Standard
must provide responses to each question that is applicable to
their operations. Responses must cover all PSM-related operations.
Please indicate that a question is "Not Applicable" if
it addresses functionality outside the scope of the operations,
and briefly explain why.
OMB#
1218 – 0239
Expires xx-xx-xxxx
Public
reporting burden for this collection of information is voluntary
and is estimated to average 40 hours per response, including time
for reviewing instructions, searching existing data sources,
gathering and maintaining the data needed, and completing and
reviewing the collection of information. Send comments regarding
this burden estimate, or any other aspect of this collection of
information, including suggestions for reducing this burden to the
Office of Partnerships and Recognition, Department of Labor, Room
N-3700, 200 Constitution Avenue, N.W., Washington, DC 20210
I.
Management of Change.
Has
the throughput changed from its original design rate? Has the
site conducted a management of change (MOC) procedure for each
throughput change since May 26, 1992?
For
the MOC procedures conducted for the unit(s), has the procedure
listed the technical basis for the change and ALL potential
safety and health impacts of the change prior to its
implementation?
From
the site's list of MOCs, identify the oldest MOC procedure which
might affect the integrity of one or more pressure vessels in the
unit(s). Do these MOC procedures meet all 1910.119(l)
requirements?
Does
the MOC process address temporary changes as well as permanent
changes?
Have
MOCs been conducted on all changes to process chemicals,
technology, equipment and procedures, and changes to facilities
that affect a covered process?
II.
Relief Design.
For
each throughput MOC procedure conducted, has the procedure
addressed a review/analysis of the relief system (includes relief
devices, relief discharge lines, relief disposal equipment and
flare system) to determine if there may be any safety and health
impacts due to increased flow as a result of throughput changes
which might impact the existing relief system?
Guidance:
An MOC procedure is required anytime a change per the
requirements of 1910.119(l) is considered. An MOC procedure is a
proactive management system tool used in part to determine if a
change might result in safety and health impacts. OSHA's MOC
requirement is prospective. The standard requires that an MOC
procedure be completed, regardless of whether any safety and
health impacts will actually be realized by the change.
After
a change in the throughput in the unit(s), did the process hazard
analysis (PHA) team consider the adequacy of the existing relief
system design with respect to the increased throughput during the
next PHA?
Guidance:
Typically, the PHA team does not do a relief system engineering
analysis. However, the PHA team should determine, through proper
evaluation and consultation with the engineering/technical staff,
if the existing/current engineering analysis of the relief system
is adequate for the current/actual unit throughput.
If
the throughput change was implemented between the time the PSM
standard became effective (May 26, 1992) and the time the
original PHA was required based on the PHA phase-in schedule, the
original PHA would need to address the throughput change.
However, if there was a throughput change after the original PHA,
the next PHA update/"redo" or PHA revalidation would
need to address the throughput change. In either event, an MOC
procedure on the throughput change would need to have been
conducted and incorporated into the next scheduled PHA.
Does
the site's process safety information (PSI) include the codes and
standards used in the design of relief systems?
Does the site's PSI
include the relief system design and design basis?
Guidance:
This includes the original design and design changes. Examples of
PSI related to relief devices, their design and design basis
include, but are not limited to such items as:
Identification/descriptor
of each relief device;
A
listing of all equipment which will be relieved through the
device;
Design
pressure;
Set
pressure;
Listing
of all sources of overpressure considered;
Identification
of the worst case overpressure scenario or relief design;
State
of material being relieved (i.e.,, liquid, vapor, liquid-vapor,
liquid-vapor-solid, along with an identification of the material
which was the basis for the relief device selection);
Physical
properties of the relieved materials, vapor rate, molecular
weight, maximum relieving pressure, heat of vaporization,
specific gravity and viscosity; and
Design
calculations.
Similar design and design bases PSI are required for the rest of
the relief system equipment downstream from the relief devices,
i.e., relief vent lines, manifolds, headers, other relief disposal
equipment, and flare stack.
Are
there intervening valves on the upstream or downstream lines
to/from relief devices? If so, does the PHA consider the
possibility that these valves could be closed during operation,
rendering the relief devices non-functional?
If
there are intervening valves on the upstream or downstream lines
to/from relief devices, does the site have effective controls in
place to ensure these intervening valves remain open during
operations?
If
there are intervening valves on the upstream or downstream lines
to/from relief devices, is there an administrative procedure
(e.g., car-seal procedure) to assure these valves are in the open
position during operations? If so, has this procedure been
subsequently audited?
Are there open vents
which discharge to atmosphere from relief devices? If so, has the
PHA considered whether these relief devices discharge to a safe
location?
Guidance: PHA teams must address basic
questions regarding what happens to the hazardous materials after
they are relieved to atmosphere, including:
Are
there negative effects on employees or other equipment that
could cause another release ("domino effects") of
hazardous materials/HHC?
What
presumptions or assessments exist to support that there will be
no negative effects of an atmospheric release of hazardous
materials/HHC?
Are
employees near where relief devices discharge, including
downwind locations (e.g., on the ground, on platforms on
pressure vessels in the vicinity of elevated relief devices,
etc.)?
Could
a release from a relief device cause a release from other
equipment, or could other nearby equipment affect the released
material (e.g., a furnace stack could be an ignition source if
it is located proximate to an elevated relief device that is
designed to relieve flammable materials)?
Part of the site's PHA team's evaluation, after it identifies the
locations of open vents, is to determine if employees might be
exposed when hazardous materials are relieved. If the PHA team
concludes that a current and appropriate evaluation (such as the
use of dispersion modeling) has been conducted, the evaluation
could find that the vessels/vents relieve to a safe location. If
the PHA team determines that this hazard has not been
appropriately evaluated, the PHA team must request that such an
evaluation be conducted, or make some other appropriate
recommendation to ensure that the identified hazard/deviation is
adequately addressed.
Does
the site have a mechanical integrity (MI) procedure for
inspecting, testing, maintaining, and repairing relief devices
which maintains the ongoing integrity of process equipment?
Does
the process use flares? If so, verify that the flares have been
in-service/operational when the process has been running. If the
flares have not been in-service, has the site used other
effective measures to relieve equipment in the event of an upset?
Has an MOC procedure been used to evaluate these changes?
III.
Vessels.
Do
pressure vessels which have integrally bonded liners, such as
strip lining or plate lining, have an MI procedure which requires
that the next scheduled inspection after an on-stream inspection
be an internal inspection?
Does
the site have an MI procedure for establishing thickness
measurement locations (TML) in pressure vessels, and does the
site implement that procedure when establishing the TML?
Does
the site have an MI procedure for inspecting pressure vessels for
corrosion-under-insulation (CUI), and does the site inspect
pressure vessels for CUI?
Does
the site's MI procedure address testing (e.g. leak testing) and
repair of pressure vessels? For example, does the MI procedure
indicate how the testing and repair will be conducted and which
personnel are authorized to do the testing and repair, including
what credentials those conducting the testing and repair must
have?
Guidance:
API 510 requires in-service pressure vessel tests when the API
authorized pressure vessel inspector believes they are
necessary.
Guidance: Recognized and Generally Accepted
Good Engineering Practices (RAGAGEP) that require credentials
include, but are not limited to:
Credentials
for pressure vessel inspectors, see API 510, Section 4.2.
RAGAGEP
for pressure vessel examiners credentials/experience and
training requirements, see API 510, Section 3.18.
RAGAGEP
for contractors performing NDE are the training and
certification requirements ASNT-TC-1A, see CCPS, Section
10.3.2.1, (In-service Inspection and Testing) Nondestructive
Examination.
RAGAGEP
for qualifications for personnel who conduct pressure vessel
repairs, alteration and rerating including qualifications for
welders, see API 510, Section 7.2.1 and the BPVC, Section IX.
RAGAGEP
for certifications at CCPS, Section 5.4 Certifications, Table
5-3, Widely Accepted MI Certifications, and Table 9-13,
Mechanical Integrity Activities for Pressure Vessels.
Were
any deficiencies found during pressure vessel inspections? If so,
how were they resolved?
Guidance:
A deficiency (as per 1910.119 (j)(5)) means a condition in
equipment or systems that is outside of acceptable PSI limits. In
the case of a pressure vessel, this could mean degradation in the
equipment/system exceeding the equipment's acceptable limits
(e.g., operating a vessel, tank or piping with a wall thickness
less than its retirement thickness).
Do
the operating procedures for pressure vessels list the safety
systems that are applicable to the vessels?
Guidance:
Examples of safety systems include but are not limited to:
emergency relief systems including relief devices, disposal
systems and flares; automatic depressurization valves; remote
isolation capabilities, aka emergency isolation valves;
safety-instrumented-systems (SIS) including emergency shutdown
systems and safety interlock systems; fire detection and
protection systems; deluge systems; fixed combustible gas and
fire detection system; safety critical alarms and
instrumentation; uninterruptible power supply; dikes; etc.
Have
there been any changes to pressure vessels or other equipment
changes that could affect pressure vessel integrity, such as a
change to more corrosive feed, a change in the type of flange
seal material used for the vessel heads or nozzles, etc.,? If so,
was an MOC procedure completed prior to implementing the change?
IV.
Piping.
Is
there information in the MI piping inspection procedures or other
PSI that indicates the original thickness measurements for all
piping sections?
Is
there information in the MI piping inspection procedures or other
PSI that indicates the locations, dates and results of all
subsequent thickness measurements?
Is
there anomalous data that has not been resolved for any piping?
(For example, the current thickness reading for a TML indicates
the pipe wall thickness is greater/thicker than the previous
reading(s) with no other explanation as to how this might occur.)
Has
each product piping been classified according to the consequences
of its failure?
Guidance:
If the site inspects and tests all piping the same, regardless of
the consequence of failure of the piping (i.e., piping
inspections are implemented using the same MI program
(1910.119(j)(2) and action/task (1910.119(j)(4) procedure for all
piping without consideration of their consequence of failure or
other operational criteria), then this question is not
applicable.
Based
on a review of piping inspection records, have all identified
piping deficiencies been addressed?
Guidance:
An example of a piping deficiency would be a situation where
piping inspection data indicates that its actual wall thickness
is less than its retirement thickness, and the site has conducted
no other evaluation to determine if the piping is safe for
continued operation. For a discussion on equipment deficiencies
the definition of deficient/deficiency.
How
does the site ensure that replacement piping is suitable for its
process application?
Guidance:
Typically, piping replacements are replacements-in-kind (RIK)
when the process service does not change. However, if the piping
replacement is not an RIK, then an MOC procedure is required.
Does
the site's MI procedure list required piping inspectors'
qualifications, welders' qualifications for welding on process
piping, and when qualified welding procedures are required?
Is
there information in the MI piping inspection procedures or other
PSI that indicates the original installation date for each
section of piping?
Is
there information in the MI piping inspection procedures or other
PSI that indicates the specifications, including the materials of
construction and strength levels for each section of piping?
Does
the site's MI procedure for piping inspections list
criteria/steps to be followed when establishing TML for injection
points in piping circuits?
V.
Operating Procedures – Normal Operating Procedures (NOP),
Emergency Shutdown Procedures (ESP) and Emergency Operations
(EOP).
Are
there established operating procedures, including: normal
operating procedures (NOP), emergency operating procedures (EOP),
and emergency shutdown procedures (ESP)?
Are
operating procedures implemented as written?
Are
there ESP for the all Unit(s), and if so, do these ESP specify
the conditions that require an emergency shutdown?
Guidance:
ESP are usually warranted during events that may include the
failure of process equipment (e.g., vessels, piping, pumps, etc.)
to contain or control HHC releases, loss of electrical power,
loss of instrumentation or cooling, fire, explosion, etc. When
EOP do not succeed during upset or emergency conditions in
returning the process to a safe state, implementation of an ESP
may be necessary.
When normal operating limits for
parameters such as pressure, temperature, level, etc., are
exceeded during an excursion, system upset, abnormal operation,
etc., a catastrophic release can occur if appropriate actions are
not taken. These actions must be listed in the EOP and must
specify the initiating conditions or the operating limits for the
EOP (e.g., temperature exceeds 225oF or pressure drops below 15
psig).
Information typically listed in EOP and/or ESP
includes, but is not limited to the responsibilities for
performing actions during an emergency, required PPE, additional
hazards not present during normal operations, consequences of
operating outside operating limits, steps to shutdown the
involved process in the safest, most direct manner, conditions
when operators must invoke the emergency response plan, or
scenarios when they themselves must stop and evacuate.
Have
control board operators received sufficient training, initial and
refresher, to be qualified to shutdown the units?
Does
the ESP specify that qualified operators are assigned authority
to shutdown the unit(s)?
Are
qualified control board operators authorized or permitted to
initiate an emergency shutdown of the unit without prior
approval?
Do
EOP procedures identify the "entry point," i.e., the
initiating/triggering conditions or operating limits when the EOP
is required, the consequences of a deviation from the EOP, and
the steps required to correct a deviation/upset once the
operating limits of the EOP have been exceeded?
Do
NOP list the normal operating limits or "exit points"
from NOP to EOP; the steps operators should take to avoid
deviations/upsets; and the precautions necessary to prevent
exposures, including engineering and administrative controls and
PPE?
Guidance:
For NOP, the "operating limits" required are those
operating parameters that if they exceed the normal range or
operating limits, a system upset or abnormal operating condition
would occur which could lead to operation outside the design
limits of the equipment/process and subsequent potential release.
These operating parameters must be determined by the site and can
include, but are not limited to, pressure, temperature, flow,
level, composition, pH, vibration, rate of reaction,
contaminants, utility failure, etc.
It is at the
point of operation outside these NOP "operating limits"
that EOP procedures must be initiated. There may be a
troubleshooting area defined by the site's EOP where operator
action can be used to bring the system upset back into normal
operating limits. During this troubleshooting phase, if an
operating parameter reaches a specified level and the process
control strategy includes automatic controls, other safety
devices (e.g., safety valves or rupture disks) or automatic
protection systems (e.g., safety instrumented systems/emergency
shutdown systems), would activate per the process design to bring
the process back to a safe state. Typically, once the predefined
limits for troubleshooting have been reached for a particular
operating parameter, the process has reached a "never exceed
limit". A buffer zone is typically provided above( and below
if applicable) the trouble shooting zone ("never exceed
limit") to ensure the operating parameters do not reach the
design safe upper or lower limit of the equipment/process. This
design safe upper and lower limits of the equipment or process
are also known as the boundaries of the design operating envelope
or the limit above (or below) which it is considered unknown or
unsafe to operate. Once the operating parameter(s) reach the
buffer zone entry point, there is no designed or intentional
operator intervention (i.e., troubleshooting) to bring the
process system upset back to a safe state. Any intervention in
the buffer zone is as a result of the continued activation of the
safety devices and automatic protection systems which initially
activated at the predefined level during the troubleshooting
phase. All of these predefined limits are important information
for operators to know and understand and must be included in the
PSI and operating procedures.
Are
operating procedures implemented as written?
VI.
PHA, Incident Investigation, and Compliance Audits
Findings/Recommendations.
Have
all corrective actions from PHA, incident investigations, MOCs,
and compliance audits been corrected in a timely manner and
documented? Provide a list of all outstanding corrective actions,
the date of corrective initiation, and the projected completion
dates.
Guidance:
There may be instances when a PHA team identifies deficiencies in
equipment/systems which would violate the requirements of
119(j)(5) if left uncorrected. If the site continues to operate
the deficient equipment/system, they must take interim measures
per 119(j)(5) to assure safe operation, and they must also meet
the 119(e)(5) requirements to resolve the findings and
recommendations related to the identified deficiency.
The
phrase from 119(j)(5), "safe and timely manner when
necessary means are taken to assure safe operation", when
taken in conjunction with 119(e)(5) means that when a PHA team
identifies a deficiency in equipment/systems and the site does
not correct the deficiency before further use, the site's system
for promptly addressing the PHA team's findings and
recommendations must assure: 1) that the recommendations are
resolved in a timely manner and that the resolutions are
documented; 2) the site has documented what actions are to be
taken, not only to resolve the recommendation, but to assure safe
operation until the deficiency can be corrected; 3) that the site
complete actions as soon as possible; and 4) that the site has
developed a written schedule describing when corrective actions
related to the resolution and any interim measures to assure safe
operations will be completed.
The system that promptly
addresses and resolves findings and recommendations referred to
in both 1910.119(e)(5) and 1910. 119(m)(5) are not
requirements to develop a management program for globally
addressing the resolution of findings and recommendations.
Rather, these "system" requirements address how each
specific finding and recommendation will be individually resolved
(Hazard Tracking requirement under VPP). Each finding or
recommendation will have its own unique resolution based on its
nature and complexity.
Has
the PHA incorporated all the previous incidents since May 26,
1992 which had a likely potential for catastrophic consequences?
VII.
Facility Siting/Human Factors.
Does
the PHA consider the siting of all occupied
structures?
Guidance:
Facility siting considerations for occupied structures include
both permanent and temporary (e.g., trailers)
structures.
Global/generic facility siting
questionnaires/checklists. Some employers (PHA teams) attempt to
comply with this 1910.119(e)(3)(v) requirement by answering
global/generic facility siting questions on a short
questionnaire/checklist. PSM is a performance standard and the
means the site uses to comply with the standard are generally up
to them as long as their performance ensures compliance with the
requirement of the standard. If the site uses a
questionnaire/checklist as part of its PHA to identify, evaluate
and control all hazards associated with facility siting, this is
permissible as long as the method they used complies with the PHA
methodology requirement, and, more importantly, all facility
siting hazards have been addressed (i.e., identified, evaluated
and controlled). This questionnaire/checklist type of methodology
would not be compliant if the site (PHA team) did not have
specific justifications for each individual situation/condition
that the global/generic questions addressed.
For
example, a PHA team responds "Yes" to a
questionnaire/checklist asking, "Is process equipment
located near unit battery limit roads sited properly?" In
this case, OSHA would first expect that the site (PHA team) would
have identified
each location
where process equipment is sited near a unit battery limit road.
Next, OSHA would expect the site would have evaluated
each
piece of process equipment located in the vicinity of a roadway.
This evaluation is conducted to determine if each
of the specific process equipment's siting is adequate/controlled
(e.g., guarded by crash barriers, elevated on a concrete
pedestal, etc.) to protect it from releasing its hazardous
contents should it be struck by vehicular traffic. Without
specific justification or other specific evidence that
corroborates the site's "Yes" response to this
global/generic questionnaire/checklist question, a possible
regulatory issue could exist for failing to address process
equipment siting near roadways when it conducted its PHA.
Guidance: Occupancy
Criteria Evaluations for Employee Occupied Structure.
OSHA does not accept occupancy criteria evaluations (see API 752,
Section 2.5.2) as the basis for a site's determination that
adequate protection has been provided for employees in occupied
structures which sites have identified as being potentially
subject to explosions, fires, ingress of toxic materials or high
energy releases. In these occupancy criteria evaluations, the
site identifies vulnerable employee occupied structures and the
hazards they may be subjected to, but rather than providing
protection to either the structures or employees through measures
like employee relocation, spacing, or protective construction,
the site simply accepts the employee exposures as adequate based
on their own acceptable occupancy criteria. This occupancy
criteria evaluation is solely based on the occupancy threshold
criteria a site is willing to accept. For instance, API 752 list
occupancy threshold criteria used by some companies as 400
personnel hours per week as acceptable exposure for employees in
an occupied structure, regardless of the magnitude of the hazard
these employees are potentially exposed to. The 400 personnel
hours per week equates to 2 employees continually exposed in an
occupied structure even if that structure has virtually no
protective construction and it is sited immediately adjacent to a
high pressure-high temperature reactor which contains flammable
or extremely toxic materials.
Non-Essential
Employees.
A site's PHA facility siting evaluation must consider the
presence of non-essential personnel in occupied structures in or
near covered processes. The "housing" of these
non-essential employees in occupied structures near operating
units may expose them to explosion, fires, toxic material, or
high energy release hazards. Therefore, unlike direct support/
essential personnel (e.g., operators, maintenance employees
working on equipment inside a unit, field supervisors, etc.) who
are needed to be located in or near operating units for
logistical and response purposes, sites (PHA teams) must consider
and justify why non-essential employees are required to be
located in occupied structures which are vulnerable to the
hazards listed above. The term "non-essential"
identifies those employees who are not needed to provide direct
support for operating processes. Non-essential employees include,
but are not limited to, administrative personnel, laboratory
employees when they are working inside a lab, maintenance staff
when they are working inside maintenance shops/areas, and
employees attending training classes.
Guidance: An
example of how a temporary structure could affect a release of
HHC would include a situation where a trailer's unclassified
electrical system could potentially ignite flammable
materials/unconfined vapor cloud if released from the process.
Do
the PHA teams identify and evaluate all situations where
operators are expected to carry out a procedure to control an
upset condition, but where the operators would not have enough
time to do so based on operating conditions?
Do
the PHA team(s) identify and evaluate all situations where field
employees must close isolation valves during emergencies, but
where doing so would expose the employees to extremely hazardous
situations? For example, to isolate a large inventory of
flammable liquids, a downstream manual isolation valve would need
to be closed, but the isolation valve is located in an area that
could be consumed by fire.
Guidance:
Some sites (PHA teams) attempt to comply with this requirement by
simply addressing some global/generic human factors questions on
a short questionnaire/checklist. This type of methodology would
not, by itself, be adequate if the PHA team did not have specific
justifications for each of its global/generic responses.
For
example, if a PHA team responds "Yes" to a
questionnaire/checklist asking whether emergency isolation valves
(EIV) are accessible during emergencies, OSHA would then expect
that the PHA team had identified,
evaluated,
and considered each
EIV's accessibility ( i.e., would the EIV be located in an area
that might be consumed in fire, or is the EIV located above
grade).
How
do the PHA teams identify likely human errors and their
consequences? Have appropriate measures been taken to reduce the
frequency and consequences of these errors?
VIII.
Operator Training.
Have
operating employees been trained on the procedures each is
expected to perform?
Guidance:
An "A" operator might be required to perform a
different set of operating procedures than a "C"
operator. Therefore, to determine if the employee has in fact
been trained on the specific operating procedures they are
expected to perform, cross-reference the specific procedures that
an individual operator is expected to perform with the training
records of the specific procedures for which the individual
operator has received training. Also determine if operators
perform tasks more than what is expected for their level of
training.
From
interviews with control board operators in the units, have these
operators received sufficient training, initial and refresher, to
be qualified to shutdown the units per the requirements of
119(f)(1)(i)(D)?
Based
on the employer's explanation of their management of operator
refresher training, verify that selected operating employees
received, completed, and understood the refresher training. For
each employee who operates a process, has the employer ensured
that the employee understands and adheres to the current
operating procedures and that the refresher training is provided
at least every three years, and more often if necessary?
IX.
Safe Work Practices.
Does
the site have a safe work practice which it implements for
motorized equipment to enter operating units and adjacent
roadways?
Guidance:
"Motorized equipment" includes, but is not limited to
automobiles, pickup trucks, fork lifts, cargo tank motor vehicles
(CTMV), aerial lifts, welder's trucks, etc.
Does
the site audit its safe work practices/procedures for opening
process equipment, vessel entry, and the control of entrance to a
facility or covered process area?
Does
the site have a safe work practice for opening process equipment,
e.g. piping and vessels, and does the site require their
employees and contractor employees to follow it?
X.
Incident Investigation Reports.
Provide
a list of actual incidents and near-miss incidents that occurred
at the site within the last year. Have all factors that
contributed to each of the incidents been reported and
investigated?
Guidance:
An "actual incident" is defined as an incident with
negative consequences such as a large HHC release, employee
injuries or fatality, or a large amount of property or equipment
damage. Typically, based on loss-control history, there is a much
higher ratio of near-miss incidents in the chemical processing
and refining industries than there are actual incidents.
XI.
Blowdown Drums and Vents Stacks (Blowdowns).
Does
the site have any blowdowns? If so, does the PSI include the
original design and design basis for each blowdown at the
site?
Guidance:
Blowdown(s) – refers to a piece of disposal equipment in a
pressure-relieving system whose construction consists of a drum
to collect liquids that are separated ("knockout") from
vapors and a vent stack, which is an elevated vertical
termination discharging vapors into the atmosphere without
combustion or conversion of the relieved fluid. Blowdown(s) are
separate vessels intended to receive episodic (e.g., when
de-inventorying a vessel for a planned shutdown) or emergency
discharges. Blowdown(s) are designed to collect liquids and to
dispose of vapors safely. In the refinery industry, hydrocarbons
typically enter blowdown(s) as liquids, vapors, or vapors
entrained with liquids. Blowdown(s) typically include quench
fluid systems which reduce the temperature of hot, condensable
hydrocarbons entering the blowdown as well as the amount of vapor
released via the vent stack. These systems can include internal
baffles to help disengage liquids from hydrocarbon vapors.
Sometimes, blowdown(s) include inert gas or steam systems to
control flashback hazards and to snuff vent stack fires if
ignited by sources such as lightning
Examples of PSI
related to blowdowns, their design and design basis include, but
are not limited to, such items as:
Physical
and chemical properties of the materials relieved to blowdowns
(See API STD 521, Section 6.2.1);
Guidance: Of
particular concern are heavier-than-air hydrocarbons with
relatively lower boiling points. Additionally, hot hydrocarbons
pose a greater risk because they are more volatile. Releasing
these materials under the right conditions can result in the
formation of unconfined vapor clouds which can and have resulted
in major catastrophes at refineries and chemical plants.
A
definition of the loadings to be handled (See API STD 521,
Section 7.1);
The
exit velocity of gasses/vapors released from the vent stack (See
API STD 521, Section 7.3.4);
Design
basis/"worst-case" scenario for maximum liquid –
vapor release to blowdown (See API STD 521, Section 4.5.j and
7.1.3);
When
more than one relief device or depressuring valve discharges to
a blowdown, the geographic locations of those devices and valves
must be defined (See API STD 521, Section 4.4.q. and 7.2.3);
The
design residence time of vapor and liquid in the drum (See API
STD 521, Section 7.3.2.1.2);
The
design basis for the vapor – liquid separation for the
drum;
The
design basis for the exit velocities for the vent stack; and
The
nature of other, lesser hazards related to smaller releases not
related to the design "worst-case" scenario such as
the release of toxic (e.g.,, H2S) and corrosive chemicals.
Since
the original installation of the blowdowns, have the original
design and design basis conditions remained the same? If not, was
an MOC conducted to determine if the blowdown design and capacity
are still adequate?
Guidance:
Examples of conditions that may have changed since the original
design and installation of the blowdowns include: increased
throughput in the unit(s) that relieve to the blowdowns;
additional relief streams routed to the blowdown, blowdowns
originally designed only to handle lighter-than-air vapor
emissions from their stacks have had liquids or other
heavier-than-air releases emitted from their vent stacks;
additional equipment, a new unit, or occupied structures have
been sited near the blowdowns in a manner that was not addressed
in the original design or design basis, etc.
Did
the PHA identify all scenarios where hot, heavier-than-air, or
liquid hydrocarbons might be discharged from blowdown stacks to
the atmosphere?
Can
the site demonstrate that atmospheric discharges from blowdowns
are to safe locations?
Guidance:
Other structures such as control rooms, trailers, offices, motor
control centers, etc., must be considered in a PHA to determine
if they have been sited in a safe location that might be affected
by a hydrocarbon or toxic material release from a blowdown.
Unsafe locations can include, but are not limited to, the
location of equipment which could act as an ignition source, such
as a furnace stack; an employee platform on a column where
employees would be exposed in the event of a release; a control
room; a satellite building; a trailer; a maintenance area/shop;
an emergency response building; an administration building; a
lunch or break room; etc.
If
there is a high-level alarm in the blowdown drum, is there an MI
procedure for calibrating, inspecting, testing and maintaining
the instrument/control?
Guidance:
The required documentation data must include the date of the
inspection or test, the name of the person who performed the
inspection or test, the serial number or other identifier of the
equipment on which the inspection or test was performed, a
description of the inspection or test performed, and the results
of the inspection or test.
Have
blowdown operators received appropriate training, either initial
or refresher?
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