cr.l..
U»«l >l 1.100 «J 1.1)1 k.n.l..
lk !••• >< I.WO k.,c.l4.
luliitet >uti«i> »Uk !»«••• •! II, MO «M i.ito kuitli
IxlirfM !••• •< I.MO ktn.li.
Uclu4ii «M «cU»l "Ilk Un nl i,IM k.rnli.
«u »Mut>
lKli>4« OM «cl«
U«»«n»«af »f T|yH|X>f|f^afl
tlt«ll*« »cclA«Bl» CtM lor yon 1000-t
j«iuuir i. Itii. u|k mcMMi it. tin
Co^lUd ky lk> olflci of Mfdliu l.l.iy
-------
SUMMARY - BY COMMODITY INVOLVED
COMMODITY
I
'OPERATIONS ACCIDENTS
|Crudu Oil
Gasoline
iL.P.fi.
•Fuel Oil
lleael Fuel
Conden«ate
Jet Fuel
Natural Haioline
Anhydrous Ammonia
Keroslne
Alkylate
TOTALS - DURING
OPERATIONS
NO. Of
ACCIDENTS
172
SI
3*
21
5
5
4
4
3
2
2
108
\ or
TOTAL
55.9
16.6
12.7
«•
1.
1.
1.
1.
1.
.
.
100.0
LOSS
(BARRELS)
11S,7«0U>
42,001
39.1.7'"
11,724
4,953
3,<5«
2.2U
• ,741
».»10»>
700
I,5i5
245,057
» OF
TOTAL
47.2
17.
1C.
5.
2.
1.
1.
4.
.1
.7
100.0
PROPER1
CARRIER
44.1«l">
I71.»4?««»
70,U4<«»
11,072
540
10,510
4,liS
10S.024<»1>
0
400
72
$420,174
» DAMAGE 1
OTHERS
73.770«S>
M.iJjUl
7*,000<»>
».»OS
250
U.lSflOO
1,000
2J
2S.000112
1,000
200
$264,935
1
TOTAL
117, »!•
21S,S«4
14t,li4
20,t77
7*0
2«,730
S.liS
105,049
25,000
1,400
272
>6I5,309
« OF
TOTAL
17.2
J4.4
21.1
1.1
.1
1.1
r!
15.1
1.7
.2
.0
100.0
DEATHS
CARRIER
EMPLOYEES
0
0
0
0
0
0
0
0
0
0
0
0
NON
HPLOYEES
0
0
0
0
0
1
0
0
0
0
0
1
JNJUR
CARRIER
EMPLOYEES
2
. 0
0
0
0
0
0
0
0
0
0
2
es
NON
EMPLOYEES
0
4
0
0
0
1
0
0
1
0
0
c
(1) Include* accident I with lo**e* of 12,100, «,<*0, 7,3*0, 5,300, and 5,111 barrel*.
• (2) Include* accident* with loiee* of «,47», 5,500, and 5,100 barrel*.
(3) Include* one accident of 6,BOO barrel*.
(4) Include*,one accident with property damage of $11,000.
(5) Include* one accident with property damage of $10,000.
(6) Include* one accident with property damage of $150,000.
(7| Include* one accident with property daatag* of $52,100.
(I) Include* accident* with property damage* of $10,000 and $50,000.
(9) Include* one accident with property damage of $t0,000.
(10) Include* one accident with property damage of $15,000.
(11) Include* on* accident with property damage of $105,024.
(12) One accident of $25,000.
Department ot Tcansportation
Pipeline accident* Iroo DOT Form 7000-1
January 1, 1871, through December 11, 1*71
Compiled by the Office of Pipeline Safety
-------
O
CT>
'-"" •* '"•""•"
-i^l^i^jl
...lf«l»H • I.M.IMI
i""1.;';.^!"""
tts£F"*-
..„,... .1 n..>~.i>
Ik...... ii.in.4 .. ..-»..
-!£?:!:^ _.
........ ,,.l. B...II..1
V !:'"-• t!« -
"..«.....;"" • ••'
Ifcl.vll*! MtU
"«•'-
' """I'll,
Ill Ittfllllfc-l 4C |4>*l ||
m iMiu4.t .c I«.M* i
1*1 tncluA.1 «c ltf.«i |l
III lMlo*,l *t I4>M 1
t*t |M:|W|>I «tilA.M |
1*1 1*1*4.. *ttt«.«l. |
IIWI |wl««.« M.CI4.M »|
tilt lib|«4~i •ttlfeM »l
lilt l^l*4>« MGl*IM I
u*
to_
»
11
*
»
1 * 1
k
1
i
..._ * -
•- *•"•
1
1
1
1
I
1
1
„
i^i. ....
l.wn.
!»!ii.. ~.
:£
Of
IHlfcl
**
V.I
i.i
i.t
*.*
...
i.*
l.fe
i.*
I.i
1.*
I.U
-•*
.;•
.»
.4
.*
IUU.U
W>. M44 114.
kM.«M.
u
CMME*
.
«
•
.
H
•
•
•
•
•
•
a
.
•
d
•
•
MMt
,
*
•
• •• " '
*
*
•
«
•
— - —
•
*
*
.
•
•
II
'
IM1
CtfMKft
tMlOIKl
1
•
*
.
•
•
•
— ; —
•
•
•
. ...
•
H
•
*
HltS
MM
uMimt*
1 —
t
»
V
.
•
•
•
— r~
•
•
•
.
•
*
•
11
rwr
UMUB
,,-/»
n.in
».H»
»»*
w.W*'
H.tM0'
»»*
I.M*
•
•M
»!
*.*»•
!.•»
*W
II. >ll. XI
111
111
111
»*l
*•» |wl-;| ||,
.,«.
,,...."'
1,*»1
-»"*
*t*
I.N*
t.VM
M*
I.I**
I.IM
H*
I.IM
IM
Ml
I.OW
11*
*
•
«..*»
£l± «:!J
!"!!Jn n«!t
£!±:«:iJ
|Ul4i
..,.,
KM
1.V.1.W*
MI.1M
I.M*
It.tlJ
IH.IBt
i.m
I.IM
l.ll*
— rsr
a. it*
I.IM
"-
ail.Bd*
»,*«•
l.*H
fcM
..»>..»
•i •! fftw.e
M •! »»I,W>
MI wtifc IM
M» «lifc IM
IMS Of
UMMMritl
IMMCltl
-W«
— !r"!"^
M.m11"
II. At*
I.IM
...I.,'"1'
'•*"»
HI
I.IM
!.*»>
I, III
IM
I.Mft
Jl*
41*
1,1*8
MU
«..»
•M «f i.*W. •>*
M* *l ».?»» >M
*.* •! II. IM. t.
••• «f II. M*. t.
li-
ft
— r~
a
1
•
•
»
-_
1
'
1
•
it
M. 1,111
.Aw* bti
•a.-i*
Lur*cc
?f
1
1
t
1
•
i
1
—r
i
•
.
•
t.
• !•.
"IX.
l|uii-i
i!»
„
i
t
B
1 - 1
i
•
•
*
•
i
i
•
••»
;:;;
^ mn (i
1ST
„
—r
i
•
.
i
•
i
i
„„•.
14
MMl *,««•
y I^HI
ItM
,
li
1
,
1
•
1
•
1
* !M«««|
latHN,]
IH«
1
1
~l~
1
1
1
1
1
•
'
till
.
_
i
1
a
1 — I — 1
1
i
~7~
•
!
IM
M
~7~
-7-
i
•
•
i
•
•
•
•
-------
- B» COMMOOin INvn..».
OPERATIONS ACCIDENTS
Crude Oil
Gasoline
fuel Oil
I. P.O.
Diesel fuel
Jet Fuel
Condensate
Kerosene
Natural Gasoline
Alkylale
TOTALS - DURING
OPERATIONS
NO. OF
ACCIDENTS
IBO
CO
25
22
a
5
4
)
)
1
309
I OF
T01AL
58.3
19.4
a.i
7.1
2.6
1.6
1.3
1.0
0.3
0.3
100.0
LOSS
(BARRELS)
233 .690*"
43.6S4<2)
17.924
30.40»
5 .814
5.869
io.2oo(s>
1.000
1.212
360.654
f OF
TOTAL
64.8
12.1
5.0
8.S
1.0
1.6
1.6
2.8
0.3
0.3
100.0
PROPERTY DAMME It)
CARRIE*
364.268'"
I.366.6I51"
38.404""
116,840<»)
1.715
2.010
MO
4I.300
55
100
$1.931. 847
onin
396.530""
40..001"1
9,750
I6.7IO<»>
2,825
1.850
2,400
800
0
0
TOlAl
760.798
1,406.715
48.154
113.550
4.540
3.860
2,940
42.100
55
100
(470.965 (2.402.812
PHMtfiWII!^LV"*VPPVmH
kof
TOTAL
31.7
58.4
2.0
6.6
0.2
0.2
0.1
1.8
0
0
100.0
BOB
oe THS
CARRIER
EMPLOYEES
0
0
0
1
0
0
0
0
0
0
1
HBBBE
NON
EMPLOYEES
2
0
0
4
0
0
0
0
0
1
7
kB^B^B^Rei!
INJ
CARRIER
EMPLOYEES
»
5
0
0
0
0
0
0
0
0
6
DRIES
NON
EMPLOYEES
6
4
0
3
0
0
0
0
0
0
13
•Boat
Includes accidents with losses of 19.965, 17,000. 15.100. 11.598. 10.260. 8.000. 8.000. 8.000. 8.000. 7.211, 6.800. 6.797.6.000. and 5.200 barrels.
Includes one accident of 6.915 barrels.
Includes accidents with lasses of 5.474. and 5.000 barrels.
Includes one accident of 5.010 barrels.
Includes one accident of 6,875 barrels.
Includes accidents with property damages of 1118.000, (100,000. (37.473, (33,000. (10.000, and (10,000.
Includes accidents tilth property danagei of it.250.000. and (100.000.
Includes accidents with property daugef of il2.500, and (12.500.
Includes accidents with property dwoes of 160.000. (20.000. (20.000. and (14.000.
Includes one accident with property damage of (40.000.
Includes accidents with property damages of (200.000. (67.900. (40,000, (14,000, and (13,000.
Includes one accident with property damage of (30,000.
Includes one accident with property dauge of (10,000.
-------
IIWII MMIIM MCIU.I
• WM..I I, lilt. IMMU licimu ||, |,n
CD
00
CAUll Of UtlOfll
rtMtIO* UflOtfllS
•rr«ila» • filar**!
•••••••I OMBlwrlBj tl«a
• rrltr Pirll.ill
:.rr.tl.* . l.lim.l
'l>tlll.....l
»>Hl ll,»"" *"' '
• M.r. 1. ll«ir Crinllill'H
l.llif l«.lt*t.l
• II ...(Mr
>»(.cii«i link viu
.IMM"."'.'""""'
i.llM.tll.. .f !•!*•
... l.ll...
upl*"!' *f l.llllf l.ll
I.. C...IIM llll.il
.1..,!,. M,.
IIM.IM
out
M. W
Ulllllll
III-
M
II *
14
14 V
II
•
1 '
1
1
1
>
1
1
»
1
4
1
1
t
1
I
III
1 W
nm
H.I
II. 1
1.1
I.I
I.I
I.I
I.I
II
I.I
14
I.I
I.I
I.I
I.I
I.I
I.I
.1
.1
.1
.t
.1
IM 1
......IM.
Cllllfl
Miltlfl
•
•
•
1
•
I
•
- ,-
I
1
I
1
1
1
1
I
I
•
I
•
I
I
1
1
urllllll
•
•
I
1
•
I
1
I
•
1
1
1
•'
.Ill
1
•
I
•
I
•
I
*
'
MNtllfl
•
•
•
1
•
1
'
•
I
'
1
I
•
•
•
t
I
I
•
•
1
IT
IMtlllll
•
•
1
1
1
1
'
•
•
'
' > '
1
•
•
1
•
I
•
•
•
1
IMIIfl
1 1.114
II .Ml
II. IM
41. Ill'"
l.lll
441. IM!"
• MI.WJ
1,111
III
MM
1,111
I.IM
1,111
»«.IM<>>
II.IH""
II.Mlf"^
1
IM
II.IM"!
Ill
III.M.I'I
II .III. Ml
"MSH"-"]
1 14. m""
...41,"'*
ii.ni
I.IM
IM
I.IM
I.IM
1
I.IM
I.MI
1
I.MI
Ml
II.IM<">
II.Ml""
IM
I.MI
•
I
•
II.I4I<"'
t
im.in
i«u
1 ii.ni
III. 114
II.Ml
ll.lll
I.IM
III.IM
II, IM
1
1,111
i.m
I.MI
I.IM
I.MI
ll.lll
III.IM
11,111
II. IM
1
IM
II. IM
11,111
III.IM
tl.M4.lll
IMS M
Ti.iTil'H
11,111
IM.MI""
41.114"'
11.411
4.111
I.IM
l§,M4"ll
1...I1"1
4,114
1. „.''«>
I.MI
411
1,111
III
lit
II. M?'1
111,111
ijniq-uii^
11
i
i
i : i
•
i
i
•
' •
i
i
~~|
W
H
•
i
i
i
t
i
i
i
t :. • | •
i iii
t ' i '"*
• i
• • t
MKK4
mi
i
ii
i
4
1
1
1
I
,
I
• t i
r-H
,
I
fir
i
ii
• i
,
,
i
_i_
,
,
•
wi
Illl
1
1
1
1
1
1
IF
•
i
•
i
0
1 I
• I
t 1
t
1
_. — , — . —
• i
1
0
__
0
iii
i i .: i ' • j • 1 i • "
* i- * \
~L
it
.
t H
§
, t i 1 1
h ..-
1
0
ii t
I
1
1
0
,, ;„
4t
"
it
It
RUHIH
0
1
0
1
0
0
1
1
1
•
0
§
0
0
0
I
0
•
1
All 4l*tkl («.*«4 fev Ml .Id...!.
Utl.411 KCI4..I •! III.IM.
Uil.4.1 .(CI4..II •* ItM.MIi Illl
Uil.4.1 I1II4..I .1 III.IM.
l.i I.J.I >.
il»l.l leilll.l .1 111.Ml
I.ll.lll liclll.l II III.Ml
Ucl.MI icclll.1 .1 ill.MI.
.el.lll .C.U..I .1 llM.IM.
Ucl*«t« 4C
Uti»*u »
UlU«tl «<
t.llll «•
Utili •! III. til •*« IIO.
i«»u «r IM.MO <«4 iio.
M«l •* III.OH.
i .1 tit.uo
10
II
10
II
11
II
14
>S
1*
•«!«*•* Ml ttt
Htlmltt Ml »Ct
ftCl«4tl Ml ICC
•ClH^II Ml ICC
•Clu'tt IM ICC
Kl«Mt i\«Uti>
Bduilai MI tec
•clkdii MI acc
•cl*«*l IMF ra
t«a *l l*ll|ya 1
turn
<
• i.
••* IM
-------
SUHMAM . »t COHHOBH;
1 rff „
COHHOOIII
•JrCDAIION ACCIDCNU
Cruda Oil
GitollB*
I P.O.
funl Oil
Jcl fuel
Uilid fuel
Coiiden&«ttt
/trbieAe
Aiiliyilroui AMMOIIU
Tout tiumiiG
OPCBATKWS
HO. Of
ACCIOENtS
155
SI
. 25
20
9
t
5
1
)
213
S Of
TOIAt
St.;
IS.?
S.2
).l
3.1
2.1
I.B
.4
.4
100.0
IUSS
(BA«mS)
20»,173("
40.2071^
SI.SM")
51.505<«>
IJ.12l'**
S.»«
6.404
229
3.210
379.36S
1 Of
TOTAL
64.1
10. C
13.6
U.t
3.S
1.5
I.S
.1
.1
100.0
f«
(AAlUk
i 2»«,>
315. 055*"
25>.3«?l«l
14». !»><**
9.938
too
48
0
80
11. Oil. 909
UftdlJ OAMAGf
AIHCR 1
»m.«2«"«>
It .112
IS.«0<'M
»>.»I*'UI
2*.I001»3)
1.950
600
0
0
U86.930
(\\
lOIAl
1 III. OW
114. 23»
2)3,24)
24). 059
Jt.038
Z.550
64«
0
w
J1.304.1I3S
S OF
roiAi
31.6
25. t
21. »
IB. 9
2.t
.2
.0
.0
.0
100.0
Lift
CA««U«
LKFLOIEES
0
0
1
0
0
U
0
0
0
'
HIS
NOk
EHflOntS
0
0
»(T4F
0
0
U
0
0
0
6
KJMI
ENPLOKES
0
0
I
0
0
0
«
0
0
1
us
HO*
EMPLOYEE:
a
0
2
0
0
0
i
a
2
i
52 101*1 OUK KG
*£> OPCBATIO«S
2)3
100.0
379.36S
100.0
tl. 018. 90S
1 Includes incident* xltk losses al 10.185; 18,700; 11.000; 13.000;
i
i
4
5
(
(7
.15
10
U
12
13
14
Include i out Accident at 0.640 btrrels.
Includes iccla
Include! ant *
tnls wltk It
:ci
U85.930 |l. 104. Hit 100.0 1 6
10.500; 6.000; 5.»I2; 5.63). iud iwu it 5,00b IxrreU
jrrels.
Include ant «ccidc»t af 6,04» birrtls
Includes accidents xltk property dcctd«*t nit
Includes ccld
enti uitk »
deAjgt o
dakege a
di«*ge o
h prwtttrty 4«««ft i
roperty
209 .000
2 SO .000
200.000
; 110.400; mil
; 120.000; »I5.
.nd 150.000.
•«d J42.500.
ilO.IOO.
000; <>d $13.000.
35.J2S; IU.443; «nd til. 220.
C ill .000.
dinefte ft 160.000:
Includes a< iccldeat Hllk properly timtft al 120.0
12K.OOO; <«d |
00.
10.000.
-------
***tr~.i iwtrtwi,* ilM
CM*M|M • *•«•«*•!
CftrilM tMMMil*
•^iS/j/'****"11'
tilW^iST"* "
I^.U^c. M U-.ll-
Mfactlv* «|«tb (*•!•
V~4.1I..
to.ll.MiiM •! «*!..
fflu»4« *lt|f**4 M feet.*
014 •**<*>•*
• *I(M« Hi flM|«M4«l|
tl«M.I^
to M*fc
•*—»»«—"•
VbtM.
II
II
1 at
i*
It
4
a
i
4
1
I
I
>
a
i
i
n
m
U.ft
14.1
i.i
i.i
1.1
1.4
1.4
1.4
1.4
I.I
».l
.1
.,
.1
..
».*
'"»
-car.-***
urutlit
•
l
•
__! —
,
•
•
t
•
•
4
,111
1
t
1
4
u „_
ciwioni*
•
•
•
!
,
•
i
•
•
«
4
,'"
4
4
,"'
4
-Ha**
•
,i»
i
• -
.
,
•
•
•
4
i
.
•
.
•
4
Ki~
4
i
,«•
4
1
.
I
4
•
•
•
•
,
t
4
•
I
UMIH
1 41. §14*''
11.141
• >,.»>>«
I.U4
lt.444*1*
444.4«.»l
I.Mt
I.U»
1.411
4I.444*1*
U4
I.«M
.
4.M4
»4«
41.. >.!»•'
I1II,IU
,.,»
*'***
4M
IU
1.144
IM
•
1.144
•
Mt
4
.
•«.»•»«">
KIU
1 Xl.444
11.444
44. 4M
1.144
141. 4M
1.144
1.414
1.111
41. 4M
1.144
!.««
•M
ft. 4*4
...
LOtfi Uff
IMMHJI
141, III HH
II. III
"1 mi
i.iii
a.Di
i.tit
i.iii
i>t
*.4l|tlll
in
iJi
"^
141
1.1 tl
«ro^-
IIJ*
i
i
4
1
4
4
*
t
' 4
HIS-
111*
*
It
(
«
•
•
•
•
.
^
:•>.
»
»
1 — i — 1
t
1
4
•
•
1
4
ItSS1.
1141
" 1
• !
t
•
•
i
•
i
—
M.U'.'-'UISI
lt:l .HI
11 } 14
' i '
l
l ; 4
: i
> « l
1 ' 4
• ••
I t
: . .
T|»
1!"
4
4
'
1
4
4
1
*
4
.
- -v« -
MvMtll
•
1 '
'
t
1
4
•
4
•
4
•
•
1
1
<**• MC.4«MI -I
li.j« <.\4 t.'i.n
Oil IM
Illl IM
Illl 1(14
Illl Itu
Illl I*.
I 111 I*
Illl IT.
Illl tr,
Illl »«
r.i« cl IUC.CM* l)«4.4*4i IIM.Mt. IM.Mfi »4 I1*.4I|.
>•• •! llt.CMi llt,4M| ll«.M4i fU,44li *M 119.444.
•I *4 lll'ue'.
•«• vl*C !«*•«• •« *4.444| i.lMt »J I.It: l-.«..U
•*• with Uit*« at l.rMi >.»Mi I.IMi «*J I.III »•!(•:•.
«i* C;.* !»••» trl 3ft*l>4* M>« »-•»! *M«I*U.
-------
»BHM»M • »¥ COMHOOm HIVO1.VUI
COHHOOITI
OKUTIOU ACCIMNTI
CruiU Oil
L.r.s.
O..OIU.
ru«i on
itt nui
OU»1 fu.l
tahrdrou. »— onU
Co".......
TOTU. MWING
ortKATioM
HO. or
ACCIOiNT*
144
"
11
14
1
•
1
1
,S,
i or
TOTU
44.1
11.1
11. 1
1.1
1.1
1.1
.1
• •«
111.*
III Include iccldin wltk lo><>» of
111 Includo >ccld«n xltk !»•••• of
111 Includd ant >cc »t al 1,411 k»i
141 IneludM ccciton of I20*.tl*i 11
111 Includti iccid«n o| till, III! ||
1(1 Inclwltt >ccid«r. al 441,111.
Ill Include iccid.n al 111. Ill «n4
III I>ctud« «ccld«n al l!M,M*i It
111 Includai i.-cid.n ol 111. lit ccla«i>t.
Illl Ml 4*«kht CAu««J fcy two «ccld*nt«
Illl raur la|uri*fl c^ustJ by ena jcctd*
UM1
IUMIUI
I4l.ll.(»>
l4.Hll»
14,111
11,111
ll,!ll<»
1,11*
>.14I
1.141
It). 14) .
t or
tatu.
11. i
n.i
t.l
4.1
1.1
.4
1.1
.4
111.*
CMU1C*
1 114,111^^
II. til '*!
4,0 JO
t.tlt
4.11*
100
II
11,111,11)
stmytjaa
1 1*, mil)
ill.lOlWt
1,11*
H.lllWI
ll.JOOlHI
III
1,1*1
no
liii.ii)
^-^T-
1 4U.444
1.11*. ill
11,111
it, 111
11, lit
4,111
1,1*1
111
ll.Ctl.41!
I or
TOTU.
11.4
II. S
1.4
1.1
1.1
.1
.1
.1
III.*
DEI
CUMM
nwu»i«
4IUI
I
*
t
I
I
*
•
4
«.5m.
(llll
•
1
*
t
0
1
1
1
amf.nu
t
,-.»:
:
;
:
.
:
:
4
HON
twiomc
0
i
i
i
i
0
JII4I
i
i
40,llt| l.llli l.iMi l.llli l.tlll 4.J»»| ••« I. III. txci«U.
11,111) 4.40I| Mid ,1,111 b*ff«l4.
oil.
11,11*1 III. Illl 111. Illl 111. 11*1 «~» 111.***.
41*. *•«.
>,*!*< lll.MIl «rd 114,000.
III. III.
-------
iimiia nm mi Kcitta tumor • J«IMU i. i««. inou* «.a..t. 11. nn
ro
liAtItt OF ALillltMl
Oft ft* 1 ION KCItiNfi
tqit*JM«M lu^lnd*! *•*"•(!>
lH«lfM"M f»U»r*(it
l*.»ri«ti OfMMlM kir
CtflUt ntlMMiUlUk
CitMMlM • Ul«(Ml
»*f«cii** HM S*M(|»
»»l«cil»« Cltlk *•«
r»ii»(* •( r***i*utir
•»•!•< fi»«(«t(t)
tt»4»IU»
fciluf* •! ff •*!*«» Mil*
••Ml*
U«kl«IMll4)
NI*callMMM«(lti
IMU
NO. Of
ACCtMNU
71
»
<«tl
U(l) .
IMU '
I
I
1
1
Jf
Ul
fkBCtllT
or
101 At.
ti. »
i*.*
4.4
I.I
l.»
t.t
l.»
1.*
k.i
• i
U.I
!••.•
«*
CAKHliK
JiMTiUlltf
•
>
1
•
*
•
•
•
1
1
1
H»
*Mfi»nts
•
•
. • /
»
•
«
t
•
t
•
t
!««
wnoiiii
i
i
•
•
•
•
•
•
•
t
t
!« .
wruikU
i j .,
•
•
•
•
•
•
i
u
| iTf.llft
U4.IU
!.«•
4.IM
It.IAt
>.WI
»l.l»«
1M.U»
M.llt.lH
r^sSn
IU4.III
• .••1
I.IH
UI.M*
•
I.IM
t*M.M>
I "'mu
1 441. til
141 .Ml
ail.kM
JM.ftM
»!.!»
ll.ltl.MI
lOtl M
COMHOttlff
(MMILII
M.I14
».«ll
tl.Ut
II. J»*
1.1)4
111.41k
•MM
urow
111!
>
•
4
1
1
1
!•»•
IIII
1
•
4
It
* Of MCIWMTI 1
Ml**
1114
I
I
1
11
::;:
u
T~
4
14
IT !**» Of IMfTAl
lt*4*
IIII
14
1
1
1
11
ia:
n
,14
1
1
'
II
LAI JIM
fsr
i
t
i
»
i
4
14
Mil
u. ratlin
i
4
1
4
4
•
14
(II•
I
<
1*1 I
pr*»*'i|T *•*•!».
lilt to* •tcl4«*t--M I
t !••• •! D.II4 fc»»r»U (
-------
SUMMAIIt • i» COMMOPm INVOLVED
-p.
I—«
GJ
COtOUDlTI
CluJc Olid)
lit
41
it
2*
>
»
4
i
2
1
2Si
fwcBNT
Of
TOTAL
S2.I
U.I
11.4
U.I
1.1
1.1
l.t
1.2
D.I
».4
10*. o
LOSS
IN
IAIULS
105,171
10.041
24.11*
101.221
4.241
2I.41S
2S.010
1,511
IS*
110
11*. 421
MKCiMT
OP
TOTAL
11.14
«.;
J.H
12.14
1.11
».M
7.14
(.41
i.17
«.«!
!»•.«
rtoruTir IMMCI (t)
CAUUI
Il,2tl.t21
771.221
11.411
2H.I70
4t2
• It
*,»1»
10
47S
•
12. 112. lit
OTHM
1147.141
114.2*1
14. 80S
4I*.«*»
S.*M
»4.2U
I. IS*
l.eo*
u*
la*
t*14.t*I
TOTAL
tl.441.;«4
•«f.(«4
>2,4»1
»»l.«7*
i.4»i
•i.Ut
t.*tt
l.ll*
57 i
It*
11,117. til
NMINT
OF
TOTAL
41.1
21.1
l.t
tl.i
*.2
l.»t
(.21
t.*l
«.*2
«.tl
!»«.«
MATHS
CAUIH
tMPLOIEES
1
«
*
i
*
«
t
*
•
(
1
NON
tMcioms
• g
0
0
4
a
t
t
«
0
t
4
INJURIES
CA»BU«
tWLOTEBS
«
«
•
1
I
•
*
II
0
0
1
NON
KMTLOUES
1
1
*
10
0
0
0
0
0
•
12
(I) ccld«ti--|l«o.too properly du>|« •ml am c.rrl.r ••»>»„• d.tik; Ilil.tM Pro|i«r>r
«•'!•; 1291.01* praftrlr J>.||. IAJ II.lit klrrtli •( cuuodlty Uiti 1S,*M k»»l> of
(2)
I2SI.IM
u|<; «4 IliS, 10* pro
clJinii- litl.tll proiu
<•••>*•.
4.122 k>rr«li of couwjlly Ion lid f7>S.*tt
(1) Accld»ll--|S*,*oa Biopirif d»>|>, four «OM«olor<*
dllthl, M4 21,SO* kirrtll «f COMOdlty Ion: 11)1.ISO
property du>|« •••! o«« noauplaxM Injury: I12S.OSS
vratircy d>«|« >»d •!«• ooooployM Ujutlis; «nd
111*.MO propiny d»>|i, tun cirrl«r InjurUs.
-------
uauio urtiiHl Acciimrr MMMAIK - JJUBULM I. it^t. TUKOUCH ntcman 11.
CAII9K ur fcCCIDCNT
CrEMTIOK kCCIDUHI
lwt ky
Coiroalon - lataraal
ralluta of rravloucly
Daatagad fl|>a
nalfunctlon of Control or
Cald Hft«ih«(
tutor VMblcl*
HO. or
ACCIDENT*
U
41
a*
14
it
I
4
i"
4
a
i
i
"i"
s
i
ii
III All daatfaa cauaad ky ona accldaoc.
Ill All loiurUi ciuaad ky oat tccldaat.
• or
TOTAL
11. •
ii.t
t.t
4.1
l.t
1.1
*.»
1.1
i .7
~i'.i'
i~cT
a~«
3.4
" •".»"
J.<
4.S
».l
Itt.t
MAIM
CAMIE*
KWUnn*
•
"•
•
*
•
•
•
•
*
i"
*
•
•
• "
•
•
a
t
HUN
UWUTUI
•
"• "" "
t
,111
•
0
•
•
....
•
•
•
•
~» '
•
•
•
1
INJIM
CAMIMI
IWUHtli
1
•
1
•
,111
t
I
•
1
t
•
t
1
(
(
1
- - .
It*
MM
uirunu
«
•
•
• "
•
•
1
t
t
•
*
1
*
•
•
•
t
-. .. .
nonm umoc 1
CAUIU
1 ll.iat*"
ir.ti*
ii. an
m. 14*1*1
4I,U1«»>
*
""l.ttl
11. lit. Ill
. .
OTHU
111*. lit*"
a».a**<*>
l*.l**">
I.tM
ia*,*l|l>ll
«
l.tl*
1.1M
I.MB
il.M*l»'l
4»»
lot
•
*
t.lt*
1411. til
II
TOTAL
1 I»4.t4»
'">>,*>•
11,114
11,111
111,11*
111.1*1
•
I.llt
l.llt
• _ l.Mt
It, Ml
l.llt
Jl*
l.t«*
IM
Itl.lti
11, lit, 1*1
u>«* or
COHHOOITI
IIAMIUI
14,llt'"l
" ii, mini
i*.ui»»
U.IM'"'
1,141
M.tl.<1"
111
'"iV.iiii'W"
'">.«•»«•»
i.iii
in
4.144
1,11*
1.141
III
I».«14<"'
lll.OI
•crmi
111*
)
1
1
•
a
t
t
" •
•
«
•
i
•
•
•
....
*
11
«
iiit-
llii
i
<
>
•
*
*
•
a "
•
t
•
t
»
•
•
i*
NJNM* Of
Hit-
Mil
i
•"
i
•
i
•
•
i "
i
i '
•
I
I
•
•
'
J
ai
HCCIBOI
114*-
1141
II
•
1
1
a
i .
i
"«
•
a
i
•
i
*
i
•
41
T* •¥ VK
IIM-
Illl
ai
>
i
i
i
4
t
,'"
•
•
•
1
•
|
t
1
41
M or m
nit-
IMI
11
1
1
t
1
a
•
i
a
•
•
0
a
*
i
•
41
CTM.LAT1
1111-
im
i
"i
i
t
*
•
•
"~«"~
•
i
i
a
i
*~
i
-.__,
it
OH
HOT
mroiTtc
•
a
•
t
1
•
•
•
«
»
«
•
*
i
*
4
Ill
III
ACludt «CCId«»l of ili.MI.
nclud* ucldut of lit*.Ml.
nclud* iccldoic of Ill.Otl.
f>cluj. ACCld»l« Of lltl.tttl ilt*,0llti .
nclud* «ccld.nlt of lll.tt* m4 111,*.**.
ncUa. >ccld»t of 111,***.
111!
1141
IH)
(III
cU«lt> ut |l*,**( »»4 111,Ml.
uludx uci«Ml «l III.M*.
MllldM MCldMM 01 lilt,*** Utt lit.MO.
oldMtl «llk |0««M Of l.llll l.aiil 4,4SJ| and
,111 ktriolt.
Mludai locldaolt "Itk loiaoo of t.llJ aod >.*•• karrola.
acludai AooloaoU Hltk lom.ai ol II.1*1 aad 4,1(1 katlalo.
•cludaa 4cold«ti vltk lotoai ol l.llli I.41II I.JIIi «ad
.111 karrall.
U>l Inoludaa
111! I«o!
Ill) lac
111) IM
vltk !<>•••• of i.ilti S,t«*i «iwl 4,ill
.cclauti >ltk lo»«> of 4.115 >»4 !,*«• b«ir«l«.
iccldrat t>ltk lo» ol I,SI* k»r«U.
•ccld.nt ultk |0» Of 1,111 b«II4l4.
-------
.» COMHOBIW
cn
COHHOOm
orCRATIOH ACCIDENT*
Cruda Oil
0..01U.
N.a.L.
riMi on
i.r.B.
j.t r».i
oieui riui
Anhydroua AMMmla
Tc.na.1.
«"""»•
TOTAL
NO. or
ACCIDENT*-
'
111
M
5
11
14
1
7
1
1
1
201
> or
TOTAL
M.I
10.7
1.4
(.1
(.7
1.4
1.1
1.4
4.S
O.S
100.0
LOU
(kAMXUI
94tg)a(l|
29.474(21
2f .ol$(l|
41,4S7(^)
10, t lad
l.JOi
Il,«t4
1*,14.«« '
111
»"
155.017
« or
TOTAL
17.7
11.1
11.4
17.1
ia.o
0.7
S.I
4.0
0.1
0.4
100.0
(11 "^U4" MjUanta with loaeae of »,17li 4,5)1, 5,150, s
(11 ncladaa an* accident o( 4,»7 barnle.
()l ncludei aecldanti ulth loeaee of l.llli «,m, and t 419
141 nclwUt .ccU.ot. ulth loaaee at 14. Itt >^1 4.S17 Mrr.i
ISI HOlud«« Aecldanto uith lo*>«* ol C $04i S Stt7i and 4 OS!
lil ncludfts OIM acoid«AK ol 4,iSl barrel* ' '
171 neludaa accidutt o( (15,040.
Ill neludai accldant ol I1SO.OOO.
r»mn« BANAO* lit
CAM1SA
J «»,«.">
17..U7»«
1.1IS
a.tif
IK.MS'"
1,1*0
l.ltO
7,140
0
21
1,11*. Ill
llai S.OOOi and
IOTJUU
U?,
• ,710
n.oio'»>
1>.*J«I»»
U5.I50'1)»
•
1.500
sa,M*'">
54,04*
1.
411,
-------
APPENDIX D
A STATISTICAL ESTIMATE OF PIPELINE LEAKAGE
D.I BACKGROUND
A statistical methodology for estimating the frequency and magnitude of
pipeline leaks utilizing reported data is presented. The particular data
base used consists of a computerized compilation prepared by SAI personnel
containing key data on all oil spills reported to the Office of Pipeline
Safety for the years 1971 through 1975 inclusive.
In the absence of a related fire, explosion or pollution, the OPSO data
does not include data on spills under 50 barrels. It is the objective of
the methodology discussed here to supply a reasonable estimate for the fre-
quency of occurrence and magnitude of spills falling below this 50 barrel
reporting threshold. The study estimates that about 70 percent of all spills
from crude pipelines fall below 50 barrels. In terms of oil lost, this
amounts to about two percent of the total spillage. It should be noted, how-
ever, that 70 percent is based on the types and causes of spills reported.
Thus, there is an absence in OPSO spill data of causes of small leaks, such
as at small fittings, sensor taps into the line, etc. Thus, this 70 percent
figure is a minimal number and it is estimated that if all line spill causes
are included the 70 percent figure would be increased upward to the 80 to 85
percent range.
D.2 ASSUMPTIONS
Two primary assumptions underlie the method. First, it is assumed that
the OPSO data base is a fair representation of actual fact. It is assumed
that all leaks exceeding the 50 barrel reporting threshold are reported, and
that their magnitudes are determined without bias. Lack of bias is more im-
portant than simple error of estimation. For example, the data does not in-
dicate groupings or clusterings of spill volumes about convenient numbers.
A great many spills are reported as "50,", "100," or "200" barrels, for ex-
ample, but very few or none as "52" or "97," etc. By assuming no bias, it
is meant that these groupings are a result of honest estimation to the near-
est reasonable number rather than a result of an attempt to consistently
exaggerate or play down the size of spills. The correctness of this assump-
tion weighs more heavily on the accuracy of the derived estimate than on the
validity of the approach in general.
The second assumption is that the nature of the distribution of re-
ported spills over 50 barrels is shared by spills below the 50 barrel
416
-------
reporting threshold. This assumption will be supported by the degree to
which the observed data (reported spills) fit a meaningful probability den-
sity function and by observing that the same contributing physical laws
which control the magnitude of spills over 50 barrels are operable in con-
trolling the magnitude of spills under 50 barrels.
D.3 STATISTICAL ESTIMATION (CRUDE SPILLS)
Table D-l is a summary of all reported spills from U.S. crude pipelines
over the five years 1971 through 1975 inclusive. This summary was" extracted
from OPS data which includes spills from all parts of a pipeline system:
the pipes, pumping stations, delivery points, tanks, valves, etc. The data
presented in Table D-l is limited to spills from the"pipes themselves, ex-
cluding all other sources.
Attempts were made to fit alternative probability density functions to
the five-year spill data. The primary density functions considered were the
gamma and the log-normal. These two were selected because they share the
property of having a fixed lower bound (there are no negative valued spills)
and because they result "naturally" from certain intuitive and reasonable
bases.
The gamma distribution is a generalization of the exponential distribu-
tion. If all spills were generated by the same size leaks (same leak rates)
and the difference in magnitudes between spills were solely attributable to
the time from inception to system shutdown, and if the likelihood of detec-
tion and shutdown remained constant with time, then it would follow that the
exponential distribution would underlie the distribution of spill sizes.
The gamma distribution, being the parent distribution of the exponential
distribution, was thus considered as a meaningful and "natural" candidate
for trial.
The log-normal distribution results when a random variable is itself
the product of many other random variables, just as a normal (or Gaussian)
random variable results from the sum of many other random variables. It is
seen immediately that the two major factors determining the magnitude of a
pipeline spill, namely leak rate and time to system shutdown, contribute
multiplicatively to spill volume. That is: magnitude = rate x time. Ad-
ditionally, leak rate is proportional to the product of the opening of the
pipe (area) and the square root of the pipeline gage pressure. Time till
detection of the leak (and hence system shutdown) is also conceivably the
result of the product of several factors such as leak detection resolution
(through the use of line variance measurements, etc.), total line flow rate,
and, of course, leak rate.
In attempting to fit gamma and log normal distributions to the histori-
cal data, it was necessary to estimate the total number of spills (reported
as well as unreported) while simultaneously determining the controlling
parameters of the candidate distribution. The results of our investigation
found an extremely close fit of the historical data is achieved with the
log-normal distribution. We will therefore discuss our method of parameter
417
-------
TABLE D-l. CRUDE SPILLS FROM LINE PIPE (NO. OF SPILLS)
Range
(Barrels)
50-100
100-200
201-400
401-800
801-1600
1600-25000
1971
36
35
26
21
14
14
146
1972
37
28
19
22
11
24
141
1973
27
25
18
19
13
20
122
1974
44
28
24
16
12
19
143
1975
23
27
13
11
6
8
' 88
5-Year
Total
167
143
100
89
56
85
640
418
-------
estimation utilizing this distribution. The method was applied in similar
fashion with the gamma distribution. The log-normal distribution is defined:
f(x;y,a) = — - — exp |- -^- (Inx - u)
ax/2¥ L 2a J
where
x > 0
a > 0
_ oo < y < ao
Now let a., i = 1,2,..., n+1 denote the end points of n intervals of spill
volume
b- , i = 1,2,..., n denote the historical data values (spills)
for each interval .
The intervals are defined in terms of spill magnitude. For example,
we used a^ = 0, 82 = 50, or the magnitudes 0 to 50 barrels for the first
interval, 32 = 50 to 33 = 100 for the second interval, and so on.
The determination of best possible fit was measured using x2 values as
follows (x2 denotes the chi -square variable as used to test statistical hypo-
theses. See Section 6.2 for additional development.) For given values of
u and a (the log-normal parameters) together with T, an assumed number of
total spills, define F.. as:
F. = I f(x;u,a)dx
ai
or the probability that a spill falls in the ith interval, and
1=2
Again, b-j is the actual spill frequency in the ith interval, while
is the estimated frequency based upon the assumed values of u, a and T.
419
-------
A program was developed which found the optimal values of y, a and T,
minimizing x2 for the historical data. This program utilized a three level
search or optimization scheme.
• Values for y were determined by direct trial, stepping through
a range of values.
• Values for a were determined by utilizing a Fibonacci search
to seek the best a for each y.
• Values of T were determined analytically for each pair: y,a.
The values of y and a determine the values of F-j in equation (1).
The optimal value of T is then found by differentiating (1).
n n n
X2 = T 2 F. - 2 2 b, + T 2 b,2/F. (from (1))
1-2 n 1-2 1=2 n n
1-2
and setting
yields
The optimal values determined for the five-year data in Table D-l were:
U = 2.31
a = 2.94
T « 2217.48
The x2 value was 1.65. A comparison of the actual and predicted values is
given in Table D-2.
Utilizing this log-normal distribution we generated Table D-3 which
provides actual versus predicted spill frequencies for each of the five
years, together with an estimate of barrels spilled for each interval.
Table D-3 also provides the resulting estimates for spill frequencies and
losses for the 0 to 50 barrel range. In generating these estimates the
basic parameters (y and a) of the log-normal distribution remained unchanged.
420
-------
TABLE D-2. LOG-NORMAL COMPARISON WITH FIVE-YEAR DATA
Number of Spills
Index Range (barrels) Prediction Actual Difference
(1) a, - a1+l F.T b.
2 50 - 100 167.22 167 0.22
3 100 - 200 139.23 143 -3.77
4 200 - 400 109.68 100 9.68
5 . 400 - 800 81.75 89 -7.25
6 800 - 1600 57.66 56 1.66
7 1600 - 25000 85.28 85 0.28
421
-------
TABLE D-3. PREDICTED AND ACTUAL SPILL FREQUENCIES
1971 I9M 1973 1974
Ningt Actutl trttSi »»rr«ll Actual trti Itrrtli Actvtl trtt limit Acluit trtt lirrcli
0-10 - 239 (29 - 212 III -- 201 S2I -- 234 (IS
10 - 20 - 47 (84 •- 46 664 - 40 S74 - 46 6(9
20 - 30 — 27 (59 - 26 640 -- 22 S53 — 26 644
10 - 40 - 18 632 - 18 614 -- IS S3I -- II 611
!
40 - SO - 14 607 -- 13 590 — U Sl» -- U 494
50 - 100 36 3* 2,746 37 37 2.666 27 32 2.306 44 38 2,665
j^ 100 - 200 35 32 4.557 28 31 4.426 25 27 3.827 28 11 4.454
ro
200 - 400 26 25 7,158 19 24 (.951 18 21 6.011 24 25 6.999
400 - «00 21 19 10.636 22 IB 10.330 II 16 8.932 16 II 10.401
«00 - 1600 14 13 I4.J55 II 13 14.524 1) II I2.SS9 12 13 14.623
It00 - 2SOOO 14 20 101. 1(3 24 19 104,082 20 16 90.002 19 19 104,798
1975 fl»e-»««r Jouli
Actutl trtt Itrnll Actvt) trtt Itrrelt
147 317 - 1042 2.739
29 421 -- 207 2.977
16 40S -- 116 2.869
II 319 - 79 2.75.1
1 374 - S9 1.644
23 24 1,689 167 167 11.955
27 20 2.804 143 139 19.843
13 IS 4.404 100 110 31.164
II 12 6,544 89 82 46.310
6 8 9.201 56 58 65.113
8 12 (5,937 85 IS 4(6.630
^og-normal estimate (prediciton)
-------
Expression (2) was utilized to generate the total number of spills for each
reporting period.
D.4 DISCUSSION OF RESULTS
In review and summary, a survey of alternative candidate distributions
to model the pipeline leak process showed a remarkable ability of the log-
normal distribution to fit the observed historical data. Fitting the his-
torical data alone was not considered adequate, however. There are, for
example, many so-called empirical distributions available to a researcher
interested in modeling a given process. These empirical distributions can
be manipulated so as to fit virtually any observed data. The degree of fit
is limited only by the ingenuity and industry of the researcher. Empirical
distributions are particularly useful for summarizing data when no clear-cut
theoretical explanation is available. Since the historical data on pipeline
spills is incomplete, and since the objective in this case is to estimate
the magnitude of the missing data, it follows that the probability density
function used to generate the estimate should possess a reasonable theoreti-
cal basis. Degree of fit is secondary and serves to validate the use of
the suggested distribution.
Our approach, as discussed earlier, was to try several likely distribu-
tions without excessive regard for theoretical explanations. The aim was
to first see if any of the "natural" distributions adequately fit the data.
The two best candidates in terms of fit, the gamma and the log-normal, also
had the strongest underlying justifications. Of the two, only the log-
normal exhibited a "good" fit by common statistical standards.
Having discovered the ability of the log-normal distribution to fit the
observed data we now reverse our discussion and hypothesize that the magni-
tude of crude pipeline spills is distributed log-normally. With some un-
avoidable repetition we will defend this hypothesis.
D.4.1 Characteristics of the Log-Normal Distribution
Since a primary objective of modeling the pipeline leak process is to
estimate the frequency of events for which direct data is not available, it
is necessary that the hypothesis (of log-normality) exhibit a reasonable
theoretical foundation. Not only must the log-normal distribution fit the
observed data over reported ranges, but there must also be a reasonable ex-
planation to justify extension of the distribution into ranges void of data.
The log-normal distribution can be derived as the model for a process
whose value results from the multiplication of contributing factors just as
the normal distribution is derived as the limiting form of a process whose
value results from the addition of contributing factors. In the case of
the normal distribution, the well known Central Limit Theorem shows that
the individual distributions of the contributing factors (random variates)
does not affect the resulting normal tendency of the sum. A simple example
is the sum of heads achieved in a sequence of flips of a "fair" coin. Each
individual trial (flip) is a binary distribution with only two possible and
equally likely outcomes. The sum of "heads" is a binomial distribution
423
-------
which approaches the normal distribution as the number of trials increases.
An equivalent "central limit theorem" exists for the log-normal distribution
(ref., The Log-Normal Distribution. J. Aitchison and J.A.C. Brown, Cambridge
University Press, Cambridge, 1957).
The log-normal distribution is the model of a random process variate
whose logarithm follows the normal distribution with parameters u (mean) and
a (standard deviation). Thus, if y = Inx is normally distributed, the
probability density function g(y) for y is:
-V (y-y)2l ; - <
[2a2 J
y <
Since y = Inx is equivalent to x = e^ which is a strictly increasing function
of y, we can transform g(y) using the Jacobian of y(x), yielding:
-L (lnx-u)2 |I|
2a x
f(x) = g[y(x)l ||£| • -L- exp
L J UA ov^F
Since for all values of y, x = e^ is positive, it follows that:
f(x) =
which is the log-normal distribution.
; 0 < x < <»
Figure D-l displays several log-normal curves with various values of u
and a. In the normal distribution, u specifies a location (the mean value)
and a specifies a scale (the standard deviation). In the log-normal distri-
bution u becomes a scale factor and a becomes a shape factor.
The log-normal distribution represents many familiar processes. Exam-
ples are:
• Distribution of personal incomes
• Size of an organism (simple life forms) whose growth rate
is subject to many small impulses (food, light, temperature,
cell division, etc.)
• Distribution of particle sizes obtained from breakage (ref.,
The Mathematical Description of Certain Breakage Mechanisms
Leading to the Logarithmic-Normal Distribution. B. Epstein,
Journal of the Franklin Institute, 1947).
424
-------
Figure 0-1. Log-normal distributions with values values
of u and a.
425
-------
The prospect of relating the sizes of oil spills from pipelines to the sizes
of particles resulting from dropping a china cup on a tile counter may or may
not appeal to one's reason. Certainly, in both cases, it seems evident that
there are more small spills than large spills as there are more small china
particles (even dust) than large particles. Also obvious: There are no
negative spills nor are there negatively sized particles.
The fundamental support of the hypothesis is that the key factors which
determine spill size contribute multiplicatively. It is clear that spill
magnitude is directly proportional to leak rate and correction shutdown re-
sponse time. Leak rate is further proportional to the area of the opening
in the pipe and the square root of the internal line pressure. Correction
time is either proportional to the ratio of leak rate and line flow (if leak
detection monitoring is sensitive to leakage as a percent of flow) or simply
proportional to leak rate (if detection is based on visual search dependent
on leak volume alone). The key factor which underlies the mechanics of the
spill process is proportionality:
• The larger the line the larger the spill
• The higher the pressure the greater the leak rate
• The greater the split or opening the greater the leak rate
• The larger the time till detection the greater the spill.
and so on. The exact functional form relating spill size to these factors is
hot so important. Clearly, these major factors contribute in a multiplica-
tive as opposed to additive fashion. This observation strongly supports the
log-normal hypothesis.
D.4.2 Goodness of Fit
Table D-3 (see Section D.3) gives a comparison of actual versus esti-
mated spill frequencies for various spill magnitude ranges. Figure D-2 pre-
sents a graphical comparison of the same data. Additionally, Figure D-2
gives the x2 values as a measure of goodness of fit for each of the five
years (1971-1975) as well as for the five-year totaled values.
The chi-squared (x2) goodness-of-fit test is the most commonly used pro-
cedure for evaluating distributional assumptions. The use of the test in-
volves grouping observed data into frequency cells. The resulting cell fre-
quencies are compared with the expected frequencies from a proposed distribu-
tion. This comparison generates a test statistic which approximates a chi-
square variate. The test of the proposed distribution is in the form of a
statistical test of the hypothesis that the observed data come from the pro-
posed distribution. As the value of x2 (the test statistic) increases the
probability that the observed data came from the proposed distribution dimin-
ishes. A level of significance is usually established to determine acceptance
or rejection of the hypothesis. The level typically adopted is five percent
(or .05), meaning that x2 values exceeding the .05 level could have occurred,
426
-------
•a o
•a o
§o o o LO
§O O vo evi
c\j «r co •—
•— o
o o o o **
o *•• *J *^ •*-*
Arf O
o o o o o us
tf) '^ CM ^ - 00 ••
APAPAPAPAPAP
FIVE YEARS
X2 « 1-55
A = ACTUAL
P * LOG-NORMAL PREDICTION
APAPAPAPAPAP
1977
X2 * 2.36
APAPAPAPAPAP
1972
X2 ' 3.87
APAPAPAPAPAP
1974
X2 = 1.84
APAPAPAP APAP
1973
X2 ' 3.20
APAPAPAPAPAP
1975
X2 - 5.10
Figure D-2. Comparison of predicted and observed spill-frequencies (crude),
427
-------
were the hypothesis true, with a chance of less than one in twenty. The x2
test statistics are calculated using expression (1), Section D.3.
The x2-values for the five years data on spills from crude pipelines,
using the log-normal distribution f(x;y,a), y = 2.31, a = 2.94, are:
Year x2
1971 2.36
1972 3.87
1973 3.20
1974 1.84
1975 5.10
All five years 1.65
The x2 value at the .05 level (five degrees of freedom) is 11.07. It is
clear therefore that the proposed distribution provides an exceptional fit of
the observed data.
D.4.3 Conclusions
The distribution of spill sizes from U.S. crude pipelines over the five
years 1971 through 1975 is reasonably modeled by a log-normal probability
density function, (f(x;y,a), u = 2.31, a = 2.94. This function is displayed
in Figure D-3. The average yearly distribution of spills and barrels lost
is given in Table D-4 and depicted by Figure D-4.
Regarding the question of spill frequency below the reporting threshold,
it is seen that the frequency of spills increases radically as the spill mag-
nitude decreases. The mode of the log-normal function (y = 2.31, a = 2.94)
occurs at about the .0018 barrel (9.7 oz or 286 cc) level. The median occurs
at close to ten barrels (almost half of all spills are ten barrels or less)
and the average (mean) spill is about 300 barrels.
From Table D-4 it appears that about 70 percent of all spills which
occur are not reported, being below the 50 barrel OPS threshold. In terms
of volume lost, however, spills in the 0-50 barrel range, while numerous,
account for only 2.1 percent of the total spillage from crude pipelines.
D.5 PRODUCT SPILLS
The estimation methodology was applied to product spills from pipeline
leaks with similarly favorable results. Table D-5 contains a summary of
product spill frequencies for the five-year period covered by the data base.
Products included were:
428
-------
sfiu tin limn n
l « • Ml. • • >-M
»iu sut (MMUI
•UUMCHL MM (IIFKItl
Figure D-3. log-normal density function.
429
-------
TABLE D-4. ANNUAL DISTRIBUTION OF SPILL FREQUENCIES, BARRELS LOST (CRUDE)
Range
(Barrels)
0 -
10 -
50 -
100 -
200 -
400 -
800 -
1600 -
10
50
100
200
400
800
1600
25000
Frequency
208
92
33
28
22
16
12
17
Percent
49
21
8
7
5
4
3
4
Barrels Lost
548
2,248
2,391
3,969
6,233
9,262
13,023
93,326
Percent
Oa
2
2
3
5
7
10
71
TOTAL 428 131,000
aLess than 1/2 of- one percent.
430
-------
OOOS3
- OOS21
(U
u
c
o
•r—
U
(/I
(U
•o
(U
(O
3
-------
TABLE D-5. PRODUCT SPILLS FROM LINE PIPE (NO. OF SPILLS)
Range
(Barrels)
50 -
100 -
201 -
400 -
800 -
1600 -
100
200
400
800
1600
25000
1971
7
7
15
21
9
15
1972
8
14
14
18
17
13
1973
7
13
14
9
6
15
1974
7
6
8
6
11
11
1975
9
11
17
9
15
15
5-Year
Total
38
53
68
63
58
69
74 84 64 49 76 347
432
-------
• Heating/fuel oil
• Kerosene
• .Gasoline
• Diesel
• Natural gas liquid/condensate gas
• Ammonia.
As with the estimate for crude, only leaks from the line pipes were considered.
Spills or leaks from valves, pumps, tanks, etc. were excluded.
The best log-normal fit to the five-year data was obtained with u = 6,
a = 1.55. The goodness-of-fit for the five-year data was even better than
the "five-year fit" on the crude data, with x2 = -70. Figure D-5 displays
the fit of the log-normal distribution to each of the five years. The x
values for each of the years data are:
Year Y
2
1971 5.71
1972 2.64
1973 3.95
1974 3.88
1975 3.48
All five years 0.70
Considering again that the x2 value (5 D.F.) at the .05 significant level
is 11.07 shows the remarkable fit of the log-normal distribution to the ob-
served data.
Table D-6 provides a tabulated comparison of actual versus recorded
spill frequencies. Table D-7 gives the average annual distribution of spill
frequencies and barrels lost by spill magnitude ranges.
Figure D-6 depicts the log-normal probability density function, f(x;y;o),
u = 6, a = 1.55. Figure D-7 gives cumulative density functions for spill
frequencies and barrels lost in relation to spill size.
A comparison of the log-normal distributions of crude and product spills
is noteworthy. The mode (or peak) of the crude distribution occurs at the
.0018 barrel level, while the mode for product spills occurs at 37 barrels.
This indicates that crude spills increase in frequency as spill size decreases,
almost to zero, while product spills "peak out" at around the 37 barrel level.
The median of crude spills is at about ten barrels, while for product '
spills the median is at about 400 barrels. While half of all crude spills
are ten barrels or less, half of all product spills are 400 barrels or less
(or conversely - larger than 400 barrels).
433
-------
8
ca
§ §
§ §
a
o
CM
LO
CM
t
O
o
VO
A * Actual
P » Log Normal Prediction
° =17",
i& Ci
*•
K\\\\VI
f7
x ,
y^X
1
A P A
*
X
x
x
X
x
x
x
X
X
X
X
X
^^ ^
x
•v
X
X
^
—
X
X
X
/
x
X
X
x
—
PAPAPAPAP
FIVE YEARS
X2 • -70
.UJ,J
*
^^•a
J
x^
X
|7
X
x
x
x
X
X
x
- — " -
X
X
;^~j
X
X
x
APAPAPAPAP AP
1971
X2 « 5.77
7~
z.
•IBM
X
X
x
x
__
7
/
/
—
/
7
/
/
/
/
X
^M*«
_
X
x
x
APAPAPAPAPAP
X
X
X
X
X
—
~^^m
X
/
L.
7]
X
X
7—
M^HH
,\\\\\N
—
APA PAPAPAPAP
1972
2.64
XI
x
x
X
X
X
x
X
x
x
APAPAPAPAPAP
1974
2
1973
« 3.95
\\
P
•-^
/.
^
3.33
A P APAPAPAPAP
1975
\ * 3.48
Figure D-5. Observed and predicted product spill-frequencies,
434
-------
co
CJ1
TABLE D-6. PREDICTED AND ACTUAL SPILL FREQUENCIES (PRODUCTS)
Interval
fUn,
0 -
10 -
20 -
10 -
40 -
SO-
100 -
200 -
400 -
800 -
1600 -
It Actutl
10
20
10
40
50
100 7
200 7
400 IS
100 ' 21
1600 9
25000 IS
1*71
frttCI Itrrtli Actuil
.7 i
l.i 21
I.I 44
I.I tl
I.I 80
8 598 8
12 1.757 14
IS 4.240 14
IS 8.40S 18
12 11.685 17
16 69.645 U
1972
frtdO Itrrtlt
.1 i
1.7 25
1.9 48
2.0 70
2.0 8*
» 664
U 1.950
16 4.706
16 9.128
11 IS. 187
17 77.218
117)
Actiul »rrt° limit
.( 4
1.) 20
l.i 17
I.S 54
l.i tl
7 7 ill
U 10 1.508
14 U 1.619
9 11 7.211
t 10 11.744
li 1) SI.7U
1174
AcUil trt*O
.i
1.0
l.i
1.2
I.I
7 i
t t
8 10
t 10
II 8
II 10
1 tori-til
>
IS
21
42
il
19t
1.164
2.109
s.st*
9.067
46.142
I»7S
Actiul fredO
.-- •»
I.S
1.8
I.I
1.8
9 8
II 12
17 IS
9 IS
IS 12
IS It
Ftvt-Itir 1»Ult
ItrrtU
i
2)
44
64
81
60S
1.777
4.288
8.499
11.818
70.422
Actiul frtdO
1.1
6.8
7.9
I.I
1.0
18 16
SI 54
68 it
. 61 66
S8 54
69 70
1 hrrtlt •
21
104
197
284
162
2.702
7.919
19.158
17.975
61.829
1I4.6SI
aLog-normal estimate.
-------
TABLE D-7. ANNUAL DISTRIBUTION OF SPILL FREQUENCIES
BARRELS LOST (PRODUCTS)
Range
(Barrels)
0
50
100
200
400
800
1600
- 50
- 100
- 200
- 400
- 300
- 1600
- 25000
Frequency
7
7
11
13
13
11
14
76
Percent
9
9
14
17
17
14
18
Barrels Lost
194
541
1,588
3,832
7,595
12,366
62,930
89,046
Percent
0
1
2
4
9
14
71
436
-------
f(x;p,o) \i = 6, o = 1.55
1 I
,0020
.0015
co
.0010 •
.0005 '
I i
HISTORICAL DATA (TYPICAL)
50 100 200
400
SPILL SIZE (BARRELS)
800
Figure D-6. Log-normal distribution, product spills,
-------
co
00
CUMULATIVE DENSITY OF SPILLS
CUMULATIVE DENSITY OF BARRELS LOST
00 O
o o o
CO 10
SPILL SIZE (BARRELS)
Figure D-7. Cumulative density functions (products).
-------
The average crude .spill is about 300 barrels, the average product spill
about 1166 barrels. In short, product spills are, on the average, somewhat
larger than crude spills. This is an expected result since products are
generally lighter and less viscous than crude.
439
-------
APPENDIX E
METHODOLOGY
E.I VISUAL AND AIDED VISUAL LINE OBSERVATION
E.I.I Visual Inspection by Air or Ground Level
(See Table 46 methods (a) through (f) and Sections 5.3.2.1 and 7.3.1.3.)
E.I.2 Visual Inspections by Ground Patrol with Hydrocarbon Detector or
Other Comparable Device
(See Table 46 method (h) and Sections 5.3.2.1, 5.3.2.4 and 7.3.1.1.)
E.2 OIL SPILL DETECTORS ON OR NEAR THE WATER
E.2.1 Oil Spill Detectors
(See Table 47 (c) and Sections 5.3.2.2 and 7.3.1.2.)
E.3 INTERNAL FLUID VARIATIONS DURING TRANSFER
E.3.1 Pressure Deviations
(See also Table 48 (a) and Sections 5.3.2.3 and 7.3.1.3.)
Principle of Operation
The pressure deviation of leak detection methods basically involve con-
tinuous monitoring by computer of line pressure at various locations along
the pipeline is carried out during oil transfer. If pressure deviations
(i.e., pressure drops, etc.) are excessive and exceed a set point value,
system alarms are generated.
Sensitivity
Pressure deviation inspection is most sensitive for large leaks close
to the discharge pumps and close to the downstream end of the pumping sta-
tions. At locations where the line pressures are low, such as upstream of
the pumps, large leaks cause small pressure drops that are difficult to de-
tect.
440
-------
Manufacturer and Costs
All necessary equipment and components for typical pressure deviation
inspection systems are commercially available. Total system costs are gen-
erally much lower than other continuous leak monitoring methods used during
petroleum transfer.
Advantages
This is a commonly used inspection method for detecting large leaks. It
is simple to implement.
Disadvantages and Limitations
It is extremely difficult to detect small leaks using this inspection
method. Because of the principle used and equipment limitations, the follow-
ing items (and others) contribute to the poor sensitivity of this method:
• Variations in input or output tank heads
• Changes in fluid properties
» Changes in temperature
• Flow variations affect line pressure drop because pressure
drop varies as the flow rate squared
• Leaks are inadvertently compensated for by pressure control
valves operating slightly when a system is operating at
maximum capacity under pressure control
• Setpoints are usually set very high to prevent false shut-
downs. In these instances/ only very large leaks or rup-
tures can be detected.
E.3.2 Flow Rate
E.3.2.1 Comparison—
(See also Table 49(c) and Sections 5.3.2.3 and 7.3.1.3.)
Principle of Operation
Flow rate comparison inspection detects pipeline leaks by measuring the
difference in the rate of flow at two locations. Computer systems are avail-
able that can continuously compare flow rates every few seconds and generate
an alarm when deviations exceed a setpoint value (one percent to five per-
cent of normal flow rate). Alarm levels are usually set to take into ac-
count changes in pumping rate, temperature or density of the oil, etc. A
variety of transducers that provide signals proportional to rate of flow are
commercially available. The most commonly used types include ultrasonic,
turbine, and orifice transducers.
441
-------
Capability
This leak detection equipment is generally used to inspect for large
leaks in the pipeline. The method generally works best on lines where the
flow is relatively stable.
Manufacturer and Costs
Flow rate comparison systems are commercially available from a number
of manufacturers. Costs vary widely depending upon line location and dimen-
sions, transducers, and the required accuracy and automation. Typical manu-
facturers of systems include Daniel Industries, Adec, Inc., and Waugh Con-
trols, etc.
Advantages
This inspection method is widely used and provides rapid detection of
large leaks.
Disadvantages and Limitations
The method can only be used to detect major oil leaks. Also, there is
a tendency by operators to raise setpoints to reduce the possibility of
alarms and thus decrease leak sensitivity.
E.3.2.2 Flow Rate Deviation—
(See Table 48(d) and Sections 5.3.2.3 and 7.3.1.3.)
The flow rate deviation method provides continuous leak detection of
the pipeline by measuring the deviations in flow rates at specific flow
stations. If the A flow rate exceeds a certain value (for example, unex-
plained changes of normal flow rate (one to five percent)), a leak alarm is
generated.
This leak detection is similar to the flow rate comparison except that
a comparison of flow rate at another flow station is not required.
E.3.3 Volume Comparisons (Balance)
(See also Table 48(b) and Sections 5.3.2.3 and 7.3.1.3.)
Principle of Operation
A variety of volume comparison techniques for detection of leakage is
commonly used in the pipeline oil transportation industry. The basic opera-
tion is to measure the input volume, output volume and line pack to check
metered barrels into the pipeline against barrels measured out. These mea-
surements are generally based on the following equation:
- VQ
442
-------
where
V, = leak volume during time t
V.j = volume of liquid put into system during time t
V = volume of liquid taken out of system during time t
AVS = change in volume of liquid in pipe and tanks in system.
Corrected flowmeter readings are used to provide measurements of Vi and VQ
at the input and output. Vs is usually computer corrected for line pack
effects by measurements of temperature and pressure at various locations on
the pipeline.
If the line is leak-free, no crude is lost. Volumes can be measured
by meters (i.e., turbine flowmeters, etc.) and by tank gages. The metering
system provides the required volume data with the computerized supervisory
control system automatically gathering, comparing and correcting for various
parameters (temperature, pressure, density of crude, etc.). Computerized
control systems are used that make continuous volume comparisons over typi-
cal time intervals ranging from every few minutes to every one to two hours.
An alarm is generated when a volume comparison difference exceeds a prede-
termined setpoint. Settings are made taking into account corrected volumes
and system tolerances in transducers, electronics, power variations, etc.
Capability
This leak detection equipment is used primarily to inspect for large
leaks in a short period of time and small leaks over a long period of time.
Manufacturer and Costs
Volume comparison systems are commercially available from a number of
manufacturers. Costs vary widely depending upon line locations and dimen-
sions, transducers, and the required accuracy and automation. Typical
manufacturers of'systems include Adec, Daniel, Siemens, and Waugh.
Advantages
Equipment can be used on an almost continuous basis. Systems can be
automated to provide simple operation. Major leaks can be detected in a
short period of time.
Disadvantages and Limitations
Some of the main disadvantages and limitations of this method for in-
spection purposes are:
443
-------
• Detects leaks after they occur
• Difficult to detect slow leaks that over a period of time may
result in a major oil spill
• Cannot detect a catastrophic failure in sufficient time to
prevent a major oil spill
• Tendency by operators to raise setpoints to reduce alarms be-
cause of line pack and other considerations
• Detects leaks only about once per hour for most commonly used
systems.
E.3.4 Mathematical Modeling
(See also Table 48(f) and Sections 5.3.2.3 and 7.3.1.3.)
Principle of Operation
Mathematical modeling is a real-time computerized pipeline monitoring
method for detection of small amounts of oil leakage; only losses in the
inventory are of interest and the inspection is a form of dynamic inventory-
ing of the pipeline product. The method is affected by solving momentum and
continuity equations for a specified pipeline and/or hose string network.
The differential equation that results is solved by iterative methods with
suitable techniques so that the mathematical model is run in real time and
can be trimmed as required to fit the actual pipeline. Mathematical models
are available that fit the pipeline during start-up and compensate for.
transients such as pump start-up, shutdown, valve closures, water-hammer
effects, etc. that normally occur in the pipeline. In addition, models can
provide accurate means of compensating for line pack due to product compres-
sibility, in pipe-wall and hose-wall deformation.
Modeling methods require that a significant amount of information be
known and a variety of measurements made continuously. These include pro-
duct information (density, viscosity, etc.); pipeline dimensions and mate-
rials; valving; and product propagation information (flow and pressure at
both ends of pipeline, temperature gradient of the product, etc.).
Capability
Mathematical modeling can be used for continuous leak inspection of the
pipeline. The method also can be used during static or hydrostatic leak
tests.
Sensitivity
Estimated sensitivity is about 0.1 percent of the flow rate at the time
the leak occurs. For example, if 100,000 barrels per hour is offloaded, a
100 barrel per hour leak can be detected.
444
-------
Manufacturer and Costs
Mathematical modeling systems for leak detection inspection are commer-
cially available from a few companies. The leak detection equipment is in
current use on oil pipelines. Costs are typically less than one-half percent
of the cost of the pipeline. Costs are even lower if the equipment can be
used with existing supervisory control systems.
Advantages
Some of the" main advantages of this inspection method are:
• Computerized reduction
• Good failure detection
• Provides leak detection improvements over conventional
hydrostatic pressure tests
• Can be used in conjunction with supervisory control systems
• Requires only repeatable rather than high accuracy flow meters
• Limited continuous inspection.
Disadvantages and Limitations
One disadvantage is that the leak can only be detected after the flow
reaches a meter. Hence, for long distances between meters significant spill-
age can occur for large leaks or ruptures before detection.
This method is new and not totally proven on a large number of lines.
Although automatic, it may require trained personnel to properly interpret
results or maintain the system. Commercial availability of these systems
is limited because of the small number of companies currently involved in
this area.
E.3.5 Negative Pressure Surge
(See Table 48(j) and Sections 5.3.2.3 and 7.3.1.3.)
E.4 DETECTION AND LOCATION OF LEAKED OIL ON OR AT A SHORT DISTANCE FROM
PIPELINE
E.4.1 External Rods with Passive Acoustic Sensor
(See Table 48(n) and Sections 5.3.2.4 and 7.3.1.4.)
E.4.2 Passive Acoustic Array
(See also Tables 49(o) and 55(a) and Sections 5.3.2.4 and 7.3.1.4.)
445
-------
Principle of Operation
Experimental results have shown that acoustic signals generated in pipe-
line from external impacts, excessive internal stresses from material de-
fects and damage, precursor internal stresses just before a leak or material
failure, are all different; each event produces a characteristic signal that
can be differentiated from the other. These acoustic signals are commonly
called "acoustic emissions" and are excellent indicators of incipient fail-
ure. Generally, these acoustic emissions, except for external impacts, are
repetitive. Repetition rate usually increases to a peak value, then drops
off slightly, and then increases dramatically just before a critical mate-
rial failure or leak occurs. The acoustic emissions only occur when the
component is stressed - externally loaded or pressurized. Acoustic emission
signals are complex, dependent upon structure and fault type and the fre-
quency typically extends to the megahertz range.
The same acoustic system that is used to detect the continuous waves
generated at a leak source and which propagate along the pipeline can, with
additions to the signal processor, be used to detect the acoustic emission
signals. Using known wave attenuation characteristics of the pipeline, and
also using suitable signal enhancement, counting, and processing technique,
the location and condition of the flawed area may be determined.
Capabilities
Passive acoustic array inspections using acoustic emissions potentially
can be applied to effectively reduce oil spill risks by continuously moni-
toring the pipelines for actual failures (leaks) and impending failures
(internal defects that may lead to a failure).
Sensitivity
Defect location depends upon a variety of factors such as pipeline
material, size and length, acoustic transducer design and spacing, and
signal processing techniques. Additionally, hydrostatic tests can be used
advantageously to enhance the internal defects so that such defects can be
detected, whereas such defects it might not be detected at normal operating
and flow conditions.
Advantages
Some of the main advantages of this inspection method are:
• Excellent potential for incipient failure detection
• Computerized automatic system can be adapted to existing
supervisory control systems
• Commercial system currently available for similar applications
such as periodic proof testing of tanks, pressure vessels, etc.
• Permanent records
446
-------
• Continuous monitoring
• Locates defects for more detailed inspection by other means.
Disadvantages and Limitations
The main disadvantage and limitation of acoustic emission leak detection
is that incipient failure data is subject to interpretation as to the sever-
ity of the defect and how long before the defect grows to a critical size and
then causes a rupture, leak, etc. Also, system effectiveness and performance
specifications are uncertain.
Applications
Two slightly different passive acoustic array systems (see Section
7.3.1.4) are selected in this study for two main applications. The first
system is for installation on new lines or on lines located in high risk
areas such as underwater. Such systems are expected to be highly sensitive
and capable of detecting most impending failures and leaks including outside
force damage and ruptures. The second system is for retrofit installations.
These types of systems are of lower sensitivity but expected to be capable
of providing prevention of failures by detecting damage by outside forces
and minimizing spill size by detecting ruptures.
E.4.2.1 Passive Acoustic Array - Systems for New Lines--
(See also Sections 5.3.2.4 and 7.3.1.4.)
Installation
Acoustic sensors with signal conditioning equipment are expected to be
installed at approximately five locations each mile. A multiconductor cable,
running the length of the line provides both power and transmission of the
signal from each acoustic sensor. Master units supply the power, signal pro-
cessing and control. These units would typically be located at each pump
station and two locations between each pump station.
Capabilities
Systems are expected to be capable of both preventing most failures and
early detection of most leaks. Capabilities include detection of outside
forces, damage, internal defects, small leaks and ruptures.
E.4.2.2 Passive Acoustic Array - Retrofit Systems—
(See also Sections 5.3.2.4 and 7.3.1.4.)
Installation
Acoustic sensors would be installed at the pump station and at various
locations, typically at four stations (approximately ten miles apart), be-
tween each pump station. Signal conditioning and telemetry would be used
for remote monitoring of sensor signals.
447
-------
Capabilities
Systems are expected to be capable of detecting damage by outside
forces and rupture detection.
E.5 PERIODIC PRESSURE TESTS
E.5.1 Pressure Static
(See also Table 50(a) and Sections 5.3.2.5 and 7.3.1.5.)
Principle of Operation
The pipeline is operated in an intermittent manner at nominal operating
pressure; static pressure measuring techniques are used to detect a leak
when sections of the line are closed off and shut down. If the pressure
holds, the line is considered tight. High accuracy pressure gages are used
to monitor the line pressure. High leakage rates (i.e., greater than 500
1/hr) can be detected over short time intervals (about 15 minutes) by mea-
suring the static pressure drop. Detections for lower leakage rates require
that effects such as temperature be taken into account by waiting until the
temperature stabilizes.
Advantages
This is a commonly used inspection method that is of low cost, simple
to implement.
Disadvantages and Limitations
Some of the main disadvantages and limitations are:
• Requires leak detection method if leaks are located
• Variations in temperature, etc. limit sensitivity of leak
inspection
• Difficult to detect slow leaks
• Less sensitive than hydrostatic pressure difference method.
E.5.2 Hydrostatic - Pressure Drop and Pressure Difference
(See also Table 50(b) and 50(c) and Sections 5.2.2.5 and 7.3.1.5.)
Principle of Operation
The pressure drop method of inspection uses pressure difference gages
that are installed across a series of block valves that isolate sections of
an empty pipeline or hose string. The empty sections are then pressurized,
typically to 600 psi. Pressure difference gages will indicate if a leak
exists after a suitable period of time. Actual stabilization time depends
upon the required tightness (leak rate allowed) of the system and temperature
448
-------
effects. Usually, a derivative dAP/dt is used to show the deviation of dif-
ferential pressure as a function of time in order to simplify conclusions of
leakage. Numerous types of pressure difference gages are commercially avail-
able for this measurement.
Variations of this inspection method can be made. One variation is to
pressurize the line with gases such as helium and detect leaky areas with
helium leak detectors. Passive ultrasonic detectors and the passive acoustic
array can also be used to detect escaping gas. In another variation, the
line could be pressurized and sections of the line closed off. Then the
static pressure of each section could be accurately measured. This method
can give, to some extent, incipient fault detection. Stresses from proof
pressures slightly above normal may cause leaks to prematurely occur and be
detected; these leaks, however, would have eventually occurred because of
corrosion or other effects at some later time at normal operating pressures.
Advantages
This inspection method is simple, provides good incipient failure detec-
tion and is a widely used inspection technique. It is a high cost inspection
since the system must be shut down.
Disadvantages
Some of the main disadvantages of this inspection method are:
• Requires out-of-service operation
• Potentially can cause damage to pipeline components if test
pressure is excessive
• Requires leak detection method to locate leak
• Downtime required because of time for temperature stabiliza-
tion can be of long duration (24 to 72 hours)
• High cost to retrofit.
E.6 CORROSION INSPECTION
E.6.1 Change or Add Inhibitors as Needed
(See Sections 5.2.2.6 and 7.3.1.6.)
E.7 STANDARD NON-DESTRUCTIVE TESTING
E.7.1 Inspection of Sample of Line for Wall Thickness
Changes by ultrasonics or comparable technique (see Table 52(a) and
Sections 5.2.2.7 and 7.3.1.7).
449
-------
E.8 INSPECTION PIGS
E.8.1 Magnetic Flux Inspection Pigs
(See also Table 53(a) and Sections 5.2.2.8 and 7.3.1.8.)
Principle of Operation
A magnetic field is induced into a pipe wall around the circumference
and the field flows- in a longitudinal direction. In an undamaged pipe, a
smooth flow of magnetic lines of flux all remain within the pipe body wall.
A damaged or unnatural area of the pipe affects the flow of the lines of
flux and causes the flow to "bridge" across this area and create a magnetic
disturbance or flux leakage. This flux leakage is proportional to the size
and depth of the damaged area.
One of the most widely used magnetic flux inspection pigs is the AMF
Tuboscope Linalog. The instrumented pig uses electromagnets to induce the
magnetic field and it is sent through the pipelines, typically at a few
miles per hour, propelled by oil or water flowing through the pipeline.
This device is expected to be operated in salt water next year. A magnetic
tape recorder is installed in both inspection pigs and is used to store the
electromagnetic data. Data tapes are then reduced and analyzed after the
pigs are run through the pipeline.
Capability
Magnetic flux inspection pigs are the most widely used type of inspec-
tion pigs. The most important capabilities of the device is that it can be
used to measure the severity of corrosion. It can also be used to inspect
for a variety of pipeline defects including hardspots, manufacturing defects
and flaws, girth welds, gouges, pits, etc. Additionally, the device can be
used to help evaluate the effectiveness of the cathodic protection system.
Sensitivity
The sensitivity of the magnetic flux inspection pig is quite good for
corrosion or pitting. Typically it is graded in three ranges of corrosion
severity: 15-30 percent of nominal wall; 30-50 percent of nominal wall;
greater than 50 percent of nominal wall. Defects as small as 1/8 are claimed
as detectable by the manufacturers.
Manufacturer .and Costs
The two main manufacturers of these magnetic flux inspection pigs are
AMF Tuboscope, Inc. and Vetco Pipeline Services. A similar type of inspec-
tion pig is currently under development in Canada.
These devices are usually provided as an inspection service that in-
cludes inspection pig, operating personnel and data analysis. A typical
cost for inspection of 20 miles of 36" pipeline is about $20K.
450
-------
Advantages
Advantages include the following:
• High reliability
• Locates defects
• Permanent record
• Monitors integrity of line
• Locates potential failures before they reach catastrophic
failure
• Helps evaluate effectiveness of cathodic protection
• Commercially available.
Disadvantages and Limitations
For maximum effectiveness, frequent inspection, once or twice a year,
are desireable. Hence, high inspection costs normally limit the number of
inspections.
Data records are difficult to interpret and require human interpretation.
It is also possible to have anomalies that are difficult to interpret. For
example, a weld that penetrates into pipe may result in cavitation downstream
causing corrosion and erosion. The girth weld would be picked up but the
adjacent anomalies may not show up because the operator may be monitoring
only one pulse from the device in that area.
The electromagnetic type cannot determine if a defect is in the inside
or outisde of a pipe. The permanent magnet type can get stuck in a pipeline
and is difficult to remove without cutting out a section of the pipeline.
Both devices do not adequately detect thin cracks.
E.9 SURVEY-PIPELINE SYSTEM CHARTING AND DEPTH OF BURIAL
E.9.1 Depth of Cover by Sonar or Other Comparable Techniques
(See Table 54(b) and (c) and Sections 5.2.2.9 and 7.3.1.9.)
E.9.2 Charting of Line Pipe
(See Table 54(e) and (f) and Sections 5.2.2.9 and 7.3.1.9.)
E.10 MISCELLANEOUS
E.ll.l Preventive Program for Outside Forces
(See Reference 12.)
E.11.2 Passive Acoustic Array
(See Section 5.3.2.10.)
451
-------
TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO.
-&c
-cyo
2.
3. RECIPIENT'S ACCESSIONING.
4. TITLH AND SUBTITLE
Petroleum Pipeline Leak Detection Study
5. REPORT DATE
January 1982
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
John R. Mastandrea
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Science Applications, Inc.
101 Continental Blvd.
El Segundo, CA 90245
10. PROGRAM ELEMENT NO.
1NE 826
11. CONTRACT/GRANT NO.
68-03-2532
12. SPONSORING AGENCY NAME ANO ADDRESS
Municipal Environmental Research Laboratory- Cin., OH
Jffice of Research and Development
J.S. Environmental Protection Agency
Cincinnati, OH 45268
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/600/14
15. SUPPLEMENTARY NOTES
J. S. Dorrler, R. A. Griffiths: Project Officers (201-321-6629)
16. ABSTRACT
This study reviews and analyzes the U.S. petroleum pipeline system, accidental
spills, and spill prevention programs. It concludes that improved pipeline spill
prevention measures are needed, because pipeline systems are aging, population
densities near lines are increasing dramatically, and new lines are expected to be
larger and longer.
An approach to developing a spill prevention program is presented. Then,
recommended spill prevention programs for individual pipeline systems are
described. These programs consist of scheduled inspection and/or leak detection
methods and are shown to be capable of significantly reducing the risk of serious
spills. Practical considerations such as the cost of inspections and spillage are
also included.
This effort involved two tasks: (1) proper assessment of the risk, and (2)
selection of optimum prevention measures. Thrs report solves two problems that
formerly prevented the accomplishment of these tasks. First, the contribution of
pipeline age, dimension, etc., to the overall risk could not be assessed, primarily
because of limitations in reported pipeline leak data and lack of a comprehensive
analysis measures for reducing the risk (frequency, volume, and the combined
frequency and volume of spills) was not previously available.
7.
KEY WORDS ANO DOCUMENT ANALYSIS
DESCRIPTORS
b.!OENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
'etroleum pipelines
'ipeline transportation
Leak detectors
Pipeline risk analysis
Leak detection
3. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS (ThisReport/
UNCLASSIFIED
21. NO. OF PAGES
472
20. SECURITY CLASS (This pafe)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
452
-------