Piping Tutorial (Basic)

1.1 Definition of Piping
Pipe is a pressure tight cylinder used to convey a fluid or to transmit a fluid pressure, ordinarily designated pipe in applicable material specifications. Materials designated tube or tubing in the specifications are treated as pipe when intended for pressure service.
Piping is an assembly of piping components used to convey, distribute, mix, separate, discharge, meter, control or snub fluid flows. Piping also includes pipe-supporting elements but does not include support structures, such as building frames, bents, foundations, or any equipment excluded from Code definitions.
Piping components are mechanical elements suitable for joining or assembly into pressure-tight fluid-containing piping systems. Components include pipe, tubing, fittings, flanges, gaskets, bolting, valves and devices such as expansion joints, flexible joints, pressure hoses, traps, strainers, in-line portions of instruments and separators.
Piping is typically round.
1.2 Piping Nomenclature, Components
Graphic of piping system illustrating
• Header
• Branch connection
• Valve
• Flange
• Expansion joint
• Expansion loop
• Pipe support
• Reducer
• Elbow

Pipe system essentials:
Header • Main run of piping
Take off • Branch run
Stub in • Branch fitting connection made to header by direct attachment of branch
•
Branch reinforcement • Material added in the vicinity of a branch opening to restore the mechanical integrity of the pipe
NPS • Nominal pipe size
Pipe support • Support elements which serve to maintain the structural integrity of the piping system, these are typically non-linear elements
Spring support • Support provided by an element composed of a spring assembly, these are linear support elements
Snubber • Support provided by an element composed of a non-linear, damping element

Category D • Within reference of B31.3, a service classification
Category M • Within reference of B31.3, a service classification
Expansible fluid • Any vapour or gaseous substance, any liquid under such pressure and temperature such that when pressure is reduced to atmospheric, will change to a gas
Hydro test • Test pressure = 1.5 x MAWP (some of the time)
MAWP • Maximum allowable working pressure
MDMT • Minimum design metal temperature
Fracture toughness • Typically measured by CVN (Charpy V Number) at MDMT
1.3 Regulatory Acts, Codes & Standards
Codes
Codes are rules for the design of prescribed systems which are given the force of law through provincial, state and federal legislation. In Canada, provincial governments have the responsibility for public safety that includes these facilities, among others:
• Pressure piping
• Pressure vessels
• Boilers
• Pipelines
• Plumbing systems
• Gas piping
Alberta Safety Codes Acts and Codes of Practice
The following are applicable to the first four facilities listed above.
Boilers and Pressure Vessels Regulation
• Prescribes requirements for registration of pressure vessels, boilers, pressure piping and fittings
Design, Construction and Installation of Boilers and Pressure Vessels Regulations
• Cites the codes and “bodies of rules” that form part of the regulations
• CSA B51 Boiler, Pressure Vessel and Pressure Piping Code
• CSA B52 Mechanical Refrigeration Code
• CAN/CSA Z184 Gas Pipeline Systems
• ASME Boiler & Pressure Vessel Code
• ASME B31 Pressure Piping Codes
• B31.1 Power Piping
• B31.3 Process Piping
• B31.4 Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia and Alcohols
• B31.5 Refrigeration Piping
• ANSI K61.1 Safety Requirements for the Storage and Handling of Anhydrous Ammonia
• NFPA 58 Standard for the Storage and Handling of Liquefied Petroleum Gases
• DOT Regulations of the Department of Transportation Governing the Transportation of Hazardous Materials in Tank Motor Vehicles
• MSS Standard Practice SP 25 Standard Marking System for Valves, Fittings, Flanges and Unions
• TEMA Standards of Tubular Exchanger Manufacturers Association
Pipeline Act
Cites the “minimum requirements for the design, construction, testing, operation, maintenance and repair of pipelines”:

• CAN/CSA Z183 Oil Pipeline Systems
• CAN/CSA Z184 Gas Pipeline Systems
• CSA Z169 Aluminum Pipe and Pressure Piping Systems
• Canadian Petroleum Association Recommended Practice for Liquid Petroleum Pipeline Leak Prevention and Detection in the Province of Alberta
Currently, CSA Z662 Oil and Gas Pipeline Systems
(This standard supercedes Z183 & Z184)
In the US:
As in Canada, some facilities are governed by federal regulations. Interstate pipeline facilities are defined by the:
• Code of Federal Regulations, Title 49
• Part 192 Transportation of Natural and Other Gas by Pipeline – Minimum Federal Safety Standards
• Part 193 Liquefied Natural Gas Facilities
• Part 195 Transportation of Hazardous Liquids by Pipeline
Other pipeline pressure piping codes include:
• ASME B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids
• ASME B31.8 Gas Transmission and Distribution Systems
1.4 Line Designation Tables
The Province of Alberta Safety Codes Act “Design, Construction and Installation of Boilers & Pressure Vessels Regulations” par 7(2) requires that construction of a pressure piping system must include submission of drawings, specifications and other information and include:
(a) Flow or line diagrams showing the general arrangement of all boilers, pressure vessels, pressure piping systems and fittings (2 copies)
(b) Pipeline identification lists showing the maximum pressures and temperatures for each pressure piping system (2 copies)
(c) A list of pressure relief devices, including the set pressure (2 copies)
(d) Material specifications, size, schedule and primary service rating of all pressure piping and fittings (2 copies)
(e) The welding procedure registration number
(f) The pressure pipe test procedure outlining the type, method, test media , test pressure, test temperature, duration and safety precautions (1 copy)
(g) A form, provided by the Administrator, completed by the engineering designer or contractor which relates to the general engineering requirements for design and field construction of pressure piping systems (AB 96)
(h) Such other information as is necessary for a safety codes officer to survey the design and determine whether it is suitable for approval and registration
Problem Set 1
1 Which Act governs the design of plant pressure piping systems in Alberta?
2 Are process plant water lines considered pressure piping systems?
3 For what fluid service category may a hydro test be waived per B31.3?
4 What is the difference between a pipe elbow and a bend?

2.0 Codes and Standards
The following codes are used for the design, construction and inspection of piping systems in North America.
2.1 The ASME B31 Piping Codes
Piping codes developed by the American Society of Mechanical Engineers:
B31.1 Power Piping
Piping typically found in electric power generating stations, in industrial and institutional plants, geothermal heating systems and central and district heating and cooling plants.
B31.3 Process Piping
Piping typically found in petroleum refineries, chemical, pharmaceutical, textile, per, semiconductor and cryogenic plants and related processing plants and terminals.
B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids
Piping transporting products which are predominately quid between plants and terminals and within terminals, pumping, regulating, and metering stations.
B31.5 Refrigeration Piping
Piping for refrigerants and secondary coolants.
B31.8 Gas Transportation and Distribution Piping Systems
Piping transporting products which are predominately gas between sources and terminals including compressor, regulating and metering stations, gas gathering pipelines.
B31.9 Building Services Piping
Piping typically found in industrial, institutional, commercial and public buildings and in multi-unit residences which does not require the range of sizes, pressures and temperatures covered in B311.1
B31.11 Slurry Transportation Piping Systems
Piping transporting aqueous slurries between plants and terminals within terminals, pumping and regulating stations.
The following codes are used to specify the geometric, material and strength of piping and components:
ASME B16 Dimensional Codes
The ASME B16 Piping Component Standards
Piping component standard developed by the American Society of Mechanical Engineers or the American National Standards Institute (ANSI)
B16.1 Cast Iron Pipe Flanges and Flanged Fittings
B16.3 Malleable Iron Threaded Fittings, Class 150 and 300
B16.4 Cast Iron Threaded Fittings, Classes 125 and 250
B16.5 Pipe Flanges and Flanged Fittings
B16.9 Factory Made Wrought Steel Butt welding Fittings
B16.10 Face to Face and End to End Dimensions of Valves
B16.11 Forged Fittings, Socket Welding and Threaded
B16.12 Cast Iron Threaded Drainage Fittings
B16.14 Ferrous Pipe Plugs, Bushings and Locknuts with Pipe Threads
B16.15 Cast Bronze Threaded Fittings Class 125 and 250
B16.18 Cast Copper Alloy Solder Joint Pressure Fittings
B16.20 Ring Joint Gaskets and Grooves for Steel Pipe Flanges
B16.21 Nonmetallic Flat Gaskets for Pipe Flanges
B16.22 Wrought Copper and Copper Alloy Solder Joint Pressure Fittings
B16.23 Cast Copper Alloy Solder Joint Drainage Fittings – DWV
B16.24 Cast Copper Alloy Pipe Flanges and Flanged Fittings Class 150, 300, 400,600, 900, 1500 and 2500
B16.25 Butt welding Ends
B16.26 Cast Copper Alloy Fittings for Flared Copper Tubes
B16.28 Wrought Steel Butt welding Short Radius Elbows and Returns
B16.29 Wrought Copper and Wrought Copper Alloy Solder Joint Drainage Fittings – DWV
B16.32 Cast Copper Alloy Solder Joint Fittings for Sovent Drainage Systems
B16.33 Manually Operated Metallic Gas Valves for Use in Gas Piping systems Up to 125 psig (sizes ½ through 2)
B16.34 Valves – Flanged, Threaded and Welding End
B16.36 Orifice Flanges
B16.37 Hydrostatic Testing of Control Valves
B16.38 Large Metallic Valves for Gas Distribution (Manually Operated, NPS 2 ½ to 12, 125 psig maximum)
B16.39 Malleable Iron Threaded Pipe Unions, Classes 1150, 250 and 300
B16.40 Manually Operated Thermoplastic Gs Shutoffs and Valves in Gas Distribution Systems
B16.42 Ductile Iron Pipe Flanges and Flanged Fittings, Class 150 and 300
B16.47 Large Diameter Steel Flanges (NPS 26 through NPS 60)

ASME B36 Piping Component Standards
Piping standards developed by the American Society of Mechanical Engineers / American National Standards Institute:
B36.10 Welded and Seamless Wrought Steel Pipe
B36.19 Stainless Steel Pipe
Other ASME or ANSI
B73.1 Horizontal, End Suction Centrifugal Pumps
B73.2 Vertical In-line Centrifugal Pumps
B133.2 Basic Gas Turbine
2.2 NEPA Codes
National Electrical Protection Association
Piping covering fire protection systems using water, carbon dioxide, halon, foam, dry chemical and wet chemicals.
NFC – NFPA Codes
National Fire Code / National Fire Protection Association
NFPA 99 Health Care Facilities
Piping for medical and laboratory gas systems.

2.3 CSA Standards
Canadian Standards Association
CSA Z662 – 94 Oil & Gas Pipeline Systems
This standard supercedes these standards:
• CAN/CSA Z183 Oil Pipeline Systems
• CAN/CSA Z184 Gas Pipeline Systems
• CAN/CSA Z187 Offshore Pipelines
Other CSA Piping and Component Codes:
B 51 Boilers and Pressure Vessels
B 53 Identification of Piping Systems
B 52 Mechanical Refrigeration Code
B 63 Welded and Seamless Steel Pipes
B 137.3 Rigid Poly-Vinyl Chloride (PVC) Pipe
B 137.4 Polyethylene Piping Systems for Gas Service
W 48.1 Mild Steel Covered Arc-Welding Electrodes
W 48.3 Low-Alloy Steel Arc-Welding Electrodes
Z 245.1 Steel Line Pipe
Z 245.11 Steel Fittings
Z 245.12 Steel Flanges
Z 245.15 Steel Valves
Z 245.20 External Fusion Bond Epoxy Coating for Steel Pipe
Z 245.21 External Polyethylene Coating for Pipe
Z 276 LNG – Production, Storage and Handling
2.4 MSS Standard Practices
Piping and related component standards developed by the Manufacturer’s Standardization Society. The MSS standards are directed at general industrial applications. The pipeline industry makes extensive use of these piping component and quality acceptance standards.
SP-6 Standard Finishes for Contact Faces Pipe Flanges and Connecting End Flanges of Valves and Fittings
SP-25 Standard Marking System for Valves, Fittings, Flanges and Union
SP-44 Steel Pipeline Flanges
SP-53 Quality Standards for Steel Castings and Forgings for Valves, Flanges and Fittings and Other Piping Components – Magnetic Particle
SP-54 Quality Standards for Steel Castings and for Valves, Flanges and Fittings and Other Piping Components – Radiographic
SP-55 Quality Standards for Steel Castings and for Valves, Flanges and Fittings and Other Piping Components – Visual
SP-58 Pipe Hangers and Supports – Material, Design and manufacture
SP-61 Pressure Testing of Steel Valves
SP-69 Pipe Hangers and Supports – Selection and Application
SP-75 High Test Wrought Butt Welding Fittings
SP-82 Valve Pressure Testing Methods
SP-89 Pipe Hangers and Supports – Fabrication and Installation Practices

2.5 API
American Petroleum Institute
The API standards are focused on oil production, refinery and product distribution services. Equipment specified to these standards are typically more robust than general industrial applications.
Spec. 5L Line Pipe
Spec. 6D Pipeline Valves
Spec. 6FA Fire Test for Valves
Spec. 12D Field Welded Tanks for Storage of Production Liquids
Spec. 12F Shop Welded Tanks for Storage of Production Liquids
Spec. 12J Oil and Gas Separators
Spec. 12K Indirect Type Oil Field Heaters
Std. 594 Wafer and Wafer-Lug Check Valves
Std. 598 Valve Inspection and Testing
Std. 599 Metal Plug Valves – Flanged and Butt-Welding Ends
Std. 600 Steel Gate Valves-Flanged and Butt-Welding Ends
Std. 602 Compact Steel Gate Valves-Flanged Threaded, Welding, and Extended-Body Ends
Std. 603 Class 150, Cast, Corrosion-Resistant, Flanged-End Gate Valves
Std. 607 Fire Test for Soft-Seated Quarter-Turn Valves
Std. 608 Metal Ball Valves-Flanged and Butt-Welding Ends
Std. 609 Lug-and Wafer-Type Butterfly Valves
Std. 610 Centrifugal Pumps For Petroleum, Heavy Duty Chemical and Gas Industry Services
Std. 611 General Purpose Steam Turbines for Refinery Services
Std. 612 Special Purpose Steam Turbines for Refinery Services
Std. 613 Special Purpose Gear Units for Refinery Services
Std. 614 Lubrication, Shaft-Sealing and Control Oil Systems for Special Purpose Application
Std. 615 Sound Control of Mechanical Equipment for Refinery Services
Std. 616 Gas Turbines for Refinery Services
Std. 617 Centrifugal Compressors for General Refinery Services
Std. 618 Reciprocating Compressors for General Refinery Services
Std. 619 Rotary-Type Positive Displacement Compressors for General Refinery Services
Std. 620 Design and Construction of Large, Welded, Low Pressure Storage Tanks
Std. 630 Tube and Header Dimensions for Fired Heaters for Refinery Service
Std. 650 Welded Steel Tanks for Oil Storage
Std. 660 Heat Exchangers for General Refinery Service
Std. 661 Air-Cooled Heat Exchangers for General Refinery Service
Std. 670 Vibrations, Axial Position, and Bearing-Temperature Monitoring Systems
Std. 671 Special Purpose Couplings for Refinery Service
Std. 674 Positive Displacement Pumps-Reciprocating
Std. 675 Positive Displacement Pumps-Controlled Volume
Std. 676 Positive Displacement Pumps-Rotary

Std. 677 General Purpose Gear Units for Refineries Services
Std. 678 Accelerometer-Base Vibration Monitoring System
Std. 1104 Welding Pipelines and Related Facilities
Std. 2000 Venting Atmospheric and low-Pressure Storage Tanks – Non-Refrigerated and Refrigerated
RP 530 Calculation for Heater Tube Thickness in Petroleum Refineries
RP 560 Fired Heater for General Refinery Services
RP 682 Shaft Sealing System for Centrifugal and Rotary Pumps
RP 1110 Pressure Testing of Liquid Petroleum Pipelines
Publ. 941 Steel for Hydrogen Service at Elevated Temperature and Pressures in Petroleum Refineries and Petrochemical Plants
Publ. 2009 Safe Welding and Cutting Practices in Refineries
Publ. 2015 Safe Entry and Cleaning of Petroleum Storage Tanks

2.6 ASTM
There are numerous American Society for Testing and Materials designations cover the specification of wrought materials, forgings and castings used for plate, fittings, pipe and valves. The ASTM standards are directed to dimensional standards, materials and strength considerations.
Some of the more material standards referenced are:
A 36 Specification for Structural Steel
A 53 Specification for Pipe, Steel, Black and Hot –Dipped, Zinc Coated Welded and Seamless
A 105 Specification for Forgings, Carbon Steel, for Piping Components
A 106 Specification for Seamless Carbon Steel Pipe for High Temperature Service
A 181 Specification for Forgings, Carbon Steel for General Purpose Piping
A 182 Specification for Forged or Rolled Alloy Steel Pipe Flanges, Forged Fittings, and Valves and Parts for High Temperature Service
A 193 Specification for Alloy Steel and Stainless Steel Bolting Materials for High Temperature Service
A 194 Specification for Carbon and Alloy Steel Nuts for Bolts for High Pressure and High Temperature Service
A 234 Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel for Moderate and Elevated Temperatures
A 333 Specification for Seamless and Welded Steel Pipe for Low Temperature Service
A 350 Specification for Forgings, Carbon and Low Alloy Steel Requiring Notch Toughness Testing for Piping Components
A 352 Specification for Steel Castings, Ferritic and Martensitic for Pressure Containing Parts Suitable for Low Temperature Service
A 420 Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel for Low Temperature Service
A 694 Specification for Forgings, carbon and Alloy Steel for Pipe Flanges, Fittings, Valves and Parts for High Pressure Transmission Service
A 707 Specifications for Flanges, Forged, Carbon and Alloy Steel for Low Temperature Service
Problem Set 2
1. A project award has been made. At the kick off meeting, the PM advises that piping design will be to B31.4. The facility is steam piping in a refinery extending from the boiler to the tank farm. What do you do or say and why?
2. A liquid pipeline is to be built to Z184. You raise an issue. Why?
3. What flange specification would you expect to reference for a gas pipeline facility?
Show the development of your answers.

Section 1 – References
Due to copyright laws, the following figures have not been published here. We leave as an exercise for the user to retrieve these for reference.
Fig 100.1.2(B) of ASME B31.1
Fig 300.1.1 of ASME B31.3 1996
Fig 300.1.1 of ASME B31.3 1999
Fig 400.1.1 of ASME B31.4
Fig 400.1.2 of ASME B31.4
Fig 1.1 of CSA Z 662
Fig 1.2 of CSA Z 662
Table of Contents CSA Z 662

3.0 Supplemental Documents
3.1 Owner’s Specifications & Documents
Many of the Owners in the industries we service are technically sophisticated and will often have supplementary specifications, standards or practices. It is the intent of these documents to clarify and provide interpretation of the legislated Codes and industry-accepted standards specific to the Owner’s facilities.
These specifications typically go beyond the requirements of Codes and without exception do not contravene a Code requirement.
3.2 Contractor’s Specifications & Documents
Engineering contractors may be called upon to provide the engineering specifications for a project if an Owner does not have his own standards or if required by terms of the contract.
Problem Set 3
1 What is the typical precedence of documents for engineering standards?
2 Can the Owner’s engineering standard override a Code provision?
3 Under what conditions can the Owner’s standard override a Code provision?
4 How would you deviate from an Owner’s engineering specification?

4.0 Piping Design
Piping design deals with the:
• Analytical design
• Material selection
• Geometric layout
• Fabrication
• Inspection specification
• Component specification
of piping and piping components.
4.1 Failure Mechanisms
Piping and piping components may fail if inadequately designed, by a number of different mechanisms. These failures, in the majority of cases are either load controlled or displacement controlled failures.
• Pipe rupture due to overpressure
• Bending failure in pipe span
• Elbow cracking after 10 years of service, 5000 cycles of heat up to 500 F
• on heat up, a line comes into contact with adjacent header which is at ambient temperature
• during startup on a cold winter day in Grande Prairie, an outdoor gas line located above grade and constructed to Z662 is suddenly subjected to full line pressure and ruptures.
• a 12” Sch.40 header, bottom supported, 40 feet long runs vertically up a tower and connects to a nozzle. On steam out of the vessel, a 1’ deflection is observed in the pipe and remains after the steam out procedure is completed and the pipe returns to ambient temperature.
• a header of a reciprocating compressor has been stressed checked; during operation vibration is observed in the line. During the unit turnaround, cracking is found at midspan in the wrought piping material.
• A stress check determines that a hot, high alloy line does not pass the flexibility requirements per B31.3. Twenty-five cycles are expected over the lifetime of the line.

4.2 Code Considerations for Design
Design of piping systems is governed by Codes. All codes have a common theme; they are intended to set forth engineering requirements deemed necessary for safe design and construction of piping installations.
The Codes are not intended to apply to the operation, examination, inspection, testing, maintenance or repair of piping that has been placed in service. The Codes do not prevent the User from applying the provisions of the Codes for those purposes.
Engineering requirements of the Codes, while considered necessary and adequate for safe design, generally use a simplified approach. A designer capable of applying a more rigorous analysis shall have the latitude to do so, but must be able to demonstrate the validity of such analysis.
Design Conditions
Design conditions refer to the operating and design temperature and pressure that the piping system will operate at over the course of its design life.

Code Design Temperature & Design Pressure
Code Design Temperature Design Pressure
B31.1 The piping shall be designed for a metal temperature representing the maximum sustained condition expected. The design temperature shall be assumed to be the same as the fluid temperature unless calculations or tests support the use of other data, in which case the design temperature shall not be less than the average of the fluid temperature and the outside wall temperature. The internal design pressure shall be not less than the maximum sustained operating pressure (MSOP) within the piping system including the effects of static head.
B31.3 The design temperature of each component in a piping system is the temperature at which, under the coincident pressure, the greatest thickness or highest component rating is required in accordance with par. 301.2 The design pressure of each component in a piping system shall be not less than the pressure at the most severe condition of coincident internal or external pressure and temperature expected during service, except as provided in par. 302.2.4.
B31.4 The design temperature is the metal temperature expected in normal operation. It is not necessary to vary the design stress for metal temperatures between –20 F and 250 F. The piping component at any point in the piping system shall be designed for an internal design pressure which shall not be less than the maximum steady state operating pressure at that point, or less than the static head pressure at that point with the line in a static condition. The maximum steady state operating pressure shall be the sum of the static head pressure, pressure required to overcome friction losses and any required back pressure.
B31.8 No design temperature. The Code mentions only ambient temperature and ground temperature. (1975) Design pressure is the maximum operating pressure permitted by the Code, as determined by the design procedures applicable to the materials and locations involved.
Z662 For restrained piping, the temperature differential shall be the difference between the maximum flowing fluid temperature and the metal temperature at the time of restraint.
For unrestrained piping, the thermal expansion range to be used in the flexibility analysis shall be the difference between the maximum and minimum operating temperatures. The design pressure at any specific location shall be specified by the designer, shall not be less than the intended maximum operating pressure at any location, and shall include static head, pressure required to overcome friction loss and any required back pressure.

Design of Piping – B31.1
B31.1 essentially limits the pressure design consideration to three items:
Minimum thickness for pressure:
tmin = + A , or
t =
The limit is based on the limit stress being less than the basic allowable stress at temperature. This limit is based on the static yield strength of the material.
Maximum longitudinal stress due to sustained loadings (SL ):
SL  Sh ; stress due to sustained loadings shall be less than the basic allowable stress at temperature. Sustained loadings are those due to pressure, self weight of contents & piping and other sustained loadings particular to the situation. The limit is based on the static yield strength of the material.
Slp=
The computed displacement stress range SE :
SE  SA = f(1.25 Sc + 0.25 Sh). SE stresses arise from the constraint of the thermal strain displacements associated with the expansion of pipe due to temperature. The limit is based on fatigue considerations.
Where the sum of the longitudinal stresses is less than Sh, the difference may be used as an additional thermal expansion allowance.
SE =

B31.1 (cont’d)
The computed displacement stress range SE:
The factor “f” is a stress range reduction factor:
Cycles, N Factor, f

7,000 and less 1.0
> 7,000 to 14,000 0.9
>14,000 to 22,000 0.8
> 22,000 to 45,000 0.7
> 45,000 to 100,000 0.6
> 100,000 to 200,000 0.5
> 200,000 to 700,000 0.4
> 700,000 to 2,000,000 0.3

Design of Piping – B31.3
B31.3 essentially limits the pressure design consideration to three items:
Minimum thickness for pressure:
t = or t = or t = (Lam Equation)
The limit is based on the limit stress being less than the basic allowable stress at temperature. This limit is based on the static yield strength of the material.
Maximum longitudinal stress due to sustained loadings (SL ):
SL  Sh ; stress due to sustained loadings shall be less than the basic allowable stress at temperature. Sustained loadings are those due to pressure, self weight of contents & piping and other sustained loadings particular to the situation. The limit is based on the static yield strength of the material.
The computed displacement stress range SE :
SE  SA = f(1.25 Sc + 0.25 Sh). SE stresses arise from the constraint of the thermal strain displacements associated with the expansion of pipe due to temperature. The limit is based on fatigue considerations.
Where the sum of the longitudinal stresses is less than Sh, the difference may be used as an additional thermal expansion allowance.

Design of Piping – B31.4
B31.4 essentially limits the pressure design consideration to three items:
Minimum thickness for pressure:
t =
The limit is based on the limit stress being less than the basic allowable stress at temperature. This limit is based on the static yield strength of the material.
,
where SMYS is the specified minimum yield strength of the material
Maximum longitudinal stress due to sustained loadings (SL ):
SL  0.75 • SA
where SA =
SL, the stress due to sustained loadings shall be less than 0.75 x the allowable stress range, SA at temperature. Sustained loadings are those due to pressure, self weight of contents & piping and other sustained loadings particular to the situation.
The computed displacement stress range SE :
For restrained lines:
SL =
For unrestrained lines:
SE  SA

Design of Piping – B31.8
B31.8 (1975) essentially limits the pressure design consideration to three items:
Design pressure:
P = F • E • T
F = design factor for construction type (includes a location factor)
E = longitudinal joint factor
T = temperature derating factor
,
where SMYS is the specified minimum yield strength of the material
Total combined stress:
The total of the following shall not exceed S:
a) Combined stress due to expansion
b) Longitudinal pressure stress
c) Longitudinal bending stress due to internal + external loads
Further,
The sum of (b) + (c)  0.75 • S • F • T
The computed displacement stress range SE :
B31.8 applies itself to the above ground piping in discussing expansion and flexibility to a temperature of 450 F.
For these “unrestrained” lines:
SE  0.72 • S

Design of Piping – CSA Z662
Z662 essentially limits the pressure design consideration to three items:
Pressure Design:
P = ; units are metric
F = design factor = 0.8
L = location factor per Table 4.1 (appear to be safety factors)
J = longitudinal joint factor
T = temperature derating factor
S = Specified Minimum Yield Strength (SMYS)
Maximum longitudinal stress due to sustained loadings (SL ):
For restrained lines (below ground):
Sh – SL + SB  0.90 • S • T ; where, SL = (below ground)
* note conservatism with respect to definition of T, Code requires use of temperature at time of restraint
Sh – SL + SB  S • T ; (above ground, freely spanning segments)
The computed displacement stress range SE :
For unrestrained lines (above ground):
SE  0.72 • S • T

Design of Piping
The Design Effort Continuum
Code Code +
Calculation Method
Simple Complex
Answer Quality
Conservative Accurate
Effort
Least Most

Design Loads
The Codes prescribe minimum rules for stress conditions and alert the designer explicitly to some of the loadings likely to act on a system. In addition to the previous listing, most of the Codes specify design rules for:
• Occasional loads such as wind & earthquake
• External pressure
The Codes caution the designer to consider the effect of other loadings and their impact on the stress state of the system:
• Impact events (hydraulic shock, liquid & solid slugging, flashing, transients)
• auto- refrigeration, seasonal temperature variations
• Vibration
• Discharge reactions
• Temperature gradients
• bi-metallic connections
• effects of support & restraint movements
• Cyclic effects
The Codes do not explicitly alert the designer to other loadings which may cause failure in the piping system, including:
• buckling (shell & column)
• Nozzle loadings on attached equipment, such as
• pumps, compressors, engines
• Pressure vessels
• Steam generating equipment
• fired heaters
• Heat exchangers
• Loadings on in-line equipment such as flanges, valves, filters, strainers

4.3 Material Selection
Key Considerations
• Material specification
• Chemical Composition
• Mechanical Properties
• Brittle fracture toughness
• Carbon equivalent
• Inspection
• Repair Welding Procedure
Let’s discuss a couple of these considerations at this time.

Material Selection – Common Specifications for Carbon Steel Systems
Commodity B31.1 B31.3 B31.4

Pipe ASTM A 106 ASTM A 53
API 5L ASTM A 53
API 5L
API 5LU
Pipe – Low Temp ASTM A 333 Gr.6 ASTM A 333 Gr.6 ASTM A 333 Gr.6
Pipe – High Temp ASTM A 106 ASTM A 106 ASTM A 106
Bolting ASTM A 193 B7 ASTM A 193 B7
ASTM A 320 ASTM A 193 B7
ASTM A 320
Nut ASTM A 194 2H ASTM A 194 2H ASTM A 194 2H
Fittings ASTM A 234 WPB ASTM A 234 WPB
Fittings – Low Temp ASTM A 420 WPL6 ASTM A 420 WPL6 ASTM A 420 WPL6
Fittings – High Temp ASTM A 234 WPB
ASTM A 216 WCB ASTM A 234 WPB
ASTM A 216 WCB ASTM A 234 WPB
Flanges ASTM A 105
ASTM A 181
ASME B16.5 ASTM A 105
ASTM A 181
ASME B16.5 ASTM A 105
ASTM A 181
ASME B16.5
Flanges – Low Temp ASTM A 350 LF2
ASTM A 352 LCB ASTM A 350 LF2
ASTM A 352 LCB ASTM A 350 LF2
Flanges – High Temp ASTM A 105
ASTM A 181
ASTM A 216 WCB ASTM A 105
ASTM A 181
ASTM A 216 WCB ASTM A 105
ASTM A 216 WCB
Valves ASTM A 105
ASME B16.34 ASTM A 105
API 600 API 6D
API 600
Valves – Low Temp ASTM A 350 LF2
ASTM A 352 LCB ASTM A 350 LF2
ASTM A 352 LCB
Valves – High Temp ASTM A 216 WCB ASTM A 216 WCB
As can be seen from the Table, material selection can be made from available national standards such as ASTM and API.

Material Selection – Common Specifications for Carbon Steel Systems (cont’d)
Commodity B31.8 CSA Z662

Pipe ASTM A 53
API 5L CSA Z 245.1
Pipe – Low Temp ASTM A 333 Gr.6 CSA Z 245.1
Pipe – High Temp ASTM A 106
Bolting ASTM A 193 B7
ASTM A 354
ASTM A 449 CSA Z 245.
Nut ASTM A 194 2H
Fittings MSS SP-75 CSA Z 245.11
Fittings – Low Temp CSA Z 245.11
Fittings – High Temp
Flanges ASTM A 105
ASTM A 372
MSS SP-44 CSA Z 245.12
Flanges – Low Temp CSA Z 245.12
Flanges – High Temp
Valves ASTM A 105
API 6D
ASME B16.34
ASME B16.38 CSA Z 245.15
Valves – Low Temp CSA Z 245.15
Valves – High Temp

Brittle Fracture
Brittle fracture refers to the often catastrophic failure of materials when subjected to stresses at a lower temperature which the materially would normally be able to withstand at higher temperatures.
A “transition temperature” can be defined at the 13.5, 20, 27 J (10, 15, 20 ft-lb) energy level.
Charpy test results for steel plate obtained from failures of Liberty ships revealed that plate failure never occurred at temperatures greater than the 20-J (15 ft-lb) transition temperature.
This transition temperature varies with the material and is not used as a criterion.
Transition Temperatures
The transition temperature establishes the temperature at which a material “goes brittle”. It’s major shortcoming is it’s imprecision and non-repeatability.
Charpy Testing
Impact testing provides a repeatable means to establish the impact toughness capability of a material under temperature. The more common method is the Charpy drop test measurement which determines the energy absorbing capacity of a standard specimen.
Minimum Required Charpy V Notch Impact Values (B31.3-1999)
Joules
Ft-lbf
Joules
Ft-lbf
(a) Carbon & Low Alloy Steels
Average for 3 specimens
Minimum for 1 specimen
SMTS  65 ksi
18
16
13
10
14
10
10
7
65 ksi  SMTS  75 ksi
20
16
15
12
18
14
13
10
75 ksi  SMTS  95 ksi
27
20
20
15
…
…
…
…
Lateral Expansion
96 ksi  SMTS
Minimum for 3 specimen
0.015 in
(b) Steels in P-Nos. 6, 7, 8
Minimum for 3 specimen
0.015 in

Impact Testing Exemption Temperatures – B31.3
Refer to Figure 323.2.2 in the Code.
This figure provides a correlation between material group, reference thickness and exemption temperature.
Material group is defined in Table A-1. For example, SA 106 B is given a Min Temp rating of “B”. Entering Figure 323.2.2A, this material is impact testing exempt up to a thickness of 0.5” down to a minimum temperature of –20 F. Curve B rises to a minimum temperature of 75 F for a material thickness of 3”.
Minimum Required Charpy V Notch Impact Values (CSA Z 662-1999)
Table 5.1 provides a toughness category matrix. This matrix is somewhat cumbersome to apply as it requires cross referencing to CSA Z 245 and makes use of toughness categories I, II & III. It is not intuitively obvious what these categories represent.
This Table also inherently provides for a risk based approach by bringing in service fluid, test fluid and pipe design operating stress parameters.
Case Study:
On the next page, the Material Requisition Form has certain boxes marked off to indicate inspection needs. Not all marked boxes are appropriate! Do you know which?

4.4 Fabricated Tees & Area Reinforcement
Paragraph 304.3.2 of the Code provides explicit direction on the proper design of branch connections.
In summary, this paragraph states that branch connections must be made using fittings that are inherently reinforced such those listed in Table 326.1 or fabricated and sufficiently reinforced using design criteria based on area reinforcement principles. This presumes that a branch connection opening weakens the pipe wall and requires reinforcement by replacement of the removed area to the extent it is in excess to that required for pressure containment. The Code is fully detailed in the necessary calculations. These calculations can be very tedious, time consuming prone to error if done by hand. A computer program is advised for productivity; a spreadsheet based program is more than adequate.
No calculation is required for branch connections made by welding a threaded or socket weld coupling or half coupling if the branch does not exceed 2 NPS nor ¼ the nominal size of the run line. The coupling cannot be rated for less than 2000 CWP.
Multiple openings are addressed by the Code.
The area reinforcement rule can be at times, be overly conservative; in other instances, this approach can be deficient even within the limits of applicability defined in the Code. Code users must be aware of the limits of applicability of the Code rules which are given in paragraph 304.3.1. Jurisdictions such as the Alberta Boiler Safety Association (ABSA) have defined additional limits. WRC publications also have guidance on this issue.
4.5 Flexibility Analysis
Stress Analysis Criteria:
This stress analysis criteria establishes the procedure, lists critical lines and piping stress/design liaison flow sheet to be followed.
Lines to be analyzed:
• all lines attached to pumps, compressors, turbines and other rotating equipment
• all lines attached to reciprocating compressors
• all pressure relief valve piping
• all category m piping
• all lines on racks (with discretion)
• all lines which the piping designer is uncomfortable with
• all vacuum lines
• all jacketed piping
• all tie-ins to existing piping
• all non metallic piping
• all steam out, decoking and regeneration lines
• all lines 16” and larger
• all lines 6” and larger over 500 F
• all lines over 750 F
• all lines specifically requested by the stress department.
• all lines specifically requested by the client.
The above list is actually very conservative and discretion is required in applying these rules to ensure economical approach to piping analysis.
Paragraph 319.4.1 lists the conditions under which flexibility analysis may be waived.
If formal analysis is deemed necessary, follow the requirements of paragraph 319.4.2.
The other Codes will have similar provisions.

Nomenclature-C5

CV = Valve Flow Coefficient.
DB = Inside Diameter of Valve Body Outlet = Inches. See Table 4.
DP = Inside Diameter of Outlet Pipe = Inches.
FF =Liquid Critical Pressure Ratio Factor:
Fk = Ratio of specific Heats Factor.
FL = Liquid Pressure Recovery Factor.
FL Required = The FL factor to avoid Choked Flow.
FL Rated = The FL factor rated for individual Trim Styles. See Table 3.
FP = Piping Geometry Factor, If the valve size and pipe size are equal us 1.0, if not refer to ISA S75.01 section 4.3.
FR = Reynolds Number Factor, Normally = 1.0 but varies with very slow fluid velocities or very viscous fluids. Refer to ISA S75.01 section 4.4.
Gf = Specific Gravity of a Liquid relative to water at 60 °F.
Gg= Specific Gravity of a Vapor relative to air at 60 °F 14.7 PSIA.
k = Ratio of specific Heats. See Table 2.
KC = Cavitation Index. See Table 3.
M = Molecular Weight. See Table 2.
P1 = Valve Inlet Pressure (psia).
P2 = Valve Outlet Pressure (psia).
PC =Fluid’s Critical Pressure (psia) See Table 2.
PV =Fluid’s Vapor Pressure (psia).
Q = Volumetric Flow Rate: Liquids(GPM) Vapor(SCFM)
T = Fluid Temperature in Degrees Rankine. °R = °F + 460. V2=Specific Volume of vapor, either gas or steam = Ft.3 / Lb.
W = Mass Flow Rate = Lb./Hr.
x = Pressure Drop Ratio.
xT = Maximum Pressure Drop Ratio, varies with Trim Style. See Table 3.
Y = Fluid Expansion Factor for vapor flow.
Z = Compressibility Factor for vapor flow. Usually 1.0. Refer ISA Handbook of Control Valves, 2nd Edition, pages 488-490.
λ = Specific Weight = Lb./Ft.3

TRIM RANGEABILITY-C4

Globe Valves.
Equal Percent – All Equal %, Full Port Trim styles
50:1
Linear Flow and Reduced Port Trim styles
30:1
Rotary Valves
Eccentric Plug Segmented Ball – Modified Linear
100:1
Concentric Plug, Segmented V-Ball – Equal %
200:1

THE SIZING PROCESS-C4

The first sizing step is to determine the required CV value for the application. Next determine if there are unusual conditions that may affect valve selection such as cavitation, flashing, high flow velocities or high flow noise. The valve sizing process will determine the proper valve size, valve trim size , valve trim style and actuator size. Warren’s Valve Sizing Program will accurately calculate the CV, flow velocity and flow noise. The program will also show messages when unusual conditions occur such as cavitation, flashing, high velocity or high noise. The results from Warren’s Valve Sizing Program are only one element of the valve selection process. Knowledge and judgment are also required. This overview will give the user some of the sizing basics.
The liquid, gas and steam CV calculation methods, in this manual, are in accordance with ISA S75.01 and the gas and steam flow noise calculations are in accordance with ISA S75.17. These two ISA Standards are in agreement with IEC-534. These standards have worldwide acceptance as the state of the art in CV and Flow Noise determination.
Operating Conditions
The most important part of Valve Sizing is obtaining the correct flowing conditions. If they are incorrect or incomplete, the sizing process will be faulty. There are two common problems. First is having a very conservative condition that overstates the CV and provide a valve less than ½ open at maximum required flow. The second is stating only the maximum flow condition that has minimum pressure drops and not stating the minimum flow conditions with high-pressure drops that often induce cavitation or have very high rangeability requirements.
5
Fluid Properties
Table 2 lists many fluid properties needed for valve sizing. These fluid properties are in Warren’s Valve Sizing Program’s database and do not need manual entry.
Rangeability: Rangeability is the ratio of maximum to minimum controllable CV. This is also sometimes called CV Ratio or Turndown. The maximum flow for Warren Controls’ valves is at maximum travel. The minimum controllable CV is where the Flow Characteristic (CV vs. Travel) initially deviates or where the valve trim cannot maintain a consistent flow rate. This is partially a function actuator stiffness as well as valve “stiction”. The Trim’s rangeability is not always the useable range as seat erosion may be a governing factor with respect to erosive fluids and high drops in the near-closed position. A valve with a significant pressure drop should not be used to throttle near the seat for extended periods of time.
The rangeability values, listed in Table 1, apply to the rated CV, not the required CV. For example, an application may require a maximum CV of 170. A 4” Equal Percentage Trim may be selected that has a maximum CV of 195. Using the rangeability value for this trim, the minimum CV is 195/100=19.5, not 170/100=17.
Valve applications subject to pressures from nature, such as gas and oil production, are usually sized for full flow at about 80% open as the pressure may be unknown when the valve is sized and the pressure may vary with time.
Those valve applications with fairly consistent inlet pressures, such as process control and power applications are usually sized at full travel. The valve specifier usually includes a fair margin of safety in the stated sizing conditions. If the valve supplier includes additional safety, such as full flow at 80% open, the valve may be at full flow at less than ½ travel giving poor performance.

VALVE FLOW TERMINOLOGY-C2

CV: The Flow Coefficient, CV, is a dimensionless value that relates to a valve’s flow capacity. Its most basic form is CQPV=Δ where Q=Flow rate and ΔP=pressure drop across the valve. See pages 6, 7 & 9 for the equations for liquid, gas, steam and two phase flow. The CV value increases if the flow rate increases or if the ΔP decreases. A sizing application will have a Required CV while a valve will have a Rated CV. The valve’s rated CV must equal or exceed the required CV.
FL: The FL, Liquid Pressure Recovery Coefficient, is a dimensionless constant used to calculate the pressure drop when the valve’s liquid flow is choked. The FL is the square root of the ratio of valve pressure drop to the pressure drop from the inlet pressure to the pressure of the vena contracta. See page 7 for the FL equation. The FL factor is an indication of the valve’s vena contracta pressure relative to the outlet pressure. If the FL were 1.0, the vena contracta pressure would be the same as the valve’s outlet pressure and there would be no pressure recovery. As the FL value becomes smaller the vena contracta pressure becomes increasingly lower than the valve’s outlet pressure and the valve is more likely to cavitate. A valve’s Rated FL varies with the valve and trim style, it may vary from .99 for a special multiple stage trim to .30 for a ball valve.
Rated FL: The Rated FL is the actual FL value for a particular valve and trim style.
Required FL: The Required FL is the FL value calculated for a particular service condition. It indicates the required FL needed to avoid choked flow. If the Rated FL is less than the Required FL, the liquid flow will be choked with cavitation.
Vena Contracta: The vena contracta is where the jet of flowing fluid is the smallest immediately downstream of the trim’s throttle point. At the vena contracta, the fluid’s velocity is the highest and the fluid’s pressure is the lowest.
3
Vapor Pressure: A fluid’s vapor pressure is the pressure where the fluid will change from a liquid to a vapor. The liquid will change to a vapor below the vapor pressure and a vapor will
4
change to a liquid above the vapor pressure. The vapor pressure increases as the temperature increases.
Choked Flow: Liquid flow will become choked when the trim’s vena contracta is filled with vapor from cavitation or flashing. Vapor flow also will become choked when the flow velocity at the vena contracta reaches sonic. A choked flow rate is limited; a further decrease of the outlet pressure does not increase flow. Choked flow is also called critical flow.
Cavitation: Cavitation is a two stage phenomena with liquid flow. The first stage is the formation of vapor bubbles in the liquid as the fluid passes through the trim and the pressure is reduced below the fluid’s vapor pressure. The second stage is the collapse of the vapor bubbles as the fluid passes the vena contracta and the pressure recovers and increases above the vapor pressure. The collapsing bubbles are very destructive when they contact metal parts and the bubble collapse may produce high noise levels.
Flashing: Flashing is similar to cavitation except the vapor bubbles do not collapse, as the downstream pressure remains less than the vapor pressure. The flow will remain a mixture of vapor and liquid.
Laminar Flow: Most fluid flow is turbulent. However, when the liquid flow velocity is very slow or the fluid is very viscous or both, the flow may become laminar. When the flow becomes laminar, the required CV is larger than for turbulent flow with similar conditions. The ISA sizing formulas adjust the CV when laminar flow exists.

Introduction To Control Valves-C1

A Control Valve performs a special task, controlling the flow of fluids so a process variable such as fluid pressure, fluid level or temperature can be controlled. In addition to controlling the flow, a control valve may be used to shut off flow. A control valve may be defined as a valve with a powered actuator that responds to an external signal. The signal usually comes from a controller. The controller and valve together form a basic control loop. The control valve is seldom full open or closed but in an intermediate position controlling the flow of fluid through the valve. In this dynamic service condition, the valve must withstand the erosive effects of the flowing fluid while maintaining an accurate position to maintain the process variable.
A Control Valve will perform these tasks satisfactorily if it is sized correctly for the flowing and shut-off conditions. The valve sizing process determines the required CV, the required FL, Flow Velocities, Flow Noise and the appropriate Actuator Size

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COMMON REQUIREMENTS -PIPING DESIGN, LAYOUT AND STRESS ANALYSIS

COMMON REQUIREMENTS
PIPING DESIGN, LAYOUT AND STRESS ANALYSIS

(For reference only)

ASME B31.3 Chemical Plant and Petroleum Refinery Piping.
ISO 5167 Measurement of fluid flow.
4 DEFINITIONS AND ABBREVIATIONS
4.1 Definitions
Normative references Shall mean normative in the application of NORSOK standards.
Informative references Shall mean informative in the application of NORSOK standards.
Shall Shall is an absolute requirement which shall be followed strictly in order
to conform with the standard.
Should Should is a recommendation. Alternative solutions having the same
functionality and quality are acceptable.
May May indicates a course of action that is permissible within the limits of
the standard (a permission).
Can Can requirements are conditional and indicates a possibility open to the
user of the standard.
Insulation Valve An insulation valve is defined as a valve that is used to shut off a piece of
equipment or system for maintenance purpose only.
4.2 Abbreviations
The following abbreviations are given for terms used in this specification:
ANSI American National Standards Institute
API American Petroleum Institute
ASME The American Society of Mechanical Engineers
BS British Standard
D Diameter
DIN Deutsches Institut für Normung (German standard)
DNV Det Norske Veritas
EDS Element Data Sheet
ISO International Organization for Standardization
MSS Manufacturers Standardization Society (USA)
NEMA National Electrical Manufacturers Association (USA)
NGS Nordic Group for Steel Regulations.
NPS Nominal Pipe Size
NPSH Net Positive Suction Head
NS Norwegian Standard
5 DESIGN AND LAYOUT
5.1 General
Design conditions shall be in accordance with the ASME B31.3. except where the requirements of
this standard are more stringent.
All piping shall be routed so as to provide a simple, neat and economical layout, allowing for easy
support and adequate flexibility.

5.3 Safety and work environment
Ergonomic consideration shall be taken in design regarding:
• Tools, valves and control devices, including emergency controls devices shall be accessable.
• Provision for cleaning, maintenance and repair shall be taken into consideration.
Requirements related to safety and working environment shall conform with S-DP-002.
No potential source of hazard (release of hydrocarbons), e.g. flange joints, shall be located outside
hazardous areas as defined in the Area Classification drawings or specification.
Where applicable, provision shall be made to protect piping and equipment from falling objects.
5.4 Clearance and accessibility
All piping shall be arranged so as to provide specified headroom and clearances for technical safety,
easy operation, inspection, maintenance and dismantling.
Particular attention shall be paid to clearances required for the removal of pump, compressor and
turbine casings and shafts, pump and fan drivers, exchanger bundles, compressor and engine
pistons. Piping shall be kept clear of manholes, access openings, inspection points, hatches, davits,
overhead cranes, runway beams, clearance areas for instrument removal, tower dropout areas,
access ways and emergency escape routes.
A vertical clearance of 40mm is recommended between bottom of skid and deck/floor to facilitate
cleaning/maintenance.
Pipe, fittings, valve controls, access panels or other equipment shall not extend into escape areas.
5.5 Pipe routing
5.5.1 Arrangement
Piping shall be arranged on horizontal racks at specific elevations. Transverse pipework shall be run
at a different elevation than longitudinal pipework. When changing direction (from longitudinal to
transverse or vice versa) the piping shall change elevation, but care shall be taken to avoid pockets.
No piping shall be located inside instrument, electrical or telecommunication control/switchgear
rooms, except fire fighting piping serving these rooms. Bridge piping shall be designed with
expansion loops capable of handling relative movement of platforms in design storm conditions.
5.5.2 Grouping
Cold and hot piping should be grouped separately with hot, non insulated, lines at a higher
elevation than cold lines. Uninsulated lines with possibility for ice build-up, shall not be run above
walk ways.
When expansion loops are required, lines should be grouped together and located on the outside of
the rack.

5.5.3 Location
Locating small pipes between large pipes shall be avoided especially when the large lines are hot.
Heaviest lines should be located furthest from centre of the rack.
5.5.4 Sloping pipes
Sloping pipes, such as flare headers and drain lines, should be located together and the routing
established at an early stage in the design period to prevent difficulties which may occur if other
process and utility lines are routed first.
5.5.5 Utility headers
Utility headers for water, steam, air, etc. shall be arranged on the top of multi-tiered pipe racks.
5.6 Valves
5.6.1 Accessibility and installation
All valves requiring operation during normal or emergency conditions shall be accessible from a
deck or platform.
Isolation valves shall preferably be accessible from deck or platform. However, if this is not
possible, valves shall be positioned such that access from temporary facilities is obtained. Fire
water ring main isolation valves shall always be accessible from deck or platform.
Pressure relief devices (relief valves, rupture discs) shall be accessible and installed for easy
removal from deck or permanent platform. Relief valves shall be installed with the stem in the
vertical position. Other valves may be tilted, as long as the stem is above horizontal position.
When ESD valves are installed as isolation valves, they shall be located as close as possible to the
fire/blast partition.
5.6.2 Check valves
Check valves may be installed in vertical lines providing the flow is upwards, with the exception of
some type of lift checks. Draining of the downstream side shall be provided.
5.6.3 Control valves
Control valves shall be located as near as possible to the relevant equipment to which they apply
and where possible along stanchions, columns, bulk heads or tower skirts. Suitable areas where
control valves may also be located are alongside walkways, working areas and other aisles
providing no obstructions such as valve stems extended into the walkways occurs.
Control valves operated by a local controller shall be located within the visual range of the
controller to enable the operation of the valve to be observed while adjustments are made on the
controller.
When an increase in line size is required downstream, the control valve shall be located as close to
the reducer as possible.
Where control valves are less than line size, the reducers shall be placed adjacent to the valve.
Spools or reducers between flanged block and control valves shall be made long enough to permit

bolt removal. In screwed lines with a screwed control valve, unions shall be installed on each side
of the control valve.
Where high pressure drop conditions exists across control valves, sonic harmonics together with
extreme noise levels can be expected. Piping subjected to these conditions must be carefully
evaluated and designed to ensure that its size and configuration downstream of the valve prevents
transmission of excessive vibration and noise.
5.6.4 Relief valves.
For relief valves, see clause 5.9.4.
5.7 Vents, drains and sample connections
5.7.1 General
Vents and drains exclusively used for hydrostatic pressure testing shall be provided if those showed
on the P&ID’s are not sufficient/suitable.
5.7.2 Vents and drains for operational use

Sloped drain lines shall be run to the nearest deck drain, avoiding walking areas. Open drains shall
be valved and located such that discharge may be observed. Open pipe ends shall extend well into
tundishes to avoid spillage.
Supports from any fixed structure components shall be avoided.
5.7.3 Vents and drains for hydrostatic pressure testing

5.7.4 Sample points

Sample points for gas shall be connected to the flare system to ensure satisfactory flushing in
advance of samples being taken. The sample connection shall be located as close as possible to the
separator/scrubber outlet, and preferably directly after the first elbow on vertical line.
Points for oil samples shall be located on vertical part of pipe. Sample station to be designed to
minimise oil spillage.
5.7.5 Combined valves
Use of “combined” valves shall be evaluated instead of a double block and single blinded bleed
valve arrangement. Evaluation shall include space requirement, risks for vibration, leak risk and life
cycle cost.

5.8 Equipment piping
5.8.1 General
Piping connected to equipment shall be designed so that any forces or moments caused by thermal
expansion, dead and operating loads, do not exceed the limits specified by R-CR-001 or the
manufacturer.
Piping configurations at equipment shall be designed and supported so that equipment can be
dismantled or removed without adding temporary supports or dismantling valves and piping other
than removing spool pieces or reducers adjacent to equipment. Clearances shall permit installing
blind flanges or reversible spades on block valves on hazardous fluids or high pressure lines. Break
out spools shall be as short as possible.
In the design of piping for rotating equipment provision shall be made for sufficient flexibility
without the use of flexible couplings and expansion bellows. Cold springing of piping at rotating
equipment shall not be used.
Where deck level pipe supports are required at pumps, compressors or turbines, they shall be
supported on integral extensions of the equipment support structure, and not be anchored to
equipment baseplate. This requirement shall apply to resilient as well as fixed supports, guides and
anchors.
Provision shall be made for the isolation of equipment with blinds or the removal of spool pieces
for pressure testing and maintenance.
Suitable supports and anchors shall be provided so that excessive weight and thermal stresses are
not imposed on the casing of rotating equipment.
Piping shall be balanced through the use of spring supports and other supports to minimise the load
exerted on the main compressor gas nozzles. The same is applicable for nozzles of large centrifugal
pumps.
5.8.2 Pumps
Suction lines shall be as short as possible and designed without pockets where vapor or gas can
collect. Where possible the piping shall be self-venting to the suction source. The suction line shall
be checked to ensure that the NPSH (Net Positive Suction Head) fulfils relevant pump
requirements.
Any reduction in line size at the pump suction shall be made with concentric reducers. Reducers in
horizontal runs shall be eccentric with flat side up. Concentric reducers shall be used in vertical
piping.
To minimise the unbalancing effect of liquid flow entering double suction centrifugal pumps,
vertical elbows are preferred adjacent to suction flanges. If this requirement can not be met, the
elbows in piping shall be at least 5 pipe diameters upstream of the pump suction flanges with the
following qualifications:
• Where no reducer is employed between the pump flange and the elbow, a straight run at least 5
pipe diameters long shall be provided.

• Where a reducer is located between the pump flange and the elbow, a straight run of at least 2
pipe diameters long, based on the larger pipe diameter, shall be provided. A reducer next to the
pump flange is considered to be equivalent to 3 large diameters.
Valves in pump discharge lines shall be located as close to the pump nozzles as possible.
All valves adjacent to pumps shall be accessible for hand operation without the use of chains or
extension-stems. Hand-wheels and stems shall not interfere with the operational passageways or the
removal of pumps.
Suction piping shall be designed to enable strainers to be easily installed or removed without
springing the pipe.
5.8.3 Compressors
5.8.3.1 Gas compressors
In order to get a neat layout, top and bottom entry compressors should be evaluated.
All gas compressors suction piping between the knock-out vessel and the compressor shall be
arranged to prevent the possibility of trapping or collecting liquid.
Piping shall slope continuously downwards from the suction cooler to the knock-out vessel
connection. Piping shall be routed so that any condensate drains back from the compressor suction
to the knock-out vessel.
All compressors shall be provided with a temporary strainer in the suction line unless a permanent
strainer is called for on the P&ID’s. The strainer shall be located as close to the compressor as
possible, unless the P&ID’s indicate otherwise.
Compressor discharge lines shall be equipped with check valves installed as close as possible to the
compressor discharge nozzle.
5.8.3.2 Air compressors
For parallel compressor trains, with a parallel layout within the same area, utility pipe nozzles for
two trains may be mirror imaged in order to get easy access to common maintenance areas.
Suction line silencers, where required, shall be located as close to the compressor suction
connection as possible according to the compressor manufacturer’s instructions.
5.8.4 Turbines
Fuel gas piping for gas turbines shall be of all welded construction with the exception of the turbine
connection and valves which may be flanged inside turbine enclosure. No threaded connections
shall be used in the fuel gas system. Turbine fuel control and fuel filters shall be easy accessible.
All inlet and exhaust piping/ducting for turbines shall be adequately supported to the approval of
the equipment manufacturer. Exhausts shall be routed into a non hazardous area and shall not prove
hazardous to personnel or foul air inlet.

5.8.5 Diesel engine
Pipework shall not be run directly over diesel engines, exhaust piping or any position where leaking
fuel oil can impinge onto hot parts. The pipework should not be supported by hanger type supports.
The fuel oil header shall not be dead ended, to simplify cleaning/purging.
Where a positive static head is required from the day tank, the minimum operating level shall be
300mm above inlet of the fuel injection pump.
The drain line from the day tank shall be positioned so that the drain line outlet into the main drain
is visible from the drain valve position.
5.8.6 Vessels and towers
Where possible, block valves shall be located directly on the vessel nozzles.
Check valves, shall be installed on the block valve at the vessel nozzle where not in conflict with
clause 5.6.2.
5.8.7 Heat transfer equipment
Valves shall not be located directly on top of channel nozzles, to avoid obstructing the removal of
channel ends. Spool pieces shall be provided to facilitate the tube pulling and maintenance.
Piping shall be arranged to permit cooling fluid to remain in all units on loss of cooling fluid
supply.
Thermowells for inlet and outlet temperatures for each fluid service shall be provided and shall be
located in adjacent piping when the exchanger nozzles will not permit a 90mm immersion for the
thermowell.
5.8.8 Launcher and receiver traps
Consideration shall be given to mechanical handling facilities for pigs and line logging devices. The
facilities can include the following:
• Overhead hoists or access for fork lift truck.
• Winching points for logging device withdrawal.
• Storage and inflation facilities for pigs and logging devices.
• Cradle for inserting the pig.
The pig trap opening closure shall face the sea. Vertical traps shall be placed on the outside area on
the platform and shall be open to air. Provision shall be made within the closure for hydraulic
connections to allow the operation of a hydraulic equipment, such as maintenance pigs and
hydroplugs.
Elevation of traps shall be kept to a minimum. Where a sight glas is specified on the drain line,
sufficient space must be provided for observation of flow.
The traps shall have a pressure indicator positioned so that it will be visible to personnel operating
the trap closures.

Piping between risers and launchers and/or receivers shall have a bend radius in accordance with
specifications from intelligent pig supplier.
The junction between the production line and the inlet/outlet to the launcher/receiver shall be
designed to prevent pigs from entering the production line.
The launcher/receiver shall be sloped towards the trap closure, and a spillage retention tray
provided with drain, shall be installed.
A minimum of 2m straight run should be arranged between the sphere or bar tee and the pipeline
ESD valve in order to accommodate for installation of an inflatable welding sphere. This is to
provide double isolation against the pipeline if repair of the isolation valves to the pig trap or
isolation valves to the process area should be necessary. This is applicable to piping where non
flexible risers are used.
5.8.9 Wellhead area piping & valves
In the design of piping manifolds, consideration shall be given to the use of extruded headers.
On fabricated manifolds the terminus of the manifold runs shall be blind flanged or hubed to
simplify cleaning and inspection.
Production manifolds shall be designed for solid (scale) removal where this may be a problem.
Consideration shall be given to any changes of direction in the flowlines where the product contains
particles at high velocities which will erode the fittings, e.g. target, tees, 3xD bends.
An erosion pipe spool approximately 2m in length shall be considered for installation immediately
downstream of each choke valve for corrosion/erosion monitoring. If the spool length between the
choke valve and the shut off valve on the manifold is sufficiently short, it can be considered as an
erosion spool.
5.9 Additional requirements related to piping systems
5.9.1 Air piping
Air piping shall be self draining with provision at all low points for the collection of condensate.
Air traps shall be provided with isolation valves, balance lines and drains to local collection points.
Instrument air headers and manifolds shall not be dead ended but supplied with blind flanges for
cleaning and maintenance.
All branches and take-offs shall be from the top of the headers.
5.9.2 Steam piping
Steam piping shall be run to prevent pockets. Condensate shall be collected at low points by using a
standard steam trapping system.
Drain points shall be from the bottom of the header and steam take-offs from the top.

5.9.3 Utility stations
Utility stations shall be provided as required for air, water, steam/hot water and nitrogen. Each
station shall be numbered and located in the general working areas at deck level. Freshwater,
seawater and plant air systems shall be equipped with hosereels. Nitrogen stations shall not be
located inside enclosed areas. Nitrogen hoses shall be installed if required . Different types of couplings shall be used for air and nitrogen.
5.9.4 Pressure relief piping
Piping to pressure relief valve inlet shall be as short as possible.
When relief valves discharge to atmosphere, the elevation at the top of the discharge line shall
typically be 3000mm above all adjacent equipment. This is to keep adjacent equipment outside
plume area. Discharge tail pipes shall have a drain hole at the low point of the line.
Relief valves discharging to a flare system shall be installed so as to prevent liquid being trapped on
the outlet side of the valve. All relief lines and headers shall be designed to eliminate pockets, but if
a relief valve must be located at a lower elevation than the header, an automatically operated drain
valve shall be installed at the valve outlet and piped to a collecting vessel or closed drain.
Relief valve headers shall slope towards the knock-out drum, taking into account anticipated deck
deflection during operation. Pockets are to be avoided, but where a pocket is unavoidable, some
approved means of continuous draining for the header shall be incorporated.
Unless specifically noted on the P&ID all branch connections on relief and blowdown systems shall
be at 90°C to the pipe run. Should there be a special requirement for a particular branch to enter a
header 45°C, this shall be highlighted by process engineers on the P&ID.
5.9.5 Open drain systems
Drains shall have slope as specified on the P&ID’s. Open drain branch connections shall all be
45°C. Rodding points shall preferably be through drain boxes and change of direction shall be
evaluated against flushing requirements, where the total change of direction is greater than 135°C.
5.9.6 Pneumatic conveying
Pneumatic conveying piping shall be designed according to and approved by the pneumatic
conveying system manufacturer.
5.9.7 Fire/explosion protection

5.9.8 Firewater distribution system
The layout of the firewater distribution system shall be carefully designed with respect to hydraulic
pressure drop.
Deluge nozzles branch off shall be located away from the bottom of the header to avoid plugging of
nozzles.
Location of nozzles shall be as specified by the safety discipline. Necessary deviations to avoid
obstructions etc. shall be approved by the safety discipline.

Dead end headers shall be avoided.
5.9.9 Lube, seal and hydraulic oil systems
Lube, seal and hydraulic oil systems shall have flanges and blind flanges on header ends for
pickling and hot oil flushing.
5.10 Fittings
5.10.1 General
All piping fittings shall conform to the relevant code or standards listed in clause 3.

Short radius elbows and reducing elbows shall not be used.
Expansion bellows and flexible couplings shall not be used, without written approval.
Where entrained sand is expected within the fluid flow, target tees shall be considered in place of
elbows for changes of direction to minimise the effect of erosion, provided the total pressure for the
system is acceptable.
Where line clean out facilities are required on headers, a blind flange shall be provided to close the
end. Where no clean out is required and no future extention is expected, the line shall be closed
with a welding cap.
5.10.2 Line blinds
Location of line blinds are indicated on P&ID’s.
The provision for blinding shall consist of a pair of flanges, one of which may be a flanged valve
(except wafer type valves) or equipment nozzle.

Provision shall be made for using mechanical means of lifting either by davits or block and tackle
lifting points, where the weight exceeds tabulated. Wherever possible, blind/spacer shall be located
in horizontal runs. Values are given in S-DP-002.
Where line blinds are installed, the piping shall be designed to allow enough flexibility to spring the
line by means of either jack screws or other jacking arrangements. On ring joint flanges the
flexibility allowance shall be sufficient to allow for the removal of the ring without overstressing
the piping.
If required, a break out spool shall be provided for dismantling.
5.10.3 Insulation spools/sets
Galvanic corrosion shall be prevented. Rubber or plastic lined insulation spools can be used.

5.10.4 Strainers
The P&ID’s will indicate whether a permanent or a temporary strainer shall be used to protect
equipment. The mesh size of the strainer shall have a free area of 250% of the cross-sectional flow
area of the line in which it is installed. Easy removal and cleaning of filters shall be possible.
The strainer housing shall conform to the appropriate material classification for the service in which
it is installed. The housing of permanent strainers shall have either flanged ends or butt-weld ends.
Butt-weld ends are preferred due to weight saving, especially for the larger sizes.
The installation of permanent strainers shall permit cleaning without dismantling the strainer
housing or piping.
Break out spool to be installed in conjunction with temporary strainers.
5.11 Hook-up piping
Offshore hook-up piping shall be kept to a minimum.
5.12 Instrumentation
5.12.1 Materials and rating
Materials and rating for instrument connections shall conform to the relevant material rating
classification of the parent line.
5.12.2 Accessibility, location and orientation
Special attention shall be given, with respect to accessibility, location and orientation of valves,
vents and drains as well as block and by pass valves.
Control cabinets (accumulator packages) shall be located as close as practically possible to the
respective valves.
Location of flow orifices shall be in accordance with ISO 5167 latest edition. For liquid services,
flow orifices shall not be put on vertical pipe runs.

For instrument items the following considerations shall be made during design for operator access
requirements.
Table 1 Location and access for instrument items
Type of instrument Access required Access via Access via
for operations fixed ladder fixed platform
Thermocouples No
Test thermowells Yes Yes Acc.
Local temperature indicator No 1) No No
Pressure gauge No 1) No No
Level gauges Yes Yes Acc.
Temperature transmitter and switches Yes Yes Acc.
(indicating)
Temperature transmitter and switches Yes Yes Acc.
(blind)
Other transmitters and switches Yes Yes Acc.
(blind)
Other transmitters and switches Yes Yes Acc.
(indicating)
Recorders and controllers Yes No Yes
Control valves and other final control Yes No Yes
elements, PSV’s
All flow primary elements Yes No Yes
(orifice plates, ventures pitot tubes)
Note
1. Must be able to read from platform or fixed ladder.
Yes Required minimum
Acc. Acceptable but not mandatory
6 STRESS ANALYSIS
6.1 General
Stress analysis shall be performed according to ASME B313 para. 319.4.
6.2 Selection criteria for lines subject to comprehensive stress analysis
As a general guidance, a line shall be subject to comprehensive stress analysis if it falls into any of
the following categories:
• All lines at design temperature above 180°C.
• 4″ NPS and larger at design temperature above 130°C.
• 16″ NPS and larger at design temperature above 105°C.
• All lines which have a design temperature below -30°C provided that the difference between the
maximum and minimum design temperature is above:
-190°C for all piping
-140°C for piping 4″ NPS and larger
-115°C for piping 16″ NPS and larger

• Note: These temperatures above are based on a design temperature 30°C above maximum
operating temperature. Where this is not the case, 30°C must be subtracted from values above.
• Lines 3″ NPS and larger with wall thickness in excess of 10% of outside diameter. Thin walled
piping of 20″ NPS and larger with wall thickness less than 1% of the outside diameter.
• All lines 3″ NPS and larger connected to sensitive equipment such as rotating equipment.
However, lubrication oil lines, cooling medium lines etc. for such equipment shall not be
selected due to this item.
• All piping subject to vibration due to internal forces such as flow pulsation and/or slugging or
external mechanical forces.
• All relief lines connected to pressure relief valves and rupture discs.
• All blowdown lines 2″ NPS and larger excluding drains.
• All piping along the derrick and the flare tower.
• All lines above 3″ NPS likely to be affected by movement of connecting equipment or by
structural deflection.
• All lines 3″ NPS and larger subject to steam out.
• Long vertical lines (typical 20 meter and higher).
• Other lines as requested by the stress engineer.
• All production and injection manifolds with connecting piping.
• Lines subject to external movements, such as abnormal platform deflections, bridge movements,
platform settlements etc.
6.3 Design temperature
The design temperature for the selection of lines subject to stress analysis shall be as stated on the
P&ID’s/line lists.
Calculation of expansion stress shall be based on the algebraic difference between the minimum
and maximum design temperature. The maximum design temperature shall not be lower than the
maximum ambient temperature.
Reaction forces on supports and connected equipment may be based on the maximum algebraic
difference between the installation temperature and the maximum or minimum design temperature.
For uninsulated lines subject to heat sun radiation, 60°C shall be used in the calculations, where this
is higher than the relevant maximum design temperature.
6.4 Environmental temperature
The minimum/maximum environmental temperature shall be as specified by the project, unless
otherwise specified, the following environmental temperatures shall apply:
• Installation temperature: 4°C
• Min. ambient temperature: -7°C
• Max. ambient temperature: 22°C
6.5 Design pressure
The design pressure for the piping system shall be as stated on the P&ID’s/line lists. Where internal
pressure below atmospheric pressure can exist, full vacuum shall be assumed for stress calculations.

6.6 Vibration
The effects of vibration imposed on piping systems shall be evaluated and vibration sources which
can be realistically determined shall be accounted for. This also includes acoustic induced vibration.
6.7 Loads
Environmental loads such as snow, ice and wind acting on exposed piping shall be evaluated. When
affecting the integrity of the piping system, the imposed deflections or movements from the main
structure shall be accounted for.
Process conditions which may result in impulse loadings, such as surge, slugging, water
hammering, reaction forces from safety valves and two phase flow, shall be included in the
calculations.
The effect of blast loads shall be evaluated, for piping which is required to maintain the integrity in
an explosion event.
6.8 Bending moment on valves, flanges and mechanical joints
In order to minimise the risk of leakage at valves, flanges and mechanical joints, the bending
moment on these shall be evaluated. Special attention shall be made to bolt tensioning values to
ensure that sufficient gasket surface pressure is maintained at all conditions.
6.9 Flexible joints
Expansion bellows, sliding joints, ball joint and similar flexible joints will generally not be
permitted.
6.10 Cold springing
Cold springing of piping will generally not be permitted. Where all other methods have been
explored and found unacceptable, cold springing may be applied provided the location of
application and the installation procedure gives a reasonable assurance that the cold springing
requirements have been achieved during installation. Credit for cold springing to reduce reaction
forces can only be given if it can be shown that stress relaxation or yielding do not occur in the
piping system.
6.11 Spring supports
In general, the use of spring supports shall be kept to a minimum by careful consideration of
support location and alternative pipe routing.
6.12 Loads from piping systems on equipment
When analysing piping connected to parallel located equipment, the relevant worst temperature
combination case of the shall be used.
Calculation of thermal nozzle loads shall be based on the maximum or minimum design
temperature.
Piping connected to compressor and pump suction and discharge nozzles shall be fully force
balanced through its supports in the liquid filled condition and shall exert only minimal loads on the
nozzles in order to minimise equipment misalignment caused by external loads.
Allowable loads on equipment shall be calculated in accordance with R-CR-001.

When calculating loads on compressor nozzles, the point for resolvement of forces and moments
shall be agreed with the compressor vendor.

Piping Stress Analysis – Where do I start?

 

 

Piping Stress Analysis – Where do I start?

The following information will take you step-by-step through the logic of the data collection effort

that should occur prior to beginning to model a piping system for a stress analysis:

1. First of all, prior to starting to build a piping model it is imperative to sort out what you wish

to achieve in any analysis. The following questions may assist you in determining the

reasoning for conducting a piping stress analysis:

a) Are you interested in performing a piping stress analysis to evaluate the stresses in a

specific piping system and to determine if these stresses are within the range allowed by

the Piping Code?

b) Are you interested in performing a piping stress analysis to evaluate the loads on a piece

of rotating equipment?

c) Are you interested in performing a piping stress analysis to evaluate the loads on a heat

exchanger, pressure vessel or tank nozzle?

d) Are you interested in performing a piping stress analysis to evaluate the loads on one or

structural anchors?

e) Are you interested in performing a piping stress analysis to evaluate the loads on one or

more pipe supports?

f) Are you interested in performing a piping stress analysis to evaluate the movements of

portions of the piping system due to thermal growth or contraction?

g) Are you interested in performing a piping stress analysis to evaluate the effects of wind

loads on the piping system and/or attached equipment?

h) Are you interested in performing a piping stress analysis to evaluate the effects of

earthquake loads on the piping system and/or attached equipment?

i) Are you interested in performing a piping stress analysis to evaluate the effects of wave

loading on the piping system and/or attached equipment?

j) Are you interested in performing a piping stress analysis to evaluate the effects of soil

resistance to movement for underground or buried piping system and/or any attached

equipment?

k) Are you interested in performing a piping stress analysis to evaluate the effects of

changes in temperature, pressure and weight on flanged couplings and to determine if

there is a tendency for the connections to leak?

Once these questions have been answered, then check each of the following steps.

2. Determine which piping code will govern the design of the piping system.

3. Collect all the plan and elevation drawings necessary to fully document the piping routing.

4. Obtain or construct an isometric drawing of the entire piping system. If you have several

piping isometrics documenting different parts of the piping system, make sure that the North

arrow orientation is the same on all such isometrics. If they are different, re-draw those

piping isometrics that are necessary to have all North arrow orientations the same on all

isometrics.

5. Collect all the necessary physical properties for all of the piping components in the piping

system as follows:

a) Nominal Pipe Diameter or Actual Outside Diameter, if the Pipe is Non-Standard.

b) Pipe Schedule or Pipe Wall Thickness.

c) Corrosion Allowance.

d) The Specific Gravity of the contents of the pipe or the Weight per unit length of the

contents.

e) The Insulation Material or Insulation Density and Thickness or the Insulation weight per

linear unit length.

f) Piping Material or piping material density, modulus of elasticity and coefficient of

expansion.

g) Operating Temperature (Minimum and maximum, if applicable), Design Temperature,

Upset Condition Temperature and Base or Ambient Temperature.

h) Operating Pressure (Internal or External), Design Pressure and Upset Condition

Pressure.

i) Flange Rating and Flange Type or Flange Weight and Length.

j) Valve Type (Gate, Globe, Butterfly, etc.) Rating or Valve Weight and Length.

k) Elbows and/or Bends Radius or Bend Radius Ratio, Fitting Thickness and the number of

miter points, if applicable.

l) Reducer length, inlet and outlet diameters, schedule or wall thickness, concentric or

eccentric and, if eccentric, the flat side orientation.

m) Branch Connections – welding tee, weld-in contour insert, weld-on fitting, fabricated tee

with the reinforcing pad thickness, extruded tee with the crotch radius or lateral fitting

data.

n) Expansion Joint Properties – Translational Spring Constants in force/unit length of travel

– Axial and Lateral or Shear and Rotational Spring Constants in moment/degree of

rotation – About the axis of the expansion joint (normally considered to be totally rigid)

and about the radial axes. The length of the bellows component is needed and in the

event that the expansion joints are not oriented along one of the axes of the X, Y, Z axis

system, the angles required to define the skewed orientation will also be required.

Further information is required. The length between tie rods is necessary as well as

whether or not nuts are on the tie rods to restrict extension as well as compression in the

expansion joint. The pressure thrust area is required in the event that tie rods do not

restrain axial movements. If an expansion joint is hinged or gimbaled, then the

orientation of the hinge or gimbal axes is required.

o) Structural Members – Any structural member that is welded or bolted to the piping

system and is expected to act as part of the piping system must be defined. If the

structural member is a standard structural shape, then the designation is required along

with the orientation with regards to the X, Y, Z axis system. If the structural member is

not a standard structural shape, then the moments of inertia about each axis is required

along with the polar moment of inertia, the cross sectional area, and the distance from

the member centerline to the outer surface. If the structural member is skewed, then the

orientation with regards to the X, Y, Z axis system is also required.

6. For all Anchors, the following data is required. The location of the anchor point in the

piping system. A complete definition of the equipment or structure to which the piping

system is connected. If a small piping system is connected to a strong beam, column or

anchor block, then the anchor can be considered to be rigid. If a large pipe, say 24”, is

anchored to an 8×13 beam, relatively flexible, then the anchor should be defined as a

flexible anchor and the flexibilities of the structural member should be calculated and

entered. If the anchor point is a nozzle on a pressure vessel, tank or heat exchanger, the

flexibility of the nozzle may need to be entered should the stress level in the piping system be computed to be too high. And the stress level in the nozzle to shell connection in the pressure vessel, tank or heat exchanger may need to be evaluated for an over stressed condition. In addition, equipment operating at a specific temperature will expand or contract from the ambient conditions. Therefore, the drawings for all connected equipment should be obtained. The lengths from the actual anchor point on the connected equipment are required as well as the temperature of the connected equipment. If the connected equipment is a piece of rotating equipment, the nozzles are considered to be completely rigid, but the casing will expand or contract from the ambient conditions to the operating conditions.

7. For all restraints, the following data is required. The location of each restraint acting on the

piping system must be defined as well as the specifics as to how each restraint affects the

piping system. The following discussion covers restraints acting along one of the X, Y, Z

axes. If skewed restraints are in the piping system, then their orientation with respect to the

X, Y, Z axis system must be defined.

a) Translational Restraints – First of all, the axis along which or about which the restraint

acts must be defined. If the restraint restricts movement along an axis (a translational

restraint), then you must be able to define if the restraint acts in one direction along the

axis or if it works in both directions along the axis and obviously if in only one direction,

which one it is.

b) Limit Stops – If the restraint allows a certain amount of movement and then restrains the

pipe, this is known as a limit stop. For limit stops, the action axis must be defined as

well as how much movement is to be allowed in the plus and minus directions along the

specified axis. Further, when the limit is encountered, the stiffness of the resistance

must be defined. Normally, a limit stop allows movement to a point and then stops the

piping from going any further. In some cases, when a limit stop is encountered, the

resistance to further movement is defined by a spring constant.

c) Imposed Movements – If a movement is to be imposed on the piping system, the amount

of the movement and the direction of the movement must be defined.

d) Imposed Forces – If a force is to be imposed on the piping system, the amount of the

force and the direction of action of the force must be defined. In addition, when the

force is imposed, the force may have a spring constant associated with it. In other

words, if a force is applied to the piping system and the force changes as piping system

movement occurs, then the change in the force per unit of movement (spring constant)

must be defined.

e) Dampers – In the event that a restraint acting on a piping system allows gradual

movements but resist impulse movements, this is commonly referred to as a damper or a

snubber. In the event that dampers or snubbers are included in a piping system, the axis

of action must be defined as well as the maximum load that can be resisted.

f) Frictional Resistance to Movement – When frictional resistance can significantly

influence the results of a piping stress analysis, it should be considered. The plane in

which frictional resistance acts as well as the dynamic and static coefficients of friction

should be defined.

g) Existing Spring Hangers – When spring hangers have been installed in a piping system

and a new piping stress analysis study is to be processed, the spring constant of the

spring hanger must be known as well as the installed load, the operating load and the

minimum and maximum loads that the spring hanger will successfully handle. It is also

necessary to know if the spring hanger is attached from above and if lateral movement is

allowed by the support rod(s) and to what limit, if any. If the spring hanger is actually a

support, then the limit of lateral movement should be defined and if a low friction

bearing has been placed on top of the spring support. If a low friction bearing has been

used, then the coefficient of friction must also be defined.

h) New Spring Hangers to be Designed – When spring hangers are to be sized and selected,

the number of spring hangers to be located at that support point must be defined.

Usually one spring hanger is to be placed at each support point. Occasionally because of

restricted headroom, a trapeze assembly with two spring hangers providing support will

be used. In addition to the number of spring hangers, the desired manufacturer should be

defined as well as the desired maximum load variation.

i) Rotational Restraints – If the restraint restricts movement about an axis (a rotational

restraint), then axis about which rotation is restrained must be defined.

j) Imposed Rotations – If a rotation is to be imposed on the piping system, the amount of

the rotation and the direction of the rotation must be defined.

k) Imposed Moments – If a moment is to be imposed on the piping system, the amount of

the moment and the direction of action of the moment must be defined. In addition,

when the moment is imposed, the moment may have a spring constant associated with it.

In other words, if a moment is applied to the piping system and the moment changes as

piping system rotation occurs, then the change in the moment per unit of rotation (spring

constant) must be defined.

8. Special Effects such as cold spring must be defined. First, the location of the cold spring in

the piping system must be specified. This must include the direction or directions of the

cold spring. Cold spring along the X axis, the Y axis and the Z axis can be placed in a

piping system. Then it must be specified whether the cold spring is a Cut Short or a Cut

Long. In addition, the amount of the cut short or cut long must also be specified.

9. Special Loading Conditions

a) Wind Loading – When wind loads are to be considered in an analysis, the piping

components on which the wind loads are to be applied must be identified. TRIFLEX

calculates wind exposure and does not apply wind loads on a piping component when

the axis of the component and the wind are coincident. To define wind loads, the

direction of the wind loads with respect to the X, Y, Z axes must be defined. Then the

magnitude of the wind loads must be quantified as a wind speed or a pressure per unit of

surface area and a shape factor or a load per unit of length of the piping component.

b) Wave Loading – When wave loads are to be considered in an analysis, the piping

components on which the wave loads are to be applied must be identified. TRIFLEX

calculates wave exposure and does not apply wave loads on a piping component when

the axis of the component and the wave are coincident. To define wave loads, the

direction of the wave loads with respect to the X, Y, Z axes must be defined. Then the

magnitude of the wave loads must be quantified as a wave speed or a pressure per unit of

surface area and a shape factor or a load per unit of length of the piping component.

c) Uniform Loads such as Snow and Ice – When uniform loads are to be considered in an

analysis, the piping components on which the uniform loads are to be applied must be

identified. TRIFLEX applies uniform loads on a piping component as defined by the

analyst. To define uniform loads, the direction of the uniform loads with respect to the

X, Y, Z axes must be defined. Then the magnitude of the uniform loads must be

quantified as a load per unit of length of the piping component.

d) Seismic Loads – When seismic loads are to be considered in an analysis, the magnitude

of the loading must be quantified and a decision as to the analysis method to be

employed must be made. When seismic loads are to be evaluated in a static analysis,

they are to be defined as a percentage of gravity along the X, Y, and Z axes. The

percentages should be identified and the various combinations of loading conditions

should also be identified.

e) Soil Interaction – When soil loading is to be considered, the piping components on

which the soil interaction is to be modeled must be identified. The analyst can elect to

calculate and enter spring constants to simulate the soil stiffness. Stepped stiffnesses

may be entered if required because of the movement and the soil properties.

Alternatively, the analyst may employ the guidelines published in the B31.1 Power

Piping Code. When using these guidelines, the following data will be required: Soil

Density, the Type of Backfill, the Depth of the Trench, the Width of the Trench, the

Load Coefficient, the Horizontal Stiffness Factor and the Axial Friction Coefficient.

10. Once all the physical data has been collected, the Global (overall) Axis System (X, Y, Z)

must be oriented on the isometric drawing for easy reference. (The standard right-hand rule

axis system is used with Y being the vertical axis. All weight calculations are based upon

gravity exerting a negative Y force on the piping system.)

11. Now you are ready to begin assigning data point numbers to all pertinent piping components

in the piping system. All such data point numbers should be placed on the isometric

drawing. A data point must be assigned to any location in the system for which output data

is desired. The data point describes the specific location in the system and the preceding

segment of the piping system. Assign a data point number at each blind end or nozzle

(which begins a Branch). Even if an Anchor is totally free to move and rotate, it will still be specified as an Anchor point at the beginning of a branch.

 

FPSO-FAQ

1

What is an FPSO?

“FPSO” stands for Floating Production, Storage and Offloading. An FPSO system is an
offshore production facility that is typically ship-shaped and stores crude oil in tanks located in
the hull of the vessel. The crude oil is periodically offloaded to shuttle tankers or ocean-going
barges for transport to shore. FPSO’s may be used as production facilities to develop marginal
oil fields or fields in deepwater areas remote from the existing OCS pipeline infrastructure.
Additional details about FPSO’s can be found in OCS Report MMS 2000-015.
Where have FPSO’s operated to date?
FPSO’s have been used to develop offshore fields around the world since the late 1970’s.
They have been used predominately in the North Sea, Brazil, Southeast Asian/South China Seas,
the Mediterranean Sea, Australia, and off the West Coast of Africa. There are currently 70
FPSO’s in operation or under construction worldwide. In addition to FPSO’s, there have been a
number of ship-shaped Floating Storage and Offloading (FSO) systems (vessels with no
production processing equipment) used in these same areas to support oil and gas developments.
One FSO is currently operated by PEMEX in the southern Gulf of Mexico (Bay of Campeche).
Have there ever been any major spills from FPSO’s?
Several organizations have developed comprehensive databases for all offshore incidents.
A study by INTEC Engineering was commissioned by DeepStar early in the environmental
impact statement (EIS) process to identify the spill history for FPSO operations. DeepStar is a
multiphase deepwater technology study currently funded by 16 oil companies and more than 40
contributing manufacturers, vendors, consulting organizations, classification organizations, and
contractors.
The largest spill from an FPSO occurred in the late 1990’s – approximately 3,900 barrels
of oil were spilled from the Texaco Captain FPSO during startup at its field location. The spill
was attributed to human error during the start-up procedure; an overboard dump valve was
inadvertently left open and hydrocarbons were released. Oil spills from all other FPSO
operations have reportedly spilled less than 500 barrels of oil combined. FPSO’s have been
successfully operating for a cumulative 460 plus FPSO-years, processing an estimated 6.4 billion
barrels of crude oil.
Why did MMS require an EIS?
Out of an abundance of caution, MMS required that an Environmental Impact Statement
(EIS) be done addressing the proposed use of FPSO’s. The National Environmental Policy Act
requires the preparation of a detailed EIS on any major Federal action that may have a significant
impact on the environment. The use of FPSO’s would represent new technology and potential
impacts in the Gulf OCS. The decision to prepare an EIS was based on several considerations
including the potential for significant environmental impacts, the degree of uncertainty about
level of potential impacts, and the concern or controversy associated with a proposed action.
There was also concern over an apparent higher risk of very large oil spills. (Subsequently, the
EIS analyses and the CRA showed that FPSO’s do not pose greater spill risks.) The EIS was
initiated not only to evaluate potential environmental impacts, but also to provide for public
2
disclosure and input.
For the purposes of the EIS, how is deepwater defined?
The MMS chose the 200-meter (approximately 650-foot) isobath to represent the
beginning of deepwater area for the purposes of this EIS. The MMS recognizes that deepwater
is defined differently by many operators. However, in considering the water depths that FPSO’s
have operated in the past, we believe 650 feet is a reasonable definition for deepwater.
Why did you investigate FPSO’s only for the Central and Western Planning Areas?
As industry is proposing the use of FPSO in the Gulf of Mexico OCS (the proponent of
the proposed action), MMS relied on industry to identify the scope of their proposed activities.
Industry indicated an interest in FPSO operations for only the deepwater areas of the Central and
Western Planning Areas of the Gulf of Mexico OCS. In addition, industry indicated they did not
anticipate that produced oil from any FPSO would be tankered into any ports east of the
Mississippi River ports.
What was the FPSO system studied in the EIS, and how was it chosen?
The MMS and DeepStar developed the FPSO scenario to be representative of the range
of typical FPSO’s that would be likely to operate in the GOM during the next 10 years.
Expertise representing FPSO operating companies, designers and builders, equipment
manufacturers, classification society organizations, and government agencies were involved in
the system definition used for the FPSO base case. The base case scenario studied in the EIS
was a generic FPSO system that can be described as follows:
- permanently moored, fully weathervaning turret;
- double-hulled (sides and bottom per OPA 90), ship-shaped;
- storage up to 1 million barrels of crude oil;
- 300,000 barrels of oil and 300 million cubic feet of gas per day processing capability;
- multiple subsea wells producing back to the FPSO;
- conventional, ship-shaped, shuttle tankers with 500,000 barrel storage capabilities.
The base case investigated in the EIS addressed shuttle tankers. Why did you not consider tugbarge
systems (e.g., articulated tug and barge (ATB))?
The use of a conventional shuttle tanker was identified by the industry/MMS/USCG team
as the most likely scenario for an FPSO-based development in the GOM. The EIS does not
exclude the use of ATB’s; both shuttle tankers and ATB’s would transport the oil from the FPSO
to shore. The EIS addressed the potential use of ATB’s as part of the range of technical options
for the proposed action. In responding to comments on the draft EIS, the USCG stated that they
consider an ATB to be a specialized type of integrated tug barge (ITB) and subject to policies
described in the USCG Navigation and Vessel Inspection Circular (NVIC) 2-81 (Change 1). The
use of ATB’s is an issue that the USCG would address in their permit requirements for the
FPSO-based development.
Why didn’t the EIS address floating storage units?
A Floating Storage and Offloading (FSO) unit can be considered to be a subset of
FPSO’s. The FSO system lacks the oil and gas production processing capabilities of the FPSO.
An FSO is typically used as a storage unit for production processed from other platforms that are
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remote from infrastructure and lack an oil pipeline to transport the oil to the refinery. One
example is the Ta’Kuntah FSO that has been operating in the southern GOM (Mexican waters)
since 1999. The EIS provides a programmatic NEPA review of the major aspects of FPSO’s and
FPSO-like operations, including on-site storage of large volumes of produced oil, offloading
operations, surface transport of OCS-produced crude oil, and the potential fate and effects of
very large oil spills. The environmental review of an FSO proposal would be able to tier from
the EIS and incorporate by reference the analyses of the aspects in common.
What is the next step now that MMS has issued the Final EIS and a Record of Decision (ROD)?
The ROD documents the Agency’s decisions that are based on the EIS and is the formal
completion of the EIS process. The MMS will continue to work with the U.S. Coast Guard
(USCG) to delineate jurisdictional issues based on the Memorandum of Understanding between
the two agencies. That Memorandum of Understanding was signed in December 1999 and
addresses all OCS oil and gas activities. Discussions with USCG will continue about the
potential use of FPSO’s within portions of the lightering prohibited areas. There will be
continued dialogue and work group activities with the industry to further enhance existing
recommended practices, guidelines and standards for floating production systems (including
FPSO’s). The API has also commissioned a workgroup to further address concerns associated
with shuttling crude oil from OCS production facilities to the tanker operations in the GOM.
Both MMS and the USCG are involved in the API-led effort.
Further action on any specific FPSO proposal would proceed as with any other
hydrocarbon development in deepwater. The first formal step in the proposal process would be
the submission, review, and approval of a Deepwater Operations Plan. Later, the operator would
submit an OCS development plan. At that time, an environmental assessment would be done to
evaluate the site-specific and proposal-specific aspects of the proposed FPSO operations.
What level of review will be required if a proposal is submitted for FPSO operations that aren’t
like the EIS base case (e.g., a single-hulled FPSO)?
The EIS is a programmatic document that examines the concept of, and fundamental
issues associated with, the petroleum industry’s proposed use of FPSO’s in the Central and
Western Planning Areas of the Gulf OCS. The EIS addresses the proposed action generically
and does not constitute a review of any site-specific development proposal. The EIS considers a
range of technical variations that would reasonably be expected to represent industry’s intended
applications of these systems. The major components of the “base-case,” a generic FPSO system
and operation, generally fall within a range of potentially viable design choices and
configurations. The EIS provides a programmatic NEPA review of the major aspects of FPSO’s
and FPSO-like operations, including on site-storage of large volumes of produced oil, offloading
operations, surface transport of OCS-produced crude oil, and the potential fate and effect of very
large accidental oil spills. Further technical and environmental evaluation will be required for
specific FPSO proposals. The MMS will require submission and approval of a Deepwater
Operations Plan (DWOP) and a Development Operations and Coordination Document (DOCD)
before any FPSO operation could occur. The DOCD environmental review will be tiered off of
the regional environmental analysis in the programmatic EIS and will focus on the site-specific
and system-specific aspects of the proposed FPSO. Any proposed FPSO operations that are not
within the range of operations evaluated in the programmatic EIS will require more extensive
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environmental review and NEPA documentation than would proposed operations within the
range addressed in the EIS.
What has been accomplished as a result of the EIS? The regulatory model process?
The EIS examined the range of most likely configurations of potential FPSO operations
that may be proposed for use in the Gulf of Mexico OCS. The EIS provides a programmatic
NEPA review of the major aspects of FPSO’s and FPSO-like operations, including on-site
storage of large volumes of produced oil, offloading operations, surface transport of OCSproduced
crude oil, and the potential fate and effects of very large oil spills. Although the level
of environmental review for a site-specific, proposal-specific development plan will depend on
the final decision document in the Record of Decision (ROD) and on the specific operations
proposed, the EIS was intended to serve as a base document from which to tier subsequent
environmental review of FPSO’s. This should allow FPSO proposals within the range of
operations addressed in the EIS and conforming to any constraints imposed by the ROD to be
addressed by a site- and proposal-specific environmental assessment (EA). The MMS
anticipates that such an EA would be completed within six months.
Review of the Regulatory Model has resulted in an MMS-proposed regulatory package to
enhance the existing rules through the incorporation of several recommended practices. A
complete rewrite of the Platforms and Structures section (Subpart I) in 30 CFR 250 is one of the
key parts of this regulatory package to address all floating production systems (including
FPSO’s). Also part of this effort is the incorporation of several recommended practices into the
existing pollution prevention regulations (30 CFR 250). Publication of the MMS regulatory
package (Documents Incorporated by Reference and Subpart I rewrite) was published as a Draft
Rule in December 2001.
The Regulatory Model development has allowed the MMS and USCG to identify the
applicable industry design and operating standards for FPSO-based developments that have been
applied throughout the world. This effort has also identified where gaps exist in the design and
operating standards, allowing the agencies and industry to develop appropriate strategies for
closing the gaps. When competed, the regulatory model will provide industry with a road map
for the approval process of an FPSO-based development on the Gulf of Mexico OCS.
During this time, the MMS funded a Comparative Risk Analysis to evaluate the risks
associated with FPSO technology compared to those associated with three types of existing
GOM deepwater facilities. The U.S. Fish and Wildlife Service and the National Marine
Fisheries Service were consulted on FPSO-related issues under their respective jurisdictions.
The MMS sponsored and participated in several joint Federal/industry workshops to identify the
technical, safety, and environmental issues and information needs related to FPSO’s, as well as
to gain a better understanding of FPSO technology and scope of operations around the world.
What steps remain to be taken by government and industry to complete the regulatory model and
what is the timetable?
Coordination and settlement of overlapping responsibilities between the USCG and MMS
are continuing. Both MMS and the USCG believe the capability (framework) exists to review an
FPSO-based development. This effort has progressed to the point of determining the specific
points within the production and marine systems where jurisdiction changes. The objectives of
this effort are to minimize duplication of effort and to ensure a consistent regulatory review for
FPSO-based developments. In addition, publication of a regulatory package by MMS
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(Documents Incorporated by Reference and Subpart I rewrite) will enhance MMS’s ability to
regulate all floating production systems, including FPSO’s, in the Gulf of Mexico OCS.
A work group comprising the Offshore Operators Committee, MMS, and USCG
developed a set of recommended actions as part of a broad regulatory framework for FPSO’s in
the GOM. There are several outstanding recommendations affecting industry and the USCG that
need to be addressed. No specific timeline has been developed by the industry to close these
action items; the USCG continues to gather information and is working closely with MMS to
address mutual requirements.
What was the focus for your Comparative Risk Analysis (CRA)?
Concurrent with the EIS, the MMS-funded CRA was performed to compare the relative
risks of an FPSO system with three other deepwater development systems: fixed platform
production hub, a spar, and a tension leg platform (TLP). All of the production systems except
the FPSO are currently in use for deepwater development projects in the U.S. Gulf of Mexico.
The study was performed under contract to the Offshore Technology Research Center, with
technical support from EQE International and the industry consortium DeepStar. The CRA used
the same base-case FPSO system that was used in the EIS. The overall intent of the CRA was to
provide MMS context and perspective for FPSO risks, and to assist with MMS decisions
regarding the potential use of FPSO’s in the Gulf OCS. The CRA was also designed to help
MMS understand the risk contributions of the various components (subsystems) and phases of
operation.
How were the results of the CRA used to focus mitigation?
The CRA did not mitigate the risks identified in the study. The CRA concluded that
there are no significant differences in the oil-spill risks among the four systems studied (FPSO,
TLP, Spar, and Fixed Jacket Platform serving as a Production Hub/Host). The MMS and the
study participants deemed it not necessary, for purposes of the CRA study, to mitigate the FPSObased
development to a lower level than the risk levels represented by the existing deepwater
production systems. The CRA did include a limited effort to identify potential risk reducing
measures but these were not quantitatively investigated.
The EIS and accompanying frequency analysis for accidental spills also identified
potential risk-reducing measures.
Specific to the shuttle tanker transport, what were the data sources used in the EIS accidental
spill frequency analysis and the CRA?
Det Norske Veritas (DNV) performed the “Accidental Spill Frequency Analysis” for the
EIS. The data set used to determine the frequency of shuttle tanker spills was based on data from
Anderson and LaBelle (1994) for spills in U.S coastal and offshore waters. The data cover
tanker spills over a 19-year period (1974-1992). Spill size distribution was based on an analysis
by DNV of data from Lloyd’s Maritime Information Service (LMIS) database for worldwide
tanker spills over a 3-year period (1992-1994).
In the CRA, risks (both for spills and fatalities) were extrapolated directly from historical
experience in the GOM, using MMS and USCG databases whenever possible. The study started
with raw data sets that were as complete as possible in the preliminary risk assessments, and
refined the data so they were relevant predicting the future performance of the FPSO in the
GOM. For example, the frequency of shuttle tanker spills of less than 10,000 bbl is based on the
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USCG data for crude oil tanker spills occurring in the Gulf of Mexico. These data were refined
to account for the benefits demonstrated to date and expected to occur as a result of OPA 90 (i.e.,
the data used are from 1992-1999). For spills greater than 10,000 bbl, the CRA used post-OPA
90 data for crude tankers worldwide. Likewise, the spill risks from process systems onboard the
various deepwater production systems were based on incidents that occurred after 1990.
Incidents prior to 1990 were discarded because of the implementation of MMS regulations in 30
CFR 250, specifically the incorporation of standards such as API RP 14B, 14C, and 14H. These
standards address the design and operation of the safety devices installed to protect both
personnel and the environment.
MMS appears to have used separate data sets for the risk studies done in the EIS and the CRA.
Why was this done?
See previous comment. Separate consultants performed the Accidental Spill Frequency
Analysis (EIS) and the Comparative Risk Analysis (DNV for the EIS; the Offshore Technology
Research Center (OTRC) for the CRA). As noted above, the data used by DNV were proprietary
data not accessible to the CRA. Further, it was decided by OTRC and expert participants in the
CRA to discard incidents prior to the implementation of OPA 90, thereby reflecting the current
requirements for an FPSO operating in the OCS. The MMS believes that the datasets used were
appropriate for their applications.
Are there plans for updating the NEPA analysis and the Comparative Risk Analysis?
The scenario for the EIS addresses a 10-year time frame from 2000-2010. The MMS
believes the scenario is representative what is likely to occur regarding FPSO operations during
this time. The MMS will use each site-specific Development Operations Coordination
Document (development plan) application and its accompanying environmental information to
update the NEPA analysis provided by the programmatic EIS. In addition, MMS will include
evaluation of FPSO’s in future lease sale EIS’s.
The MMS is considering a follow-up study to the CRA to investigate alternative hulls
(e.g., Spars) used as FPSO’s. Data collection and experience with actual FPSO’s and other
deepwater systems will provide the opportunity to refine some of the results in the CRA, thereby
reducing the level of uncertainty identified in the study. (On many of the CRA graphics, error
bars show the range of uncertainty).
What systems or operations were identified as having the highest risk of a large pollution event?
Oil transportation, regardless of the type of deepwater production facility, was identified
through the various programmatic studies as having the highest risk for a spill. The oil
transportation systems include pipelines for Spars, TLP’s, and fixed platforms; and shuttle
tankers for FPSO’s.
Are there FPSO systems, subsystems, or technical issues that MMS has identified as having a
higher leak frequency or risk to operational safety? If so, how will these be addressed?
The risk studies and other technical evaluations have been performed as part of MMS’s
strategy to support a decision about the acceptability of FPSO’s for OCS development in the
deepwater Central and Western GOM. Both the EIS and the CRA found the transportation
system to have the highest risk component, not only for FPSO’s, but for all deepwater
development systems. There are systems unique to FPSO-based development that will require
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technical evaluation when a site-specific application is submitted. Two examples are the turret
mooring system and the equipment used to transfer produced-fluids from the seafloor production
equipment to the FPSO.
The turret transfer system provides the ability for an FPSO to weathervane (that is,
allowing the ship to take the position of least resistance based on wind, waves, and currents)
around the mooring, thus minimizing the loading imposed by the environment. Two designs
have been used for transferring hydrocarbons and utilities (control fluids, etc.) from the risers to
the piping on the deck of the FPSO mooring system: a swivel system that allows production
from the subsea wells to be transferred to a freely weathervaning ship, and a drag-chain system.
The reader is referred to MMS 2000-015 for details of the two systems
A key component of MMS’s ability to review an FPSO-based development, and in
particular the unique systems associated with an FPSO, is the Deepwater Operations Plan
(DWOP). Notice to Lessees (NTL) 2000-N06 describes the DWOP requirement. The DWOP
addresses MMS’s review of the deepwater development project from a total system perspective
without writing new regulations, i.e., using the existing regulations that provide for the use of
alternative compliance measures. The information required to be submitted in a DWOP focuses
on characterizing the production system on a component basis, including the following:
structural aspects of the facility (fixed, floating, subsea); stationkeeping (includes mooring
system); wellbore, completion, riser systems; safety systems; offtake; and hazards and
operability of the production systems. By design, the DWOP is able to look at the components
of a proposed development system to see how they relate to previously approved production
systems. Information is gathered for the individual components of the various types of
deepwater production systems and integrated into a review that is focused from a total systems
perspective. The DWOP also provides the mechanism for MMS to move forward with actions
on a development project even though all the technical issues have not been completely
identified or resolved. The DWOP provides MMS with the ability to determine that the operator
has designed and built sufficient safeguards into the production system to prevent the occurrence
of significant safety or environmental incidents.
When do you expect the first application for an FPSO-based development to be submitted?
To date, no lease operator has approached MMS with plans to develop an OCS discovery
with an FPSO. The GOM operators have made it clear that the FPSO is a system they believe is
necessary to enable the development of some Gulf of Mexico OCS leases. They have further
indicated that not all discoveries will be candidates for FPSO-based projects. As operators
continue to make discoveries far away from existing infrastructure, and find economically
marginal fields, the FPSO will likely be a development system that is given serious
consideration.
How long will it take for MMS to review the permits for an FPSO-based development?
Early dialogue between MMS and the operator and complete information submittal are
key to avoiding delays that might affect project start-up plans. Further technical and
environmental evaluation will be required for specific FPSO proposals. The MMS will require
submission and approval of a Deepwater Operations Plan (DWOP) and a Development
Operations and Coordination Document (DOCD) before any FPSO operation could occur. The
EIS provides a programmatic NEPA review of the major aspects of FPSO operations, including
on-site storage of large volumes of produced oil, offloading operations, surface transport of
8
OCS-produced crude oil, and the potential fate and effects of very large oil spills. The
environmental review of an FPSO proposal would be able to tier from the EIS and incorporate by
reference the programmatic analyses. The MMS projects that it will take 6 to 9 months to
complete the environmental review and take action on a Development Operations Coordination
Document (referred to as a DOCD) for a proposed FPSO within the range of activities evaluated
in the EIS. Any proposed FPSO operations that are not within the range of operations evaluated
in the programmatic EIS will require more extensive environmental and technical review to
demonstrate equivalence to what was investigated by MMS.
The technical permit requirements would be closely tied to key milestones in the
operator’s development schedule. The DWOP timing can be summarized as follows:
- 30 days for Conceptual Part of DWOP;
- up to 90 days for Preliminary Part of DWOP.
Will MMS allow gas to be flared or reinjected?
The MMS will require the operator to transport produced gas to market. This will likely
require a dedicated pipeline for gas production. The MMS has stated throughout the
development of the FPSO strategy that flaring of gas would not be permitted on an extended
basis. The MMS regulations do provide some limited volume, short duration flaring upon
approval.
Although gas may be injected to increase ultimate oil recovery, MMS has stated that
reinjection of the produced gas would generally not be permitted without a commitment from the
operator to produce the gas at a later time. Although it is possible for another lessee to produce
injected gas at a later date, it is highly unlikely that after the oil has been depleted another
operator could economically recover the gas if the original operator couldn’t at the time the oil
was produced. A policy that permitted gas injection without a commitment to later produce the
gas would result in a tremendous loss of mineral resources to the United States.
There are emerging technologies for converting gas to liquids, gas compression for shipborn
transport, etc. that have been identified in industry studies as technically and economically
feasible. The MMS believes these alternatives must be considered in decisions about gas
disposition.
Has there been a ruling from the U.S. Customs Service regarding the applicability of the Jones
Act to FPSO’s and shuttle tankers involved in OCS development?
The USCG received a response from the Customs Service dated March 7, 2001. The
response states that shuttle tankers must comply with Jones Act requirements and be coastwise
qualified. The Customs Service states that an FPSO permanently-moored at an OCS location
would not be required to be coastwise qualified. If the FPSO is used to transport oil or natural
gas to a U.S. port or a deepwater port located on the OCS (e.g., LOOP), then it must be
coastwise qualified.
Could an operator transport the oil produced from an FPSO to a foreign location?
The OCS Lands Act Amendments of 1978 (43 USC 1354, Section 28) states that “any oil
or gas produced from the outer continental shelf shall be subject to the requirements and
provisions of the Export Administration Act of 1969.” That law prohibits the export of OCS oil
unless the President of the United States publishes an express finding that such exports will not
increase the reliance on imported oil and gas and are in the national interest.
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Are FPSO’s reviewed in the programmatic EIS similar to the P-36 facility that recently sunk off
the coast of Brazil?
There are many different types and configurations of floating production facilities.
FPSO’s reviewed in the programmatic EIS are ship-shaped-type facilities while the P-36 that
recently sank off Brazil was a semi-submersible-type facility. Each FPSO proposal will be
reviewed separately. Information gained from the P-36 tragedy and other offshore incidents will
be factored into these reviews. Revisions to MMS rules and industry technical standards will
also incorporate lessons learned from offshore incidents.