SPPE Form

OMB Control Number: 2138-0046

Burden Statement
A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a
person be subject to a penalty for failure to comply with a collection of information subject to the
requirements of the Paperwork Reduction Act unless that collection of information displays a current
valid OMB Control Number. The OMB Control Number for this information collection is 2138-0046 (Exp.
Date 03/31/2017). Reporting of an Equipment Failure is estimated to take approximately 30 minutes,
including the time for reviewing instructions, completing and reviewing the report. Send comments
regarding this burden estimate or any other aspect of this collection of information, including
suggestions for reducing this burden to: SafeOCS Data Collection Office, Demetra Collia, US DOT/ BTS,
1200 New Jersey Avenue SE, Room E36-302, Washington, D.C. 20590 or e-mail: [email protected]
Pledge of Confidentiality
The information you provide will be used for statistical purposes only. In accordance with the BTS
confidentiality statute (49 U.S.C. 6307) and the Confidential Information Protection provisions of Title V,
Subtitle A, Public Law 107-347, your responses will be kept confidential and will not be disclosed in
identifiable form to anyone other than BTS employees or BTS agents such as telephone interviewers. In
accordance with these confidentiality statutes, only statistical and non-identifying data will be made
publicly available through aggregate reports. By law, every BTS employee and BTS agent has taken an
oath of confidentiality and is subject to a jail term of up to 5 years, a fine of up to $250,000, or both if he
or she discloses ANY identifiable information about the respondent or reporting company or operator.
BTS will not release to the Bureau of Safety and Environmental Enforcement, Department of Interior, or
any other public or private entity any information that might reveal the identity of individuals or
company/operator names mentioned in near-miss reports.

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SPPE (Safety and Pollution Prevention Equipment) Failure Notification Form
(Please submit the information listed below)
_____________________________________________________________________________________
I. Operator Data
Date of Failure _______________________
Operator Company Name ______________________
(Operators will select their BSEE operator number from a drop down list that BSEE will provide)
Complex ID / Structure Number __________/__________
(Operators will select their Complex ID and Structure Number from a drop down list that BSEE will
provide)
API Well Number, if applicable ___________________
Company Name Submitting Form, if different than the Operator ____________________________
Type of Company Submitting Form (select one)
□ Production Contractor
□ Other, Specify __________________________
_____________________________________________________________________________________
II. SPPE Details
Equipment manufacturer _____________________
Model ___________________
Serial Number ______________________
Working pressure ___________________
Nominal size _______________________
Provide a narrative describing any redress history for the SPPE that failed:

Please provide the date and a narrative description of the last SPPE test.
Date _________________
Narrative:

____________________________________________________________________________________
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III. What was the Certification Status of the Failed SPPE (select one)
□ Newly Installed; certified SPPE pursuant to ANSI/API Spec Q1
□ Newly Installed; certified SPPE pursuant to Another Quality Assurance Program
□ Previously certified under ANSI/ASME SPPE-1
□ Non-Certified SPPE
_____________________________________________________________________________________
IV. Was the SPPE previously repaired, remanufactured or subject to hot work offsite? □ Yes □ No
_____________________________________________________________________________________
V. What type of tree was associated with the SPPE that failed? (select one)
□ Dry Tree
□ Subsea Tree
_____________________________________________________________________________________
VI. Which SPPE component failed? (select all that apply)
□ Valve Body
□ Actuator
□ Flow coupling (required for surface- or subsurface-controlled SSSV)
□ Safety Lock
□ Landing Nipple
□ Direct hydraulic control system
□ Electro-hydraulic control umbilical
□ Flange
□ Ring joints
□ Ball
□ Flapper
□Temperature Safety Element (TSE)
□ Emergency Shutdown (ESD) System
_____________________________________________________________________________________
VII. SPPE Type
What was the type of SPPE that failed? (select one)
□ Surface Safety Valve (SSV)
□ Boarding Shutdown Valve (BSDV)
□ Underwater Safety Valve (USV)
□ Surface controlled SCSSV
□ Subsurface controlled SSCSV
_____________________________________________________________________________________
VIII. SSSV Details
What was the type of SSSV that failed? (select one)
□ Tubing retrievable
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□ Wireline retrievable
□ Through flowline (TFL)
□ SCSSV retrievable
□ SSCSV retrievable
Was the SSSV formerly a pump through type tubing plug? □ Yes □ No
If the SSSV that failed was Subsurface Controlled (SSCSV), what type was it? (select one)
□ Velocity-type SSCSV
□ Tubing-pressure-type SSCSV
What was the service class of the SSSV that failed? (select one)
□ Class 1 only standard service
□ Class 2 sandy service
□ Class 1 and 2
□ Class 3 stress cracking
□ Class 3s (sulfide stress and chlorides in a sour environment)
□ Class 3c (sulfide stress and chlorides in a non-sour environment)
□ Class 4 mass loss corrosion service
_____________________________________________________________________________________
X. BDSVs, SSVs, and USVs
What was the service class of the BDSV/SSV/USV? (select one)
Class I: performance level requirement intended for use on wells that do not exhibit the
detrimental effects of sand erosion.
Class II: performance requirement level intended of use if a substance such as sand could be
expected to cause an SSV/USV valve failure
If the SPPE that failed was a BSDV, which type was it? (select one)
□ Automatic
□ Manual BSDV
___________________________________________________________________________________
X. SPPE Design Criteria
Was the SPPE designed for High Pressure High Temperature (HPHT) conditions? □ Yes □ No
Was the SPPE designed for Arctic Conditions? □ Yes □ No
Please specify the most extreme exposure conditions for which the SPPE was designed to function?
Design Pressure _________ psi
Design Temperature ________ degrees F
Design Flow Rate _________ (number)
Flow rate units _____ per _______
Other Design Environmental Conditions _________________________________________
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__________________________________________________________________________
__________________________________________________________________________
_____________________________________________________________________________
XI. Well data (Provide the information below, as applicable)
What was the type of well associated with the SPPE failure? (select one)
□ Production
□ Injection Well
Was the well shut in at the time of failure? □ Yes □ No
What was the last Well Test Rate? ___________________ BOE/day
What was the date of the last Well Test? _________________
What were the Environmental Conditions (check all that apply)
□ Sand, Specify percentage _____%
□ H2S
□ CO2
□ Other, Specify _________________________________________________________
Pressures and temperatures
Surface ___________ psi / ___________ degrees F
Bottom hole ____________psi / __________degrees F
_____________________________________________________________________________________
XII. Under what conditions was the SPPE activated at the time of the failure (check all that apply)
□ Activated during normal well operations
□ Activated in response to an ESD
□ Activated during emergency weather or other emergency conditions
Specify the nature of the emergency: _____________________________________________
□ Activated during a process upset
□ Activated in response to the detection of a high or a low pressure condition by a PSHL sensor
located upstream of the BSDV
□ Activated when the gas lift system introduced gas into the system
□ Activated during a leakage test
_____________________________________________________________________________________
XIII. Description of the failure
Provide a narrative description of the failure to include, but not limited to:
● as much information as possible on the operating conditions that existed at the time of the
malfunction or failure
● an accurate a description as possible of the malfunction or failure

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● any operating history of the SPPE leading up to the malfunction or failure (e.g. field repair,
modifications made to the SPPE, etc.)

_____________________________________________________________________________________
XIV.
Specify how many cycles or hours were completed since the last preventative maintenance.
(If the SPPE was newly installed, specify how many cycles or hours were completed since the SPPE
was installed).
_______________number of cycles or ______________ number of hours
_____________________________________________________________________________________
XV.Provide a narrative describing the general configuration of the SPPE and hydrocarbon flow path.

_____________________________________________________________________________________
XVI. What factors contributed to the failure? (select all that apply)
□ Improper Design
□ SPPE erroneously thought to be certified but was not
□ Inadequate requalification/verification testing
□ Installation was incompatible with specific design elements like subsea trees and related
equipment, tubing hangers, etc.
□ Improper Use
□ Operating conditions out of range of device
□ Mechanical failure – leak
□ Mechanical failure -- sand cut erosion
□ Mechanical failure – Corrosion (chemical - H2S orCO2)
□ Mechanical failure -- Corrosion (atmosphere)
□ Valve seat degradation
□ Failed to open
□ Failed to close
□ Failed to contain hydrocarbons
□ Failure to meet required closure timing (consider both isolation and bleed time when deciding)
□ Electrical power failure
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□ Hydraulic power failure
□ Incorrect assembly
□ Valve damaged during assembly/disassembly
□ Improper maintenance
□ Improper repair
□ Shipping damage
□ Damage related to lifting or material handling
□ Storm damage
□ Collision damage
□ Damage related to a seismic event
□ Applied hydraulic pressure through wellhead seal assembly required to maintain surfacecontrolled SSSV in the open position exceeds MRWP of the wellhead by more than a minimum
required amount
□ Other, Specify _______________________________________________________________
_____________________________________________________________________________________
XVII.Preliminary Root Cause (select all that apply)
□ Human Error, Personnel Skills or Knowledge
□ Human Error, Quality of Task Planning and Preparation
□ Human Error, individual or group decision-making
□ Human Error, quality of task execution
□ Human Error, quality of hazard mitigation
□ Human Error, communication
□ Maintenance plan and procedure
□ Manufacturing defect
□ Design issue
□ Wear and tear
□ Other, Specify _________________________________________________________________
_____________________________________________________________________________________
XVIII.Is a formal Root Cause and Failure Analysis recommended? □ Yes □ No
_____________________________________________________________________________________
XIX.Corrective Action
What corrective action was taken related to the SPPE failure? (select all that apply)
□ Adjust
□ Check
□ Inspection
□ Modify
□ Overhaul
□ Refit
□ Remanufacturer
□ Repair
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□ Replace
□ Service
□ Test
□ Other, Specify _______________________________________________________________
Where was the corrective action accomplished? (select one)
□ Contractor’s facility
□ Manufacturer’s facility
□ On location
□ Operator’s facility
If the corrective action was accomplished on location, who conducted the corrective action?
(select one)
□ Operator
□ Contractor
□ Manufacturer
_____________________________________________________________________________________
XX.Was the failure associated with an HSE Incident: □ Yes □ No
If Yes, what was the type of incident? (select all that apply)
□ One or More Fatalities
□ Injury to 5 or more persons in a single incident
□ Tier 1 Process Safety Event (API 754/IOGP 456)
□ Loss of Well Control
□ $1 million direct cost from damage of loss of facility/vessel/equipment
□ Oil in the water >= 10,000 gallons (238 bbls)
□ Tier 2 Process safety event (API 754/IOGP 456)
□ Collisions that result in property or equipment damage > $25,000
□ Incident involving crane or personnel/material handling operations
□ Loss of Station-keeping
□ Gas release (H2S and Other) that result in process or equipment shutdown
□ Muster for evacuation
□ Structural Damage
□ Spill < 10,000 gallons (238 bbls)
□ Other, Specify ______________________________________________________________

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Appendix
The Act
AIV
ANSI
API
APM
ASME
BAST
BOEM
BOPs
BSDV
BSEE
CSU
CVA
DOI
DPP
DWOP
E.O.
ESD
FPS
FPSO
FSV
GLIV
GOM
H2S
HP
HPHT
INCs
ISO
IVA
LP
LSH
MAWP
MMS
MOAs
MODU
MOU
NAE
NPRM
NTL
NTTAA
OESC
OFR
OIRA
OMB
OCS
OCSLA
P&ID

02-Sep-2016

List of Acronyms and References
Outer Continental Shelf Lands Act
alternate isolation valve
American National Standards Institute
American Petroleum Institute
Application for Permit to Modify
American Society of Mechanical Engineers
Best available and safest technology
Bureau of Ocean Energy Management
Blowout Preventers
Boarding shutdown valves
Bureau of Safety and Environmental Enforcement
column-stabilized-unit
certified verification agent
Department of the Interior
Development and Production Plan
Deepwater Operations Plan
Executive Order
emergency shutdown
floating production systems
floating production, storage, and offloading facility
flow safety valves
gas-lift isolation valve
Gulf of Mexico
hydrogen sulfide
high pressure
high pressure high temperature
Incidents of noncompliance
International Organization for Standardization
Independent verification agent
low pressure
level safety high
Maximum allowable working pressure
Minerals Management Service
Memoranda of Agreement
mobile offshore drilling unit
Memorandum of Understanding
National Academy of Engineering
Notice of Proposed Rulemaking
Notices to Lessees and Operators
National Technology Transfer and Advancement Act
Ocean Energy Safety Advisory Committee
Office of the Federal Register
Office of Information and Regulatory Affairs
Office of Management and Budget
Outer Continental Shelf
Outer Continental Shelf Lands Act
piping and instrumentation diagram

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PE
PLC
PRA
PSH
PSHL
psi
psia
psig
PSL
PSV
RFA
RP
SBA
SBREFA
SAFD
SDV
Secretary
SEMS
SIL
SWRI
Spec.
SPPE
SSSV
SSV
TLPs
TSE
TSH
USCG
USV
VRU
WI
WISDV
WIV

02-Sep-2016

Professional Engineer
programmable logic controller
Paperwork Reduction Act
pressure safety high
pressure safety high and low
Pounds per square inch
pounds per square inch absolute
pounds per square inch gauge
pressure safety low
pressure safety valve
Regulatory Flexibility Act
Recommended Practice
Small Business Administration
Small Business Regulatory Enforcement Fairness Act
safety analysis flow diagram
shutdown valve
Secretary of the Interior
Safety and Environmental Management Systems
safety integrity level
Southwest Research Institute
Specification
Safety and Pollution Prevention Equipment
Subsurface safety valve
surface safety valve
tension-leg platforms
temperature safety element
temperature safety high
U.S. Coast Guard
Underwater safety valve
vapor recovery unit
water injection
water injection shutdown valve
water injection valve

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