A.
Transfers
Between Land Based Oil Terminal Facilities and Vessels.
(1) Personnel. For transfers at an oil
terminal facility, the facility must provide the transporter with a written
transfer procedure. This procedure must be acknowledged in writing by the
transporter. A transfer is considered to begin when the person in charge on the
transferring vessel or facility and the person in charge on the receiving
facility or vessel first meet to begin completing the declaration of
inspection.
(2) Inspections.
Inspections are required at the beginning of each transfer and as needed to
verify the tightness of the loading and offloading lines, valves, and other
attached apparatuses. Inspection logs must be retained at the facility for at
least 3 years.
(3) Tank Capacity.
Persons transferring oil shall assure that the high level alarms on the
receiving tank are set at such a level that if an alarm should occur during the
oil transfer there would be sufficient time to shutdown the oil transfer
operation prior to overfilling the tank. This alarm level must be verified to
the Department's satisfaction by a signed agreement with the local fire
suppression agency or by demonstrating that there is sufficient shutdown time
to the Department.
(4) Bonding
Cable. Pipelines on wharves must be adequately bonded and grounded if Class I
or Class II liquids are handled. If excessive stray electrical currents are
encountered, insulating joints must be installed. Bonding and grounding
connections on all piping must be located on the wharf side of the hose riser
insulating flanges. The bonding cable must incorporate a meter or other
suitable positive means of determining a ground. Typical methods for protection
against stray current hazards at wharves are illustrated in API RP
2003, Protection Against Ignitions Arising Out of Static, Lightning, and Stray
Currents. Any bonding cable employed between the wharf piping and the
vessel must employ an explosion-proof switch as a method of completing the
connection. Insulating flanges properly installed in accordance with API 2003
can be used instead of a bonding cable to isolate the vessel from the terminal
piping during product transfers across the pier.
(5) Safe Transfer Operations. Oil transfer
operations are not permitted when any of the following conditions arise:
(a) If any weather-related condition develops
that, in the opinion of the dock watchman, terminal supervisor or watch
officer, is too severe for operations to be safely continued;
(b) If a fire occurs on the dock, tank
vessel, adjacent tank vessel, or in the nearby vicinity;
(c) If a tank vessel breaks loose or if
another vessel comes alongside which is not under control or is emitting sparks
from its stack or is apt to collide or to otherwise present a hazard to the
tank vessel in berth at the terminal;
(d) If an oil spill occurs aboard the tank
vessel, an adjacent vessel, or on the dock, or if a leak develops in a joint of
hoses or piping which is not able to be stopped by tightening;
(e) If in the opinion of the dock watchman,
terminal supervisor, or watch officer a vapor condition develops aboard or
around the tank vessel or dock which would be too serious to safely continue
operations;
(f) If any other
emergency occurs which, in the opinion of the dock watchman, terminal
supervisor, or watch officer constitutes a potential hazard to the tank vessel
or facilities; or
(g) If at any
time the high level alarm system within the terminal activates to warn of a
possible or pending overflow.
(6) Illumination. A person may not transfer
or cause to be transferred or consent to the transfer of any bulk oil after
dark unless the point of transfer is illuminated to a minimum standard of 50
lux.
(7) Open Hatch Transfer.
Transfer of oil by means of a hose through an open hatch is prohibited. An
exception may be made only when an emergency arises and this is the only means
available to move oil from one vessel compartment to another or to unload oil
from a vessel for purposes of reducing or preventing pollution, or for
preventing foundering. Such emergency exceptions are allowed only when all
possible precautions to prevent discharge to the waters of the State have been
taken. The owner or operator shall notify the Commissioner or the
Commissioner's designee and the local fire suppression agency prior to
commencing such emergency transfer operations.
(8) Sample Collection. A terminal operator
may not transfer or cause to be transferred or consent to the transfer of any
bulk oil until a sample of the oil to be transferred has been collected,
identified by proper labeling, and stored in a place acceptable to the
Department. Oil terminal facilities with automatic sampling capabilities are
not required to presample. The sample must be stored for a minimum of fifteen
days. The Department shall determine the information to be provided with each
sample and may require chemical analysis of the sample. Sampling must be done
in accordance with Appendix B. Samples must be stored at the facility or at the
lab where the samples are analyzed in accordance with chain-of-custody
protocols.
(9) Anticipated
Transfer. The terminal owner or operator shall notify the Supervisor of the
appropriate Department Regional Office of the Division of Response Services, at
least 12 hours in advance of any transfer of bulk oil. The notification must
include the following information:
(a)
Terminal name and location, or anchorage if the transfer will be
offshore;
(b) Approximate amount of
oil to be transferred;
(c) Oil
type;
(d) Vessel name(s);
and
(e) Expected time and date of
vessel arrival(s).
Should unusual circumstances make it impossible to provide
12-hour notice, the terminal operator shall notify the Commissioner as soon as
possible. Notification is not required for bunkering.
(10) Declaration of Inspection. A
copy of any "Declaration of Inspection" required by the United States Coast
Guard for a tank vessel transferring oil at an oil terminal facility must be in
the possession of the terminal operator or the operator's representative and
must be available to the representative of the Commissioner who shall, on
demand, be given the opportunity to verify that the condition of the vessel is
as stated in the "Declaration of Inspection."
(11) Other Reports and Forms. The oil
terminal facility operator shall also complete and submit such other forms,
checklists, and reports as the Commissioner may require.
(12) General Safety Provisions.
(a) Signs. During the time a tank vessel is
in berth, a warning sign carrying letters not less than 2 inches high on a
contrasting background must be displayed on the dock and near the gangplank.
This sign must read substantially as follows: WARNING-NO OPEN LIGHTS, NO
SMOKING, NO UNAUTHORIZED VISITORS.
(b) Hazardous Vapor. When in the opinion of
the terminal operator or the Commissioner's representative a hazardous vapor
condition develops on a dock or on any vessel, all transfer operations
involving such vessels must be stopped and all sources of ignition such as
smoking, use of matches, lighters and open flame except boiler fires must be
eliminated and prohibited.
(c)
Transfer of Sour Crude. An oil terminal facility must take special precautions
for the transfer of sour crude oil to minimize the release of vapors during the
transfer period.
(d) Multiple
Vessel Mooring. A tank vessel may not be secured alongside another tank vessel
at a pier except while taking bunker fuel aboard. A tow boat must stand by
alongside or in the notch during the transfer of bunker fuel from a bunker
vessel to a tank vessel. The bunkering vessel must be moved away from the tank
vessel immediately after completion of the loading process.
(13) Vessel Pre-Transfer
Conference. A person may not commence or consent to the commencement of bulk
oil transfer operations at an oil terminal facility unless the following items
have been reviewed, agreed upon and complied with by both vessel and facility
personnel:
(a) A sufficient number of
adequately trained oil terminal facility personnel are assigned to be
constantly on duty during cargo transfer operations to keep the transfer
operation under constant observation and to ensure immediate action in case of
a malfunction;
(b) Cargo sequence
for loading or discharging products and the proper pipe for each product must
be established;
(c) The handling
rate at which oil will be transferred must be established. Reduced rates are
required when commencing transfer, changing the lineup, topping off tanks or
nearing completion of transfer. The amount of time to be given when the vessel
or terminal desires to start, or stop, or change the rate of flow must be
determined;
(d) A positive
communication and signal system must be operable during transfer
operations;
(e) The emergency
procedures to be followed in order to stop and contain any discharge must be
established;
(f) Vessel and
facility personnel responsible for transfer shall always be clearly
identifiable. Prior to transfer operations, terminal and vessel personnel
responsible for transfer shall be made known to each other; and
(g) The oil terminal facility must have
written operation guidelines pertaining to dock operations for vessels coming
to or alongside its dock during abnormal weather conditions.
(14) Transfer Hoses. A person may
not transfer or cause to be transferred or consent to the transfer of any oil
between an oil carrying vessel and an oil terminal facility unless the
following conditions are met:
(a) All oil
terminal facility transfer hoses must be of a type designed specifically for
the oil transferred. Transfer hoses must be tested annually to 1.5 times the
maximum working pressure
(i) For pipe that
can be visually examined, the test pressure must be maintained for a minimum of
10 minutes and held for such additional time as may be necessary to conduct the
examination for leakage, or
(ii)
For pipe that is buried or insulated and cannot be visually inspected, the
pressure must be maintained for one hour.
(b) As provided for below, each oil terminal
facility hose must be marked with:
(i) The
products for which the hose is to be used for or the words "oil
service";
(ii) Maximum allowable
working pressure;
(iii) Date of
manufacture; and
(iv) Date of the
most recent test performed.
The information described in subparagraphs (i-iv) above need
not be marked on the hose if it is recorded elsewhere in the hose records at
the facility and the hose is marked to identify it with the location of that
information. The logbook or records must be available for inspection on demand
by a representative of the Commissioner.
(c) Hoses must be supported to avoid crushing
or excessive strain. Flanges, joints, and hoses must be checked visually for
cracks and wet spots before each use.
(d) Oil terminal facility hose handling rigs
must allow adjustment for vessel movement and hoses must be long enough so that
they are not strained by any movement of the vessel.
(e) Hose ends must be blanked tightly when
hoses are moved into position to be connected and immediately after they are
disconnected, and must be drained either into the vessel tanks or into suitable
shore receptacles before they are moved away from their connections.
(f) Hoses may not be permitted to chafe on
the dock or vessel or be in contact with hot surfaces such as steam pipes.
Hoses may not be exposed to any sources of corrosion.
(g) Hoses no longer in service must be
removed from the transfer area.
(15) Mooring Lines. Mooring lines must be
tended during transfer operations to prevent excessive movement of the
vessel.
(16) Fire Main Connections.
Serviceable fire hose sufficient to reach all parts of the vessel and dock with
approved combination nozzles attached must be connected to the fire main on the
vessel and/or on the dock and be ready for instant use during the time a vessel
is in berth. The fire main must have a master valve at the head of the dock so
the fire main can be kept dry in cold weather and wet in warm weather. The fire
main on the dock must be at least 6 inches in diameter. The fire main must
always be charged to the master valve. The owner or operator of an oil terminal
facility not meeting these requirements shall file an alternate fire protection
plan with the Department. The alternate plan must be approved by the State Fire
Marshal's Office or local fire suppression agency.
(17) Fire Wires. During transfer operations,
fore and aft fire wires must be rigged on the offshore side of the vessel for
use by tugs in removing the vessels from the pier in event of fire.
(18) Vessel to Shore Transfer. A person may
not transfer or cause to be transferred or consent to the transfer of any bulk
oil from any tank vessel to a land based oil terminal facility unless:
(a) All cargo risers not intended for use in
the transfer are blanked;
(b) Sea
valves connected to the cargo piping and stern loading connections are tightly
closed and sealed with a numbered seal which is logged in the logbook of the
vessel;
(c) Piping and valves in
the pump rooms and on deck are checked by the master of the vessel, senior deck
officer or deck officer on duty, or licensed tanker man to see that they are
properly set for discharging cargo. An additional check must be made for the
same purposes each time the setting is changed;
(d) Full rate of transfer is not attained
until shore lines are proven clear; and
(e) On completion of transfer operations,
hoses or other connecting devices are drained of the remaining oil. A drip pan
must be in place when breaking a connection and the end of the hose or other
connecting devices must be blanked off before being moved.
(19) Shore to Vessel Transfer. A person may
not transfer or cause to be transferred or consent to the transfer of any bulk
oil from a land based oil terminal facility to any tank vessel unless:
(a) All sea valves connected to the cargo
piping, stern discharge and ballast discharge valves are closed and sealed with
a numbered seal which is logged in the logbook of the vessel and with the
responsible vessel officer of the vessel;
(b) All hose riser valves not to be used in
the transfer are closed and blank flanged, and all air valves on headers are
closed;
(c) During the topping off
process, special attention is paid to the loading rate, the number of tanks
open, the danger of air pockets and the inspection of tanks already loading.
Shore personnel must be given notice of the slowdown for topping off;
and
(d) Upon completion of loading,
all tank valves and loading valves are closed. After draining, hoses must be
disconnected and hose risers blanked.
(20) Scuppers. A person may not transfer or
cause to be transferred or consent to the transfer of any bulk oil between a
tank vessel and a land based oil terminal facility unless the scuppers of the
vessel are plugged watertight during the oil transfer operation, except on tank
vessels using water for deck cooling. However, it is permissible to remove
scupper plugs as necessary to allow run-off of water provided a vessel crew
member stands watch to re-close the scuppers in case of an oil
discharge.
(21) Tank Tops and Hatch
Covers. When transferring oil, tank tops and hatch covers must be closed.
Ullage caps or plugs may only be opened on tanks that are to be loaded or
unloaded and all open ullage holes must be covered with flame screens which
must be kept in place during the transfer except for the minimum time necessary
to observe transfer progress, take samples or take ullage readings. If a tow
boat or other vessel such as a bunker barge or lighter is moved alongside for
the purpose of serving the vessel, and if that tow boat or other vessel is
steam propelled or propelled by an internal combustion engine, tank tops, tank
hatches and ullage plugs or caps must be kept open only on those tanks from
which oil is being withdrawn. Any such open ullage plugs or caps must have
flame screens in place. When there is no longer any possibility of sparks or
other source of ignition, normal procedure may be resumed.
(22) Ports and Doors to Crew Quarters. When
loading and unloading oil, all ports and doors facing the cargo decks or facing
a breeze bringing vapors from another vessel must be closed except to allow for
passage of personnel.
(23) Blowing
of Boiler Tubes. During transfer operations, blowing of boiler tubes or other
work on the boilers which could cause the emissions of sparks or soot from the
stacks is prohibited.
(24) Spillage
During Transfer. Transfer operations must cease if a discharge of oil to the
waters of the State occurs during such transfer. Operations may resume when, in
the judgment of the Commissioner's representative adequate steps have been
taken to control the discharge and to prevent further discharge. In making this
judgement, the Commissioner's representative may consult with the United States
Coast Guard or Local Fire Chief, if necessary.
(25) Contingency Plan. Each owner or operator
of an oil terminal facility shall have available for inspection by the
Commissioner or a representative of the Commissioner, a copy of any oil
discharge response plan required to be submitted to the President of the United
States under the federal OPA 90.
(26) Operations Plans. The owner or operator
of each oil terminal facility shall have an operations plan available for
inspection upon request of the Commissioner or representative of the
Commissioner. The operations plan must describe in detail the equipment and
procedures used at that terminal for the prevention of oil spills and the
protection of the public health, safety, welfare, and environment.
(27) Spill Prevention Control and
Countermeasure (SPCC) Plan. The owner or operator of an oil terminal facility
shall comply with all the requirements of the Spill Prevention Control and
Countermeasures Plan in Oil Pollution Prevention, 40 C.F.R.
pt. 112, incorporated by reference herein.
(28) Inventory Records and Fees. Records of
all monthly fees paid to the Maine Ground and Surface Waters Clean-up and
Response Fund for all applicable product transfers, annual reports on
transfers, and third party observer records must be available for inspection
upon the request of the Commissioner or a representative of the Commissioner.
All inventory records must be retained for a minimum of 10 years. Fees on
transfers must be paid monthly and accompanied by the applicable Department
form. If no transfers are received during a month, the form must be filed with
the Department stating that no transfers occurred. In the case of an
enforcement action, the record retention timeframe is automatically extended
until the action is resolved.
B.
Booming of Vessels
(1) All tank vessels and tank barges, engaged
in transfer operations, must be protected by an oil boom device to catch and
contain oil discharges. The boom must completely surround the vessel at a
minimum distance of 50 feet from the vessel and be secured in place by
sufficient anchors, except:
(a) When engaged
in the actual vessel to vessel bunkering operations while at
anchorage;
(b) When personnel
safety conditions, weather, wind, sea, or ice conditions are such that a boom
is not able to be wholly or partially deployed, and the terminal operator
reports this fact to the Commissioner. Reporting must be prior to transfer,
whenever conditions develop which require removal of the boom, or when
conditions are such that only a partial boom is appropriate to deploy. If the
Commissioner's offices are closed, reporting must be on the next working day
following the transfer; or
(c) When
a portion of the oil has a flash point of -45symbol 176 \f "Symbol" F or less,
and an ignition temperature of 536symbol 176 \f "Symbol" For more, such as
gasoline.
(2) The boom
used to enclose the tank vessel must be of a type suited to the conditions of
wind, currents, and waves found at the transfer site at the time the transfer
takes place, and must be capable of retaining the maximum most probable
discharge from the tank vessel under the conditions normally found at the
transfer site at the time the transfer takes place unless subparagraph (1)(b)
applies. Maximum most probable discharge means a discharge of:
(1) 2,500 barrels of oil for a vessel with an
oil cargo capacity equal to or greater than 25,000 barrels; or
(2) 10% of the vessel's oil cargo capacity
for vessel with a capacity of less than 25,000 barrels.
(3) If a terminal operator believes it is
impossible or wholly impracticable to implement the booming requirement in
whole or in part on a regular basis, the operator may apply to the Department
for complete or partial exemption from this requirement. The marine oil
terminal application must set forth in detail the reasons why such complete or
partial exemption should be granted. The Department may set any reasonable
conditions in granting any such exemption.
C.
Land Based Oil Terminal
Facilities.
(1) Inventory
Control/Overfill Protection.
(a) Inventory
Reconciliation. The liquid level in a tank must be gauged at least once every 7
days and the measurements compared to previous readings. A record of the
measurements must be maintained for inspection by the Commissioner or
representative of the Commissioner. Tank gauging also is required prior to any
delivery of oil into a storage tank at a facility.
(b) Mandatory Loss Reporting. Any liquid
level measurements that, after reconciliation of inventory, indicate a loss of
liquid of at least 0.5% of throughput on a monthly basis, must be immediately
investigated. This investigation must include determining if a loss of material
has occurred, the estimate of how much material is unaccounted for, the reason
for the loss, and what happened to the material. The potential loss of material
in excess of 0.5% must be reported to the Commissioner:
(i) Within 24 hours of discovery of the
potential loss, if the investigation is not concluded, or
(ii) Within 2 hours of discovering that the
loss was a result of a spill or leak.
All investigations for potential loss of material in excess
of 0.5% must be kept on file for review by the Department.
(c) Overfill Prevention. Tank
overfilling must be prevented by the following measures:
(i) High liquid level alarm with audible and
visual signals; and
(ii) High-high
liquid level alarm with audible and visual signals.
(d) Overfill protection systems must be
tested before each transfer or monthly, whichever is the least
frequent.
(2)
Maintenance and Inspection. Prior to operation and as a condition of continued
operation of an oil terminal facility, a maintenance and inspection program
must be implemented by the facility operator as follows:
(a) Daily visual inspection of aboveground
tanks, piping, equipment and discharge control devices and surrounding areas to
detect possible oil discharges and to determine and carry out any maintenance
necessary to prevent discharges from occurring. The operator shall make a list
of daily inspection procedures and inspection logs available upon request of
the Commissioner or representative of the Commissioner.
(b) A documented monthly visual inspection of
the facility, including but not limited to, tanks and all ancillary devices
(vents, water drawoff, etc.), valves, piping, spill containment dikes and other
spill holding areas, oil/water separators and equipment.
(c) Monthly visual tank inspection,
including, but not limited to the following:
(i) Inspection of exterior surfaces of tanks
for discharges and maintenance deficiencies;
(ii) Identification of cracks, wear,
corrosion, thinning, poor maintenance and operating practices, settlement,
swelling of tank insulation, malfunctioning equipment, structural or foundation
weaknesses; and
(iii) Inspection
and monitoring of discharge detection systems, or warning systems.
(d) Tank De-watering. An
appropriate schedule for removal of water from tanks must be included in the
maintenance and inspection program. Maintenance to remove water from tanks must
be appropriately handled. Discharge of water from tank bottoms must be to an
appropriate treatment facility. Oil removed from the tank as part of the water
bottom drawoff maybe returned to the tank.
(e) Cathodic Protection System. A monthly
inspection must be performed on any impressed current cathodic protection
system. Monthly voltage and current readings must be in the range to provide
adequate cathodic protection levels per NACE SP0169 for underground piping or
NACE SP0193 for above ground storage tanks. An annual structure to soil and
structure to structure potential test must be performed by a cathodic
protection tester for impressed current systems as well as annual structure to
soil potentials for galvanic systems. All readings and repairs must be
documented and made available at the time of the inspection and submitted to
the Department at the request of the Commissioner or the Commissioner's
representative.
(f) Underground
Piping. All underground oil piping must be inspected or tested to verify the
integrity of the piping in accordance with API Standard 570, Piping
Inspection Code: In-Service Inspection, Rating, Repairs and Alternation of
Piping Systems. Verification by pressure testing must consist of
holding pressure at 1.5 times the maximum operating pressure for a period of
one hour on an annual basis. Verification by use of internal inspection devices
designed to verify the structural integrity of the pipe by measuring pipe wall
thickness and indicating geometric irregularities of the piping is an
acceptable alternative. Verification by the use of internal inspection devices
must be performed no more than 5 years from the most recent internal inspection
and every 5 years thereafter. Pressure testing or internal inspection is not
required on underground piping equipped with secondary containment or a leak
detection system. The Commissioner may also require testing if there is reason
to suspect a discharge.
(g)
Aboveground Piping Tightness Testing. Tightness testing is required for
aboveground piping no more than 10 years after installation and every 5 years
thereafter in accordance with API 570. Aboveground piping must
be hydrostatically pressure tested to 1.5 times the maximum operating pressure
for a period of one hour. For the purpose of this paragraph a hydrostatic
pressure test may be performed using hydrocarbon product or water. Verification
by use of internal inspection devices, designed to verify the structural
integrity of the pipe by measuring pipe wall thickness and indicating geometric
irregularities of the piping, is an acceptable alternative. Verification by
internal inspection devices must be performed no more than 5 years after the
most recent internal test and every 5 years thereafter. If the piping,
including insulated piping, can be visually inspected 360 degrees around over
its entire length, then tightness testing is not required.
(h) Internal Tank Inspection. All field
constructed tanks must be internally inspected as follows:
(i) Tanks with an RPB that have no internal
tank bottom liner, no cathodically protected bottom, and that do not contain #
6 fuel oil or asphalt must be internally inspected no more than 10 years after
a prior internal inspection, and every 10 years thereafter;
(ii) Tanks with an RPB, an internal tank
bottom liner, a cathodically protected bottom, and that do not contain # 6 fuel
oil or asphalt must be internally inspected no more than 20 years after a prior
internal inspection, and every 20 years thereafter;
(iii) Tanks containing #6 fuel with or
without a cathodically protected bottom must be internally inspected no more
than 20 years after a prior internal inspection, and every 20 years
thereafter;
(iv) Tanks containing
asphalt with or without a cathodically protected bottom must be externally and
internally inspected no more than 20 years after a prior external/internal
inspection, and every 20 years thereafter.
(i) Internal inspections must be in
accordance with API 653. If, during an inspection, evidence is
found of a change from the original physical condition of the tank, then the
suitability of the tank for continued service must be evaluated in accordance
with API 653. Internal inspections and suitability for service
evaluations must be conducted by an API 653 certified
inspector. Inspection records must be retained for review by the Commissioner
or representative of the Commissioner. Any hole or failure of a tank or piping
must be reported to the Department.
(j) For the purpose of this Chapter, the
following inspection requirements must meet the intent of API 653, Section
6.5,
Alternative to Internal
Inspection to Determine Bottom Thickness for Asphalt Tanks.
(i) Inspections for indications of asphalt
seepage and foundation stability, such as erosion or fill migration or
settlement, must be performed around the exterior perimeter of the tank where
the tank floor is flush with the ring wall foundation or pad foundation. For
the purposes of this Section, the pad foundation refers to earth or
concrete.
(ii) The area around the
external shell to floor joint must be inspected for indications of seepage or
cracked weld seams.
(iii) If the
tank wall or floor is of riveted construction, rivets must be inspected for
indications of seepage or corrosion which could indicate a rivet losing
strength. Insulation must be temporarily removed to allow inspection of rivets
at 10 to 16 locations. If the inspection reveals a significant number of
leaking rivets, a weep for walls and 25% of the 10 to 16 locations for a floor,
then an expanded detailed inspection plan must be prepared and submitted to the
Department for approval. Subsequent inspections must consist of inspection
locations in areas not previously inspected.
Repair of leaking rivets may be made using the best
acceptable industry practices in use at that time. Thermal expansion and
contraction of the shell, rivet and hole must be accounted for in determining
the proper repair procedure.
(iv) The tank perimeter must be inspected for
indications of tank settling such as floor or shell deformations. If the
exterior of the tank is insulated, inspections for shell deformation must be
conducted from the interior of the tank. The exterior floor elevations must be
checked at 8 evenly spaced locations around the perimeter of the tank using a
level. Records of the elevations must be maintained for comparison with
measurements taken during subsequent inspections to detect any long-term
settling.
(v) Floor thickness must
be measured at 6 to 8 locations distributed throughout the interior bottom. At
least one of these points must be within 6 inches of the shell. Asphalt at
these points must be removed to expose bare metal. If there is any evidence of
external or internal corrosion of the tank shell or floor, the floor thickness
must be measured at the suspected point of minimal floor thickness. The minimum
floor thickness observed must be used to compare with acceptable minimum
thicknesses. If corrosion is present, allowances must be made for future metal
loss in determining whether to replace the tank bottom or schedule for the next
inspection.
(vi) In the event that
inspection of the tank reveals weld cracks, leaking rivets or other indications
of joint failure, the entire floor must be cleaned and inspected, or replaced
with a new floor in accordance with API 653.
(vii) The inspection of the balance of the
tank and any repairs or modifications must be in accordance with API 650 and
653.
(3)
Steam or Heating Devices. A person may not discharge exhaust steam containing
oil from any coil or other device used to heat oil either directly or
indirectly onto lands adjacent to or into any surface or ground waters of the
State.
(4) Records. Owners or
operators shall maintain records documenting required training, inspections,
tests, maintenance and repairs. Unless otherwise specified, such records must
be kept on file at the facility for a minimum of three years and must be
available for inspection upon the request of the Commissioner or representative
of the Commissioner. In cases involving enforcement action, the three-year
period for maintaining such records is automatically extended until the action
is resolved.
(5) Financial
Responsibility Requirements.
(a) Financial
Assurance for Closure and Remediation Costs. The Commissioner requires evidence
of financial assurance in the amount of at least $2 million per facility as a
condition of an operating license to ensure proper closure and remediation of
facilities. This evidence must accompany any new, renewal or transfer
application for a marine oil terminal license. Financial assurance can be
established, subject to the approval of the Commissioner, by any combination,
of the following: insurance and risk retention group coverage, guarantee,
surety bond, letter of credit or trust fund. In determining the adequacy of
evidence of financial assurance, the Commissioner shall consider the financial
mechanisms in 40 C.F.R.,
§§
280.96 through
280.99 and
280.102 through
280.103 except the term
"underground tank" or "UST" must be replaced with or include the addition of,
"aboveground tank" or "AST", as applicable. Any bond filed must be issued by a
bonding company authorized to do business in the United States. Any guarantee
must specify the relationship of the entity providing the guarantee to the
licensee and applicant.
Financial instruments must also be updated when estimated
costs for closure and remediation of the facility change, at license renewal,
or prior to expiration dates or non-renewal of the financial instruments, and
in the case of guarantee on an annual basis.
The Commissioner may require a change in the amount of
financial assurance required if after a review of a preliminary closure plan
and engineering assessment of probable closure and remediation costs the review
indicates a change in the requirement would be appropriate.
(b) Preliminary Closure Plan. A preliminary
closure plan must accompany the financial assurance instrument and must detail
the approach for completing closure in accordance with Section (12)(D) of this
Chapter. The plan must include an engineering assessment of probable closure
costs completed in support of this Section, and that must include a detailed
cost analysis of all closure and remediation actions. The engineering
assessment must include:
(i) For any
underground piping proposed to remain in place, a feasibility assessment for
removal of underground piping in accordance with Section (12)(D)(2) of this
Chapter, including the supporting rationale;
(ii) The removal of all underground piping
not covered by (i) above;
(iii) The
removal of all tanks and aboveground piping;
(iv) The cost for removal of all ancillary
equipment such as oil water separators, transformers, additive tanks, and
containment structures;
(v) The
cost of an investigation into contamination from spills, releases and disposal
activities that have occurred on the site;
(vi) The cost of removal of contamination and
cleanup of the site for expected areas of contamination and where a discharge
has occurred, such that the facility site is suitable for the most protective
use level (generally residential use, although occasionally a different use has
more protective levels). Where contamination is likely to discharge to surface
water or ground water, the cost to clean up to applicable cleanup standards
protective of surface water and ground water; and
Note: For purposes of demonstrating adequate funding in a
financial assurance mechanism to fully complete closure, the preliminary
closure plan and associated cost estimate is intended to be a conservative view
of what actions will be necessary to complete closure. The assumptions used in
arriving at the cost estimate associated with the preliminary closure plan may
vary from the actual site conditions at the time of the final implementable
closure plan. A preliminary closure plan is a future looking plan. The closure
plan in Section (12)(D) of this Chapter is a plan that would be implemented at
closure with consideration of actual site conditions at the time of
closure.
(vii) A contingency
amount of 25%.
The engineering assessment may not consider the salvage value
for scrap metal, used equipment, additives or other wastes including waste
oils. The engineering assessment must include costs for the required work to be
performed by a third party.
Note: Consult Standards for Owners and Operators of
Hazardous Waste Treatment, Storage, and Disposal Facilities,
40 C.F.R. §
264.142, Cost Estimate for Closure for
assistance in conducting a cost estimate. Other documents that provide helpful
information are RCRA, Superfund & EPCRA Call Center Training Module
(Introduction to RCRA Financial Assurance), Items to Submit for RCRA Closure
Cost Estimate, and Transmittal of Interim Guidance on Facilities Subject to
RCRA Corrective Action. Each of these documents includes information on cost
estimating, the types of financial instruments and other general financial
guidance.
(c) Liability Insurance Requirements. Owners
or operators shall maintain a minimum of $1,000,000 per occurrence and
$2,000,000 annual aggregate in liability insurance exclusive of legal defense
costs, for third parties to address damage to their property or personal
injury. The Commissioner may require at their sole discretion, if deemed
appropriate, an increase in the amount of liability insurance when taking into
consideration such factors as the size and location of the facility and the
proximity of neighbors and sensitive resources to the facility. Insurance
policies must provide full coverage of the facility without exclusions or
limitations including exclusions for self insured retention for a portion of
the policy and loading or offloading exclusions. Documentation of liability
insurance must be submitted with the license application, when the policy
changes, and upon request of the Department. Documentation must include a
certificate of insurance and the signed insurance policy in effect.