Gas Blowby - An Overview - ScienceDirect Topics

6/29/2021 Gas Blowby - an overview | ScienceDirect Topics
Gas Blowby
Gas blowby occurs when free gas escapes with the liquid phase and
can be an indication of low liquid level, vortexing, or level control
failure.
From: Gas-Liquid And Liquid-Liquid Separators, 2008
Related terms:
Crankcases, Relief Valves, Separators, Overpressure, Relief Device, Safety Analysis,

Safety Device
Two-Phase Gas–Liquid Separators

Maurice Stewart, Ken Arnold, in Gas-Liquid And Liquid-Liquid Separators, 2008
3.6.5 Gas Blowby

Gas blowby occurs when free gas escapes with the liquid phase and can be an
indication of low liquid level, vortexing, or level control failure. This could lead to a
very dangerous situation. If there is a level control failure and the liquid dump valve
is open, the gas entering the vessel will exit the liquid outlet line and would have to
be handled by the next downstream vessel in the process. Unless the downstream
vessel is designed for the gas blowby condition, it can be over-pressured. Gas
blowby can usually be prevented by installing a level safety low sensor (LSL) that
shuts in the inflow and/or outflow to the vessel when the liquid level drops to 10–
15% below the lowest operating level. In addition, downstream process
components should be equipped with a pressure safety high (PSH) sensor and a
pressure safety valve (PSV) sized for gas blowby.
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URL: https://www.sciencedirect.com/science/article/pii/B9780750689793000039
Relief, vent and flare disposal systems

Maurice Stewart, in Surface Production Operations, 2016
8.2.2 Causes of overpressure

The most common causes of overpressure in upstream oil and gas operations are
blocked discharge, gas blowby, and fire. When the worst-case relief load is caused
by a control valve failing to open (blocked discharge), the relief device should be
sized with full-sized trim in the control valve, even if the actual valve has reduced
trim. When the worst-case relief load is caused by gas blowby, the relief device
should be sized with full-sized trim in the smallest valve in the liquid-outlet line,
even if the actual valve has reduced trim. Many vessels are insulated for energy
savings. Thermal insulation limits the heat absorption from fire exposure as long as
it is intact. It is essential that effective weather protection be provided so that
insulation will not be removed by high-velocity fire-hose streams.
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Measurement of liquid fuel, oil, and combustion air

consumption
Anthony J. Martyr, David R. Rogers, in Engine Testing (Fifth Edition), 2021
Measurement of crankcase blowby

In all reciprocating ICEs there is a flow of gas into and out of the clearances
between piston top land, ring grooves, and cylinder bore. In an automotive
gasoline engine these can amount to 3% of the combustion chamber volume.
Since in a spark-ignition engine the gas consists of unburned mixture that
emerges during the expansion stroke too late to be burned, this can be a major
source of HC emissions and represents a loss of power. Some of this gas will leak
past the rings and piston skirt as blowby into the crankcase. It is then vented back
into the induction manifold and to this extent reduces the HC emissions and fuel
loss but has an adverse effect on the lubricant. A second possible source of blowby
gas is from the oil drain a turbocharger system feeds into the crankcase void; to
isolate this source and to measure the volumes produced requires a separate
metering device.
Blowby flow is highly variable over the full range of an engine’s performance and
life; therefore accurate blowby meters will need to be able to deal with a wide range
of flows and with pulsation. Instruments based on the orifice measurement
principle, coupled with linearizing signal conditioning (the flow rate is proportional
to the square root of the differential pressure), are good at measuring the blowby
gas in both directions of flow that can occur when there is heavy pulsation between
pressure and partial vacuum in the crankcase.
Within the gas flow there may be carbon and other “dirt” particles; the sensitivity of
the measuring instrument to this dirt will depend on the application. Sensitivity is
shown in Table 15.1.
Table 15.1. Types of blowby meters.
Type Typical accuracy Dirt sensitivity Lowest flow (L/min)
Positive impeller 2% FS Medium Approx. 6
Hot wire 2% High Approx. 28
Commercial gas meter 1% FS High Claimed 0.5
Vortex 1% High Approx. 7
Flow through an orifice 1% Low Claimed 0.2
Note that a “flow through an orifice” device usually has an inferior turndown
ratio to most other types. FS, Full scale.
Crankcase blowby is a significant indicator of engine condition and should

preferably be monitored during any extended test sequence. An increase in blowby
can be a symptom of various problems such as incipient ring sticking, bore
polishing, deficient cylinder bore lubrication, or developing turbocharger
problems.
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Safety and environmental management programs
Ian Sutton, in Offshore Safety Management, 2012
Appendix B—Industry codes, practices, and standards

Appendix B in RP 75 provides a list of reference documents that have achieved
substantial acceptance within industry and government bodies. They are shown
here in Table 3.3. Most are from the API, but other organizations, such as the
ASME, are also referenced.
Table 3.3. RP 75 Referenced Standards
▪ Bull E2 Management of Naturally Occurring Radioactive Materials (NORM) in

Oil and Gas Production
▪ Publ 510 Pressure Vessel Inspection Code: Maintenance Inspection, Rating,

Repair, and Alteration
▪ Publ 521 Guide for Pressure-Relieving and Depressuring Systems
▪ Publ 2004 Inspection for Fire Protection
▪ Publ 2007 Safe Maintenance Practices in Refineries
▪ Publ 2015 Cleaning Petroleum Storage Tanks
▪ Publ 2201 Procedures for Welding or Hot Tapping on Equipment Containing

Flammables
▪ Publ 2207 Preparing Tank Bottoms for Hot Work
▪ Publ 2217A Guidelines for Work in Inert Confined Spaces in the Petroleum
Industry
▪ Publ 2510 Design and Construction of Liquefied Petroleum Gas (LPG)

Installations
▪ Publ 2510A Fire-Protection Considerations for the Design and Operation of

Liquefied Petroleum Gas (LPG) Storage Facilities
▪ RP 1107 Pipeline Maintenance Welding Practices
▪ RP 2D Operation and Maintenance of Offshore Cranes
▪ RP 4G Maintenance and Use of Drilling and Well Servicing Structures
▪ RP 76 Contractor Safety Management for Oil and Gas Drilling and Production
Operations
▪ RP 500 Classification of Locations for Electrical Installations at Petroleum

Facilities
▪ RP 505 Recommended Practice for Classification of Locations for Electrical

Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1 and Zone 2
▪ RP T-1 Orientation Program for Personnel Going Offshore for the First Time
▪ RP T-2 Qualification Programs for Offshore Production Personnel Who Work

with Anti-Pollution Safety Devices
▪ RP T-4 Training of Offshore Personnel in Non-Operating Emergencies
▪ RP T-6 Training and Qualifications of Personnel in Well Control Equipment and

Techniques for Completion and Workover Operations on Offshore Locations
▪ RP T-7 Training of Personnel in Rescue of Persons in Water
▪ Spec 2C Offshore Cranes
▪ Spec 4F Drilling and Well Servicing Structures
▪ Std 1104 Welding of Pipelines and Related Facilities
Three of the references, each of which belongs in the RP 14 Series, are particularly
important. They are briefly discussed below.
RP 14C
The full title of this standard is Analysis, Design, Installation and Testing of Basic
Surface Safety Systems on Offshore Production Platforms. It specifies the
requirements for the analysis, design, installation, and testing of surface safety
systems for offshore production platforms (not drilling or exploration facilities).
Although it is a Recommended Practice, RP 14C had been incorporated as a legal
requirement by the MMS prior to the publication of the SEMS rule (Chapter 4).
This practice is built around the idea that if hydrocarbons can remain contained in
the system of pipes and vessels, then a serious process-related accident is unlikely
to occur. This goal is achieved by identifying those process hazards that could lead
to a release, and then installing two independent protective devices for each
detectable event. The two levels of protection should be independent of, and in
addition to, the control devices used in normal process operation. In general, the
two levels should be provided by functionally different types of safety devices for a
wider spectrum of coverage. Two identical devices would have the same
characteristics and might have the same inherent weaknesses.
A common example of two separate and independent devices concerns high-
pressure protection. A high-pressure switch (PSH) is the first level of response. It
detects a high pressure and initiates actions such as shutting off heat sources and
stopping feed streams to the affected equipment. If these actions are insufficient to
control the pressure, a second device, usually a pressure safety relief valve (PSRV)
opens, and quickly vents the vessel's contents to a safe location (usually a flare).
RP 14C has been criticized as being “overkill” and “ultraconservative.” It has also
been challenged as being outdated in a modern world of safety instrumented
systems. Such criticisms will likely be addressed as updates are issued (a new
edition is currently being prepared). In the meantime, the practice does seem to be
effective. Failures in safety systems are rarely, if ever, cited as being a factor in
major offshore events.
RP 14C is implemented using a three-step process.
(1) Create a safety analysis table (SAT) that lists undesirable events that could affect
a component such as a pressure vessel. Such events include overpressure, low
pressure (vacuum), a leak, liquid overflow, high temperature, and gas blowby.
(2) Create a safety analysis checklist (SAC) that lists all recommended safety devices
and that shows conditions under which particular safety devices may be
excluded.
(3) Create a safety analysis function evaluation (SAFE) chart. This chart shows all
process components and their required safety devices.
RP 14C also provides a standard for component identification. The first letter
identifies the component type. For example, C is compressor, M is pressure vessel
(ambient temperature). This can be followed by a modifier. So MAV is a metering
pressure vessel. Three additional digits are then be assigned to provide a unique
identification for that item and its location.
RP 14G
The full title of this standard is Fire Prevention and Control on Open-Type Offshore
Production Platforms. It provides recommendations for minimizing the likelihood of
an accidental fire, and for designing, inspecting, and maintaining fire control
systems. It emphasizes the need to train personnel in fire fighting, to conduct
routine drills, and to establish methods and procedures for safe evacuation. The
fire control systems discussed in this RP are intended to provide an early response
to incipient fires to prevent their growth. They provide a base line and are not
intended to preclude the application of more extensive practices to meet special
situations or the substitution of other systems, which will provide an equivalent or
greater level of protection.
This publication is applicable to fixed open-type offshore production platforms,
which are generally installed in moderate climates and which have sufficient
natural ventilation to minimize the accumulation of vapors. Enclosed areas, such as
quarters buildings and equipment enclosures, normally installed on this type
platform, are also addressed. Totally enclosed platforms such as those that are
installed when weather conditions are very severe are outside the scope of this RP.
RP 14J
First published in 1993, API RP 14J—Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities—is one document containing useful
procedures and guidelines for planning, designing, and arranging offshore
production facilities, and for performing a hazards analysis on open-type offshore
production facilities (like RP 14C, the focus is on production facilities). It covers
design concepts, hazard mitigation, personnel evacuation, equipment
arrangements, and hazards analysis. A checklist is provided.
The standard is intended to bring together a brief description of basic hazards
analysis procedures for offshore production facilities in one place. This RP
discusses several procedures that could be used to perform a hazards analysis, and
it presents minimum requirements for process safety information and hazards
analysis, which can be used for satisfying the requirements of API RP 75.
Some of the special offshore hazards that the standard considers are listed below.
(1) Spatial limitations that may cause potential ignition sources being installed in
or near production equipment.
(2) Spatial limitations that may result in quarters being installed near production
equipment, pipeline/flow line risers, fuel storage tanks, or other major fuel
sources.
(3) The inherent fire hazard presented by the release of flammable liquids or
vapors, whether during normal operations or as a result of any unusual or
abnormal condition.
(4) The severe marine environment, including corrosion, remoteness/isolation,
and weather (wind, wave and current and ice).
(5) High-temperature and high-pressure fluids, hot surfaces, and rotating
equipment located in or near operating areas.
(6) The handling of hydrocarbons over water.
(7) Large inventories of hydrocarbons from wells/reservoirs and pipelines
connected to or crossing a producing platform.
(8) Storage and handling of hazardous chemicals.
(9) Potential H2S releases.
Read full chapter

Regulations and Standards

Ian Sutton, in Offshore Safety Management (Second Edition), 2014
Engineering standards
Hundreds of engineering standards are used by the offshore oil and gas industry.
For example, Appendix B of RP 75 lists the API publications and are shown in Table
4.1. Some of the more important standards mentioned in Table 4.1 are discussed
in greater detail below.
API RP 14C
The full title of this standard is “Analysis, Design, Installation and Testing of Basic
Surface Safety Systems on Offshore Production Platforms.” It specifies the
requirements for the analysis, design, installation, and testing of surface safety
systems for offshore production platforms (not drilling or exploration facilities).
Although it is a Recommended Practice, RP 14C had been incorporated as a legal
requirement by the MMS prior to the publication of the SEMS rule.
This practice is built around the idea that, if hydrocarbons can remain contained in
the system of pipes and vessels, then a serious process-related accident is unlikely
to occur. This goal is achieved by identifying those process hazards that could lead
to a release, and then installing two independent protective devices for each
detectable event. The two levels of protection should be independent of, and in
addition to, the control devices used in normal process operation. In general, the
two levels should be provided by functionally different types of safety devices for a
wider spectrum of coverage. Two identical devices would have the same
characteristics and might have the same inherent weaknesses.
A common example of two separate and independent devices concerns high
pressure protection. A high-pressure switch (PSH) is the first level of response. It
detects high pressure and initiates actions such as shutting off heat sources and
stopping feed streams of the affected equipment. If these actions are insufficient to
control the pressure, a second device, usually a pressure safety relief valve (PSRV),
opens and quickly vents the vessel’s contents to a safe location (usually a flare).
RP 14C has been criticized as being “overkill” and “ultraconservative.” It has also
been challenged as being out-of-date in a modern world of safety-instrumented
systems. Such criticisms will likely be addressed as updates are issued (a new
edition is currently being prepared). In the meantime, the practice does seem to be
effective. Failures in safety systems are rarely, if ever, cited as being a factor in
major offshore events.
Structure
RP 14C is implemented using a three-step process:
1. Create a Safety Analysis Table (SAT) that lists undesirable events that could
affect a component such as a pressure vessel. Such events include
overpressure, low pressure (vacuum), a leak, liquid overflow, high temperature
and gas blowby.
2. Create a Safety Analysis Checklist (SAC) that lists all recommended safety
devices and that shows conditions under which particular safety devices may be
excluded.
3. Create a Safety Analysis Function Evaluation (SAFE) Chart. This is a chart
showing all process components and their required safety devices.
RP 14C also provides a standard for component identification. The first letter
identifies the component type. For example, “C” is for compressor and “M” is for
pressure vessel (ambient temperature). This can be followed by a modifier. So MAV
is a metering pressure vessel. Three additional digits are then assigned to provide a
unique identification for that item and its location.
Contents
Table 4.2 provides the Table of Contents for RP 14C.
Table 4.2. Contents for API RP 14C
1. General
1.1. Introduction
1.2. Scope
1.3. Organization of Technical Content
1.4. Government Codes, Rules, and Regulations
1.5. Industry Codes, Standards, and Recommended Practices
1.6. Metric Conversions
2. Safety Device Symbols and Identification
2.1. Introduction
2.2. Functional Device Identification
2.3. Symbols
2.4. Component Identification
2.5. Example Identification
3. Introduction to Safety Analysis and System Design
3.1. Purpose and Objectives
3.2. Safety Flow Chart
3.3. Modes of Safety System Operation
3.4. Premises for Basic Analysis and Design
4. Protection Concepts and Safety Analysis
4.1. Introduction
4.2. Protection Concepts
4.3. Safety Analysis
4.4. Analysis and Design Procedure Summary
Appendix
Appendix A: Process Component Analysis
Appendix B: Analysis Tables
Appendix C: Support Systems
Appendix D: Testing and Reporting Procedures
Appendix E: Examples of Safety Analysis Flow Diagram and Safety
Analysis Function Evaluation (SAFE) ChartAppendix F: Toxic Gas Section
Appendix G: Definitions
API RP 14H
The full title of this standard is, “Fire Prevention and Control on Open Type
Offshore Production Platforms.” It provides recommendations for minimizing the
likelihood of having an accidental fire, and for designing, inspecting, and
maintaining fire control systems. It emphasizes the need to train personnel in
firefighting, to conduct routine drills, and to establish methods and procedures for
safe evacuation. The fire control systems discussed in this recommended practice
are intended to provide an early response to incipient fires to prevent their growth.
They provide a baseline, and are not intended to preclude the application of more
extensive practices to meet special situations or the substitution of other systems
that will provide an equivalent or greater level of protection.
which are generally installed in moderate climates and have sufficient natural
ventilation to minimize the accumulation of vapors. Enclosed areas, such as living
quarters buildings and equipment enclosures, normally installed on this type of
platform, are also addressed. Totally enclosed platforms such as those that are
API RP 14J
First published in 1993, API RP 14J entitled Recommended Practice for Design and
Hazards Analysis for Offshore Production Facilities, assembles in one document
useful procedures and guidelines for planning, designing and arranging offshore
production facilities, and for performing a hazards analysis on open-type offshore
production facilities. It covers design concepts, hazard mitigation, personnel
evacuation, equipment arrangements, and hazards analysis. It was revised in 2001
and reissued in 2007.
This standard brings together in one place a brief description of basic hazards
analysis procedures for offshore production facilities. This recommended practice
discusses several procedures that could be used to perform a hazards analysis and
it presents minimum requirements for process safety information and hazards
analysis that can be used for satisfying the requirements of API RP 75.
Some of the special offshore hazards that the standard considers are listed below:
1. Spatial limitations that may cause potential ignition sources being installed in
or near production equipment
2. Spatial limitations that may result in living quarters being installed near
production equipment, pipeline/flow line risers, fuel storage tanks, or other
major fuel sources
3. The inherent fire hazard presented by the release of flammable liquids or
vapors, whether during normal operations or as a result of any unusual or
abnormal condition
4. The severe marine environment, including corrosion, remoteness/isolation,
and weather (wind, waves, current, and ice)
5. High-temperature and high-pressure fluids, hot surfaces, and rotating
equipment located in or near operating areas
6. The handling of hydrocarbons over water
7. Large inventories of hydrocarbons from wells/reservoirs and pipelines
connected to or crossing a producing platform
8. Storage and handling of hazardous chemicals
9. Potential H2S releases.
The guidance provided in RP 14J is of a general nature and is not quantified, as can
be seen from the following quotation:
The layout of production equipment should allow space for personnel escape
routes, as well as space for fighting fires. Living quarters should be positioned to
provide a quick and easy escape for personnel to the boat landing or escape
devices.
There is no quantification in the above statement. For example, it does not say how
wide escape routes should be.
The following items are specifically covered by the standard:
• Wellheads, flowlines, and headers
• Pressure vessels
• Atmospheric tanks
• Direct-fired and exhaust-heated components
• Pumps
• Compressors
• Pipelines and pipeline risers
• Heat exchangers
• Vent, flare, and emergency relief systems
• Relief valve sizing
• Drain systems
• Piping design, including a detailed discussion having to do with the selection
of spec breaks
• Corrosion and erosion prevention
• Surface safety systems
• Programmable electronic systems and remote operations
• Electrical systems
• Living quarters.
Special safety considerations are discussed for the following systems:
• Simultaneous operations and multiple use
• Toxic gas
• Gas processing
• Human engineering.
Contents
The Table of Contents for RP 14J is shown in Table 4.3.
Table 4.3. Contents of RP 14J
1. General
1.1. Purpose
1.2. Scope
1.3. Industry Codes, Practices and Standards
1.4. Government Codes, Rules and Regulations
1.5. Organization of Technical Content
2. Introduction
2.1. General
2.2. Containing Hydrocarbons
2.2.1.Surface Safety Systems
2.2.2.Production Equipment Maintenance
2.2.3.Equipment Operation
2.2.4.Special Precautions
2.2.5.Control of Normal Hydrocarbon Releases
2.3. Preventing Hydrocarbon Ignition
2.3.1.Flare, Vent and Drain Systems
2.3.2.Separation of Fuel and Ignition Sources
2.3.3.Adequate Ventilation
2.3.4.Combustible Gas Detection
2.4. Preventing Fire Escalation
2.4.1.Fire Detection
2.4.2.Hydrocarbon Inventory Reduction
2.4.3.Passive Fire Protection
2.4.4.Active Fire Protection
2.5. Personnel Protection and Escape
2.5.1.Personnel Escape Routes
2.5.2.Fire-Fighting and Other Emergency Equipment
2.5.3.Fire-Fighting and Evacuation Procedures
2.6. Hazards Analysis
3. Basic Facilities Design Concepts
3.1. General
3.2. Applicable Codes, Regulations, Standards, and Recommended Practices
3.3. Mechanical Design Considerations
3.3.1.Wellheads, Flowlines and Headers
3.3.2.Pressure Vessels
3.3.3.Atmospheric Tanks
3.3.4.Direct-Fired and Exhaust-heated Components

3.3.5.Pumps
3.3.6.Compressors
3.3.7.Pipelines and Pipeline Risers
3.3.8.Heat Exchangers
3.3.9.Vent, Flare and Emergency Relief Systems
3.3.10.Relief Valve Sizing
3.3.11.Drain Systems
3.3.12.Piping Design
3.3.13.Corrosion and Erosion Prevention
3.3.14.Surface Safety Systems
3.3.15.Programmable Electronic Systems and Remote Operations
3.3.16.Electrical Systems
3.4. Special Safety Considerations
3.4.1.Simultaneous Operations and Multiple Use
3.4.2.Toxic Gas Considerations
3.4.3.Gas Processing
3.4.4.Human Engineering
4. Hazard Mitigation and Personnel Evacuation
4.1. General
4.2. Fire and Gas Detection, Alarm/Communication Systems
4.3. Escape Paths
4.4. Fire-Fighting and Evacuating Procedures
4.5. Passive Fire Mitigation
4.6. Active Fire Mitigation
4.7. Hydrocarbon Inventory Reduction
5. Platform Equipment Arrangements
5.1. General
5.1.1.Wind Direction
5.1.2.Firewalls and Barrier Walls
5.1.3.Process Flow
5.1.4.Maintenance of Equipment
5.1.5.Safe Welding Areas
5.1.6.Simultaneous Operations
5.2. Wellhead Areas
5.3. Unfired Process Areas
5.4. Hydrocarbon Storage Tanks
5.5. Fired Process Area
5.6. Machinery Areas
5.7. Living Quarters Area
5.8. Pipelines and Risers
5.9. Flares and Vents
5.10.Practical Limitations
6. Documentation
6.1. General
6.2. Safety and Environmental Information
6.2.1.P&IDs
6.2.2.Process Design Information
6.2.3.Relief Valve Sizing Information
6.2.4.Process Safety Information
6.2.5.Layout Information
6.2.6.Fire Protection and Safety Equipment Information
6.2.7.Hazards Analysis
6.2.8.Material Safety Data
6.3. Documentation for Hazards Analysis
6.4. Design Documentation for New Facilities
6.4.1.Design Basis
6.4.2.Supporting Calculations
6.4.3.Drawings
6.4.4.Vendor Supplied Information
6.5. Pre-Start-Up Review
6.6. Operating Procedures
6.6.1.Start-Up Procedures
6.6.2.Normal Operating Procedures
6.6.3.Shutdown Procedures
7. Hazards Analysis
7.1. General
7.2. Introduction
7.3. Application
7.4. Hazards Analysis Concepts
7.4.1.Compliance with Standard Practice
7.4.2.Predictive Hazards Analysis
7.4.3.Application to Offshore Operations
7.5. Hazards Analysis Methods
7.5.1.Checklist
7.5.2.“What If ” Analysis
7.5.3.Hazard and Operability (HAZOP) Study
7.5.4.Failure Modes and Effects Analysis (FEMA)
7.5.5.Fault Tree Analysis (FTA)
7.5.6.Other Methods
7.6. Review Procedures
7.6.1.Organization
7.6.2.Hazards Analysis
7.6.3.Documentation
7.6.4.Corrective Action
7.7. Guidelines for Selecting an Analysis Method
Appendix A.1. Example Simplified Checklist
Appendix A.2. Example Detailed Checklist
Appendix B. Analysis of Example Layouts
Appendix C. Industry Codes, Guides, and Standards
Appendix D. Government Codes, Rules, and Regulations
Purpose
The Introduction to RP 14J starts with the following statement:
The purpose of this recommended practice is to assemble into one document
useful procedures and guidelines for planning, designing and arranging offshore
production facilities, and performing a hazards analysis on open-type offshore
production facilities. This will promote safe, pollution free and efficient production
of oil and gas. This publication is only a guide and requires the application of
sound engineering judgment.
This standard applies only to the design of production facilities. It may be useful
for drilling operations, but it is not written for such operations.
It is linked to RP 75, as shown in the following statement:
This recommended practice discusses several procedures that could be used to
perform a hazards analysis, and it presents minimum requirements for process
safety information and hazards analysis that can be used for satisfying the
requirements of API RP 75.
Design safety
The practice notes that design safety is achieved through the use (in the order
shown) of:
1. Inherent design features (ideally by removing or reducing the amount of
hazardous materials);
2. Engineering controls; and
3. Administrative controls.
Safe operations are then achieved by:
• Minimizing the likelihood of uncontrollable releases of hydrocarbons and other
hazardous materials;
• Minimizing the chances of ignition;
• Preventing fire escalation and equipment damage; and
• Providing for personnel protection and escape.
RP 14J stresses the importance of keeping ignition sources away from areas from
which hydrocarbons may be released. Further guidance is provided in API RP 500
—Classification of Locations for Electrical Installations at Petroleum Facilities. This
standard also provides guidance to do with ventilation and area classification.
Reference documents
API RP 14J references many other standards, as can be seen in Table 4.4. Appendix
C in RP 14J provides additional references and standards.
Table 4.4. Referenced Standards
General ASME Code, Section VIII; ANSI B16.5
Separator API 12J, Publ. 421
Indirect-type oil field API 12K, 12N

heaters
Emulsion treaters API 12L
Storage tanks ANSI/AWWA D103; API 12B, 12D, 12F, 12P, 12R1, Std.
2000, Publ. 2210
Engines ANSI 7B-11C, 1B; ASME PTC 17-73
Aerial coolers API 11K, 631M, 661, 632
Wellhead SSV’s API 14D, 14H; 30 CFR 250.122 (MMS)
Pipe, valves fittings ANSI B31.3, B31.4, B16.5, B31.8; API 6D, 14E, Publ. 2028,
Std. 590
Instrumentation ISA RP7.1, RP12.1, 12.2, S7.4, S12.4
Cranes API 2C
Heliports API 2L; Louisiana DOT, Offshore Heliport Design Guide

Information Publ.; 46 CFR Part 108.233, .235, .235
(USCG)
Relief valves/vent API 520, 521

systems
Vent tank API 2000
Centrifugal pumps API 610; Hydraulic Institute Stds.; ANSI B73.1, B73.2
Gas turbines API 616; ASME PTC 1-86, PTC 16-58
Centrifugal API 617; ASME B19.3D-90, PTC 10-65

compressors
Reciprocating API 618; ASME B19.3D-90, PTC 9-70

compressors
Shell- and-tube-heat API 660; TEMA Std.

exchangers
Reciprocating pumps API 674; ASME PTC 7-49, PTC 7.1-62
Rotary pumps API Publ. 676
General-purpose gear API 677

units
Packaged, centrifugal API 672; ASME B19.1-90

air compressors
Packaged, API 680; ASME B19.1-90

reciprocating air
compressors
Glycol dehydration API 12GDU
Rotary-type positive API 619

displacement
compressors
Generators and NEMA and UL standards

motors
Generators, IEEE 446

emergency
Transformers IEEE C57
Hazards analysis
RP 14J provides guidance for conducting hazards analyses. It states:
Hazards analysis is a systematic procedure for identifying, evaluating and
controlling potential hazards in a facility. A hazards analysis program should be
applied to all phases of the life of a facility from project inception through
abandonment to assess potential hazards during design, construction and
operation.
The guidance that RP 14J provides on this topic is in alignment with other API
documents and industry standards.
Checklists
Appendix A in RP 14J provides a set of useful checklists that match the text of the
standard itself. It starts with a simplified checklist that can be used for simple and
low risk facilities such as single well caissons and most unmanned wellhead
platforms with minimum process facilities. The standard states that the “primary
concern in these types of facilities is that production is shut-in on detection of an
abnormal condition”.
Appendix A also provides examples of more detailed checklists that fall under the
following major categories:
1. General facility/layout
2. Process
3. Systems
4. Fire and gas
5. Mechanical.
Under each section a set of questions is provided. So, for example, under “General
Facility/Layout” the following question is provided:
1.B.10 Are the cranes located so the supply boats and laydown areas are reached
with minimum of lifting over process and wellhead areas, or over any equipment or
piping which contain hydrocarbons? If this is not possible, has dropped-object
protection been considered for critical equipment?
Finally, a Hazards Analysis Worksheet is provided.
The checklists and worksheets should be used by each operator to develop their
own analysis tool.
Appendix B in RP 14J provides a particularly useful “Analysis of Example Layouts” in
which three different deck configurations are critiqued for both positive and safety
features. It states:
Three representative deck layouts follow. Each illustrates the trade-offs involved in
developing a design based on the recommendations of this RP. The advantages
and disadvantages of each design are listed—but are not exhaustive. The main
purpose of the analyses is to demonstrate that no design can be free of
disadvantages; the best that can be hoped for is an acceptable compromise.
API RP 14G—Fire prevention and control on open-type offshore production
platforms
This standard provides recommendations for minimizing the likelihood of having
an accidental fire, and for designing, inspecting, and maintaining fire-control
systems. It emphasizes the need to train personnel in firefighting, to conduct
routine drills, and to establish methods and procedures for safe evacuation. The
fire-control systems discussed in this recommended practice are intended to
provide an early response to incipient fires to prevent their growth. They provide a
baseline, and are not intended to preclude the application of more extensive
practices to meet special situations or the substitution of other systems that will
provide an equivalent or greater level of protection.
which are generally installed in moderate climates and which have sufficient
natural ventilation to minimize the accumulation of vapors. Enclosed areas, such as
the living quarters buildings and equipment enclosures, normally installed on this
type platform, are also addressed. Totally enclosed platforms such as those that are
API RP 521— Guide for pressure-relieving and depressuring systems
This recommended practice is used in the design and evaluation of pressure-
relieving and vapor depressuring systems. This recommended practice is intended
to supplement the practices set forth in API Recommended Practice 520, Part 1, for
establishing a basis of design. RP 521 provides guidelines for examining the
principal causes of overpressure; determining individual relieving rates; and
selecting and designing disposal systems, including such component parts as
vessels, flares, and vent stacks.
Analysis
API RP 521 requires that those people designing relief valves and flare systems
consider all the potential scenarios that could require the use of a relief valve. All
assumptions used in the calculations should be listed along with the associated
technical and engineering information.
The analysis should include an evaluation of the equipment downstream of the
relief device, particularly the flare header. It is possible that if two or more relief
devices operate simultaneously, even if they themselves are adequate, the flare or
relief header could be overloaded.
Two-thirds rule
Shell and tube exchangers seldom have pressure-relief valves for fire exposure
because vapors will quickly flow to the next pressure vessel from which they can be
discharged. The “two-thirds rule” from API RP 521 states:
For relatively low-pressure equipment, complete tube failure is not a viable
contingency when the design pressure of the low-pressure side is equal to or
greater than two-thirds the design pressure of the high-pressure side. Minor
leakage can seldom result in overpressure of the low-pressure side during
operation.
If the above rule is satisfied, then a relief valve on the low-pressure side of the
exchanger is not needed provided the following contingencies are true:
• An engineering study is performed to verify that the low-pressure side of the
exchanger is able to absorb the flow rate through the rupture without over-
pressuring the exchanger.
• There are no block valves, check valves, or automatic-control valves on the low-
pressure inlet or outlet-piping systems that may isolate the exchanger.
• Operating procedures require that the high-pressure side be isolated before
the low-pressure side.
• Operating procedures require that the exchanger be immediately drained after
being removed from service. Also, the exchanger must remain drained while it
is out of service.
• The valve isolating the vessel and the exchanger will generally be a horizontal
stem and a manually operated gate that is locked open.
• The hot-side fluid is not hot enough to boil the cold-side fluid at the design
pressure.
Documentation
The following documentation requirements are used by one company:
The documentation must be sufficient to allow the owner to manage the flare
system in the event of future process modifications and to provide proof to
regulatory agencies that the system was adequately designed.
The documentation should include fluid compositions, temperatures, pressures,
and levels both for the operating conditions and for the relief system.
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Crankcases, Relief Valves, Separators, Overpressure, Relief Device, Safety Analysis,

Two-Phase Gas–Liquid Separators

3.6.5 Gas Blowby

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Relief, vent and flare disposal systems

8.2.2 Causes of overpressure

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Measurement of liquid fuel, oil, and combustion air

Measurement of crankcase blowby

Table 15.1. Types of blowby meters.

Type Typical accuracy Dirt sensitivity Lowest flow (L/min)

Positive impeller 2% FS Medium Approx. 6

Hot wire 2% High Approx. 28

Commercial gas meter 1% FS High Claimed 0.5

Vortex 1% High Approx. 7

Flow through an orifice 1% Low Claimed 0.2

Crankcase blowby is a significant indicator of engine condition and should

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Safety and environmental management programs

Appendix B—Industry codes, practices, and standards

Table 3.3. RP 75 Referenced Standards

▪ Bull E2 Management of Naturally Occurring Radioactive Materials (NORM) in

▪ Publ 510 Pressure Vessel Inspection Code: Maintenance Inspection, Rating,

▪ Publ 521 Guide for Pressure-Relieving and Depressuring Systems

▪ Publ 2004 Inspection for Fire Protection

▪ Publ 2007 Safe Maintenance Practices in Refineries

▪ Publ 2015 Cleaning Petroleum Storage Tanks

▪ Publ 2201 Procedures for Welding or Hot Tapping on Equipment Containing

▪ Publ 2207 Preparing Tank Bottoms for Hot Work

▪ Publ 2510 Design and Construction of Liquefied Petroleum Gas (LPG)

▪ Publ 2510A Fire-Protection Considerations for the Design and Operation of

▪ RP 1107 Pipeline Maintenance Welding Practices

▪ RP 2D Operation and Maintenance of Offshore Cranes

▪ RP 4G Maintenance and Use of Drilling and Well Servicing Structures

▪ RP 500 Classification of Locations for Electrical Installations at Petroleum

▪ RP 505 Recommended Practice for Classification of Locations for Electrical

▪ RP T-2 Qualification Programs for Offshore Production Personnel Who Work

▪ RP T-4 Training of Offshore Personnel in Non-Operating Emergencies

▪ RP T-6 Training and Qualifications of Personnel in Well Control Equipment and

▪ RP T-7 Training of Personnel in Rescue of Persons in Water

▪ Spec 2C Offshore Cranes

▪ Spec 4F Drilling and Well Servicing Structures

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Regulations and Standards

Table 4.2. Contents for API RP 14C

Table 4.3. Contents of RP 14J

3.3.4.Direct-Fired and Exhaust-heated Components

Table 4.4. Referenced Standards

General ASME Code, Section VIII; ANSI B16.5

Separator API 12J, Publ. 421

Indirect-type oil field API 12K, 12N

Emulsion treaters API 12L

Engines ANSI 7B-11C, 1B; ASME PTC 17-73

Aerial coolers API 11K, 631M, 661, 632

Wellhead SSV’s API 14D, 14H; 30 CFR 250.122 (MMS)

Instrumentation ISA RP7.1, RP12.1, 12.2, S7.4, S12.4

Heliports API 2L; Louisiana DOT, Offshore Heliport Design Guide

Relief valves/vent API 520, 521