GP 44-15 14 August 2007 - Offshore Platform Layout

GP 44-15

Offshore Platform Layout

Group Practice

Document No. GP 44-15

Applicability Group

Date Draft 14 August 2007

BP GROUP ENGINEERING TECHNICAL PRACTICES

Draft 14 August 2007 GP 44-15 Group PracticeOffshore Platform Layout

Downloaded Date: 6/17/2008 11:13:22 PM The latest update of this document is located in the BP ETP and Projects Library

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Foreword

This is a draft issue of Engineering Technical Practice (ETP) BP GP 44-15. This Group Practice (GP) is newly developed and is not based on heritage documents from the merged BP companies.

Copyright 2007, BP Group. All rights reserved. The information contained in this document is subject to the terms and conditions of the agreement or contract under which the document was supplied to the recipient’s organisation. None of the information contained in this document shall be disclosed outside the recipient’s own organisation without the prior written permission of, BP Group, unless the terms of such agreement or contract expressly allow.



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Table of Contents

Page

1. Scope .................................................................................................................................... 5

2. Normative references............................................................................................................. 5

3. Terms and definitions............................................................................................................. 6

4. Symbols and abbreviations .................................................................................................... 9

5. Design parameters............................................................................................................... 10 5.1. Capital project design ............................................................................................... 10 5.2. Existing plant continuous risk reduction .................................................................... 11 5.3. Inherently safer design (ISD) .................................................................................... 11

6. Layout philosophy................................................................................................................ 12 6.1. Overview................................................................................................................... 12 6.2. Platform access ........................................................................................................ 13 6.3. Platform design study ............................................................................................... 14

7. Overall platform layout ......................................................................................................... 15 7.1. General platform design............................................................................................ 15 7.2. Typical platform layout options.................................................................................. 16

8. Platform decks and systems layout...................................................................................... 20 8.1. General..................................................................................................................... 20 8.2. Platform orientation and elevations requirements...................................................... 20 8.3. Decks........................................................................................................................ 20 8.4. Decking and stairways construction .......................................................................... 21

9. Potential low hazard area .................................................................................................... 22 9.1. General..................................................................................................................... 22 9.2. Buildings within low hazard area ............................................................................... 23 9.3. Temporary refuge (TR) ............................................................................................. 25

10. Emergency escape .............................................................................................................. 26 10.1. General..................................................................................................................... 26 10.2. Muster areas and evacuation facilities ...................................................................... 26 10.3. Alternative muster area............................................................................................. 27 10.4. Open shelter ............................................................................................................. 27 10.5. Evacuation facilities .................................................................................................. 28 10.6. Lifeboats or escape craft........................................................................................... 28 10.7. Helideck.................................................................................................................... 28 10.8. Boat landings and cargo transfer areas..................................................................... 29 10.9. Emergency fire protection equipment in low hazard area.......................................... 29 10.10. Firewalls and blastwalls ............................................................................................ 29

11. Potential high hazard areas ................................................................................................. 29 11.1. Wellbay area............................................................................................................. 29 11.2. Wellhead area........................................................................................................... 30



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11.3. Drilling rigs ................................................................................................................ 31 11.4. Pipeline equipment ................................................................................................... 33

12. Equipment layout ................................................................................................................. 33 12.1. Arrangement of equipment........................................................................................ 33 12.2. General piping arrangement (API RP 14E) ............................................................... 34 12.3. Layout and spacing................................................................................................... 35 12.4. Clearance requirements............................................................................................ 40

List of Figures

Figure 1 - PQ platform - topsides, south elevation......................................................................... 17

Figure 2 - PQ platform - topsides, east elevation .......................................................................... 17

Figure 3 - PDQ platform - production deck.................................................................................... 18

Figure 4 - PDQ platform - elevation............................................................................................... 18

Figure 5 - PDQ platform - alternate arrangement .......................................................................... 19

Figure 6 - FPSO - functional diagram............................................................................................ 20



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1. Scope

a. This GP provides requirements for layout of offshore platform facilities and forms a foundation for inherently safer design (ISD).

This GP is based on BP practice, good industry practice, and years of accumulated experience and lessons learned.

b. This GP applies to:

1. New facilities.

2. The evaluation of risk reduction opportunities for existing facilities

3. Expansions and modifications of existing facilities.

c. The intent of this GP is to share requirements for ISD of facilities but not to mandate a set design.

d. Facilities that may be addressed by this GP include:

1. Topsides layout for permanently installed platforms supported by substructures, such as steel piled jackets, gravity base structures, guyed towers, and floating production facilities (including tension leg and deep draft caisson vessels).

2. Both manned and normally unmanned installations (NUI), including facilities to support drilling equipment.

3. Conventional installations for processing, storing, and handling flammable or toxic fluids.

4. Units constructed onsite and modules fabricated offsite.

2. Normative references

The following normative documents contain requirements that, through reference in this text, constitute requirements of this technical practice. For dated references, subsequent amendments to, or revisions of, any of these publications do not apply. However, parties to agreements based on this technical practice are encouraged to investigate the possibility of applying the most recent editions of the normative documents indicated below. For undated references, the latest edition of the normative document referred to applies.

BP GIS 22-201 Flares (API 537). GIS 24-233 Fire Water Pumps and System Design. GP 04-10 Drainage Systems. GP 04-30 Design and Location of Occupied Portable Buildings within E&P

Segment Facilities. GP 22-10 Design of Fired Heaters to ISO 13705 (API 560). GP 22-20 Design of Flares (API 537). GP 24-03 Inherently Safer Design Concept Selection. GP 24-22 Gas Explosion Hazard Analysis - Offshore and Onshore. GP 24-23 Active Fire Protection - Offshore. GP 30-85 Fire and Gas Detection. GP 44-30 Event Modelling and Risk Based Evaluation. GP 44-60 API RP 500 Area Classification.



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GP 44-70 Overpressure Protection. GP 44-80 Relief Disposal Systems.

ASME International (ASME) ASME B31.3 Process Piping.

American Petroleum Institute (API) API RP 14 Recommended Practice for Analysis, Design, Installation, and Testing of

Basic Surface Safety Systems for Offshore Production Platforms. API RP 14 E Recommended Practice for Design and Installation of Offshore

Production Platform Piping Systems. API RP 14 F Recommended Practice for Design and Installation of Electrical Systems

for Fixed and Floating Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations.

API RP 49 Recommended Practice for Drilling and Well Servicing Operations Involving Hydrogen Sulfide.

API RP 64 Recommended Practice for Diverter Systems Equipment and Operation. API RP 500 Recommended Practice for Classification of Locations for Electrical

Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2.

API RP 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone \2.

API RP 521 Guide for Pressure-Relieving and Depressuring Systems.

National Fire Protection Association (NFPA) NFPA 30 Flammable and Combustible Liquids Code. NFPA 497 Recommended Practice on the Classification of Flammable Liquids,

Gases, or Vapours and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas.

3. Terms and definitions

For the purposes of this GP, the following terms and definitions apply:

Drilling facilities Drilling rigs (including associated drilling systems) that may be procured as preexisting contracted equipment and may be on location only temporarily during the drilling programme. Drilling rigs and their associated equipment (except related electrical generators, switchgear, and motor control centres [MCCs]) should be considered process equipment.

Control rooms Room serving as an operations center where a facility or service can be monitored and controlled. Control rooms may also be buildings where personnel perform incident control for a facility major accident.

Evacuation facilities

a. Primary evacuation for an offshore facility that provides for orderly evacuation of personnel in an emergency without external assistance (usually lifeboats).

b. Evacuation facilities are designed to remain useable for the endurance period.



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Endurance period Time period following a major accident during which the following facilities perform their respective roles:

a. Temporary refuges (TRs).

b. Other buildings that remain occupied.

c. Evacuation facilities.

Equipment

a. Any platform hardware item, including vessels, machinery, utilities, and piping.

b. Basic platform supporting structure, flare boom, and equipment internal to quarters or pressure vessel internals are not included in this definition.

Integrated decks Decks that reflect the fabrication method of topsides construction by which facilities and structural support systems are fabricated into a single unit that may be installed by a single lift or by float on mating to the substructure.

Layout Addresses the location of:

a. Equipment, including pipework, cable trays, instrument racks, surrounding and associated with discrete pieces of equipment.

b. Buildings, such as control rooms, switchgear, MCCs, workshops, storerooms, portable buildings, and permanent buildings.

c. Support structure and consideration of construction/installation methods, hookup, and commissioning of facilities.

Living quarters (LQ) Includes buildings in which personnel sleep (cabins), work (offices), and food preparation, dining, exercise, and recreation occur.

Major Accident Risk (MAR) process Combination of likelihood and consequence of major accidents. This is usually expressed in graphical format as a FN curve for risks to people, and as a F-Reputation curve for risk to the environment.

Identified events represent a range of hypothetical events that could lead to multiple fatalities or significant damage to ecosystems. Likelihood of the events is heavily influenced by engineering design of the facilities. Possible physical effects and consequences resulting from events are heavily influenced by facility layout.

Occupied building Building is considered occupied if its primary purpose is to provide workspace or accommodation for personnel, irrespective of occupancy. Typical examples include office buildings, control rooms, laboratories, and gate houses.

If the primary purpose of a building is to house equipment (turbine enclosure, compressor shelters, motor control centre [MCC] rooms, analyser shelters, instrument outstation, process equipment enclosures in regions of severe weather, etc.), it is not considered occupied, unless occupancy under normal operational conditions averages 2 man-hr or more in any 24 hr period.



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If a building has distinct sub buildings with different primary purposes (e.g., an enclosed office within a store building or an instrument room/MCC connected to a control room), occupancy of each part of the building may be considered separately.

Examples of occupied buildings may include, but are not limited to:

a. Offices

b. Training rooms

c. Orientation rooms

d. Lunch rooms

e. Conference rooms

f. Control rooms

g. Laboratories

h. Change houses

i. Maintenance shops

Buildings or shelters occupied only for short duration (e.g., toilet facilities, smoking shelters, and weather shelters) should be evaluated on a case-by-case basis.

Open shelters for muster Buildings open on one or more sides where personnel are instructed to muster following a major accident that provide protection against radiated heat effects for a defined period. Although these shelters are not normally occupied, they may be occupied in an emergency.

Platform modules Platform modules reflect the modular construction method typically used for topside facilities. These modules are usually installed offshore by crane vessels and supported on a jacket cap structure or module support frame (MSF) for steel piled jackets.

Process equipment Equipment containing produced hydrocarbons, including wellheads and piping. Formation water handling equipment that normally carries minimal produced hydrocarbons is also considered process equipment. Equipment associated with diesel fuel and other nonproduced hydrocarbons (such as machinery lube and seal oil consoles) is not considered process equipment.

Temporary refuge (TR) Buildings where personnel on board are instructed to muster in an emergency to take refuge for a defined period from effects of a major accident.

In some facilities, personnel may be instructed to muster at the evacuation point.

Utility enclosures (UE) Buildings occupied for part of the time that house equipment which needs to be isolated from the surrounding environment and where personnel also need to have access for maintenance and process control. Examples of these are:

a. Local equipment rooms.

b. Local control rooms.

c. Machinery spaces.

d. Subsea master control rooms.



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e. Fire pump rooms.

f. Emergency generator rooms.

g. Inert gas generator rooms.

h. Drilling utility enclosures.

Utility equipment Facilities necessary to support operation and maintenance of the process equipment plus equipment necessary for life support. Such equipment generally includes:

a. Electrical power generation, distribution equipment, emergency generators, and battery systems.

b. Seawater, potable water, and inhibited fresh water (cooling water) storage, pumps, and piping.

c. Instrument and utility air compressors, dryers, filters, and distribution systems.

d. Diesel fuel storage, pumping, treating, and distribution facilities.

e. Heating, ventilating, and air conditioning (HVAC) equipment and ducting.

f. Lube and seal oil storage tanks, pumps, filters, and piping required for rotating machinery.

Workshops Buildings occupied for periods of time that contain maintenance or repair equipment.

4. Symbols and abbreviations

For the purpose of this GP, the following symbols and abbreviations apply:

AMA Alternative muster area.

BOP Blowout preventer.

DLLR Davit launched lifeboat.

ESD Emergency shutdown.

E&P Exploration and Production.

FPSO Floating production, storage, and offloading (vessel).

FVO First valve on.

FVO/LVO First valve on, last valve off.

HAZID Hazard identification.

HAZOP Hazard and operability.

HSSE Health, safety, security, and environment.

HVAC Heating, ventilation, and air conditioning.

ISD Inherently safer design.



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LEL Lower explosive limit.

LFL Lower flammable limit.

LQ Living quarters.

LVO Last valve off.

MAR Major accident risk.

MCC Motor control centre.

MCR Main control room.

MCVP Major capital value process.

MOL Main oil line.

MSF Module support frame.

MSL Mean sea level.

MWD Measurement while drilling.

NUI Normally unmanned installation.

PA Public address.

PDQ Production, drilling, and quarters.

PPE Personal protection equipment.

PQ Production and quarters.

TEMPSC Totally enclosed motor propelled survival craft.

TR Temporary refuge.

SIL Safety integrity level.

UE Utility enclosures.

UPS Uninterruptible power supply.

5. Design parameters

5.1. Capital project design

a. When designing layout of new offshore facilities, Major Project Common Process (MPcp) principles of design safety should be used.

b. MPcp Design Safety supports and uses ISD principles, hazard evaluation, and risk management tools.

c. Design tools that should be used (and when) are contained in MPcp supporting documentation.



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5.2. Existing plant continuous risk reduction

a. Existing facilities can also benefit from requirements in this GP.

b. This GP includes many principles and examples of ways to reduce risk that can support the need to incorporate lessons learned in process safety and design safety activities.

Once a facility is built, it is much more challenging to rearrange the layout than if the facility is still on the drawing board, but general concepts apply. If applicable and of benefit, these concepts should be considered in risk reduction efforts.

5.3. Inherently safer design (ISD)

5.3.1. Purpose of ISD

a. This GP provides requirements and shares knowledge from experience and lessons learned to support the application of ISD.

b. The concept of ISD should be incorporated into the process risk management programme for each facility throughout all phases of design and operation, including facility layout (GP 24-03).

c. The content of this GP should be reviewed and considered while activities and analyses are performed in support of ISD.

d. The use of an ISD approach may eliminate or reduce hazards and eliminate the need for elaborate safety systems and administrative controls.

e. Facilities that have not used ISD methodology typically rely more on engineered and procedural safeguards to manage higher residual risks.

5.3.2. ISD principles

The four principles of ISD are:

a. Minimising amount of hazardous materials.

b. Substituting a hazardous material with a less hazardous one.

c. Moderating process conditions.

d. Simplifying process and equipment.

5.3.3. Hazard evaluation and risk management

a. A number of hazard evaluations and risk analyses are identified throughout the capital project value process supporting documentation.

b. Risk analyses overtly address ISD by identifying hazards and risks and considering ways to eliminate or reduce them through layers of protection.

c. Many decisions and design choices during project development also support ISD.

d. Analyses that overtly address ISD include:

1. Hazard identification (HAZID) analysis: Typically performed early in a project (appraise stage) and intended to identify hazards or risks in initial design concepts and layout such that forward design can eliminate or reduce hazards.

2. “What if”: Typically performed midway through a project design when sufficient details are available to identify specific hazards and project time is remaining to efficiently address the hazards.

3. Fire and blast analyses: Performed as details are available to evaluate consequence of fires and explosions on occupied buildings.



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4. Safety integrity level (SIL) analyses: Performed as details are available to examine layers of protection of detailed design.

5. Procedures: Operating and emergency procedures provide administrative controls to address residual risks remaining after engineering design is complete.

6. Layout philosophy

6.1. Overview

6.1.1. Safe layout design

Offshore equipment and systems arrangement should provide the following features in offshore facility design and layout:

a. Layout that separates high risk areas from personnel housing and emergency facilities.

b. Protected access to TR and emergency evacuation facilities.

c. TR separated from remainder of platform and designed to protect personnel from credible hazardous events.

d. Escape routes to facilitate personnel escape, evacuation, and rescue in event of emergency.

e. Wells, production, process, and pipeline facilities located to minimise risk.

f. Well ventilated and open production and process areas to minimise fire escalation and explosion risks.

g. Segregated large or high pressure hydrocarbon inventories to minimise risk of fire escalation.

h. Separation between releases from flare, vent, and drain systems and occupied buildings or other sensitive areas.

6.1.2. Living quarters (LQ) layout

a. Consideration should be given to locating LQ and emergency utility systems on a separate platform from production, drilling, risers, and gas compression facilities.

b. LQ platform should be bridge connected but at sufficient distance to minimise consequence of fires, explosions, and toxic releases onto quarters platform.

c. If separate platforms are not practical, a combined platform design may be required.

6.1.3. Low hazard area

a. Low hazard area should be provided that is separate from remainder of platform and designed to protect personnel and critical equipment from credible fire, explosion, and hazardous release events.

b. Low hazard area should be at the end of platform and upwind of production, drilling, process, pipeline, and flare facilities.

c. Facilities and equipment normally located in low hazard area include:

1. TR.

2. LQ.

3. Control room.

4. Firewater pumps.

5. Emergency switchgear.

6. Muster area (lifeboat muster locations).



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6.1.4. Fuel storage

a. Storage of diesel fuel, methanol, additives, and other potentially hazardous materials should be as far as practical from low hazard area.

b. With exception of diesel fuel tanks for diesel driven firewater pumps and emergency generators, potentially hazardous materials should not be stored within low hazard area.

c. Stored amount of hazardous materials onboard a platform should be kept to minimum needed for safe operation.

d. Both horizontal and vertical separation should be provided between potential ignition sources and systems containing or processing flammable materials.

6.2. Platform access

6.2.1. Emergency response access

a. Emergency response access should have the following features:

1. Access to all locations on platform designed to facilitate rescue of personnel.

2. Access to all remote activation panels or headers for fire protection systems and emergency shutdown (ESD)/isolation systems.

3. Access for firefighting.

b. Layout should facilitate personnel escape, evacuation, and rescue in event of emergency.

c. Emergency access routes from low hazard area to TR and muster area should be fully protected from fire hazards.

d. At least two emergency access (escape) routes should be provided from process, drilling, and other working areas, generally on opposite sides of the platform, as follows:

1. Highly exposed escape routes should be protected from high heat radiation levels.

2. Safe means of escape should be provided from enclosed spaces and open areas on both manned and normally unmanned platforms. This includes work areas, accommodations, and recreation areas.

3. TR and LQ areas should have ready access to helideck by at least two emergency access routes.

6.2.2. Operational access

Operational access should be provided to all:

a. Routine operated manual valves and local field instrumentation required for normal operation.

b. Isolation points required for emergency shutdown and isolation of operations.

c. Sample points, manual drains, and vents required for normal operations.

d. Equipment requiring routine inspection and surveillance (e.g., compressors, pumps, fin fans, etc.).

6.2.3. Maintenance access

Maintenance access should have the following features:

a. Equipment located with adequate access for crane lifts and mobile handling equipment during maintenance.

b. If elevated equipment requires crane handling, sufficient area to manipulate a boom, monorail, and/or trolley.



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c. Equipment layout should avoid need to lift heavy pieces of frequently maintained equipment during unit operation over in service process lines or equipment or provide passive protection.

6.2.4. Future equipment

Space allocation for planned future equipment should be addressed during initial project risk assessment to identify potential hazards associated with installation, operation, and maintenance of future equipment.

6.3. Platform design study

6.3.1. Hazard analysis

a. Potential hazards associated with process conditions, equipment layout, ignition sources, fuel sources, etc., should be considered during platform layout design stage.

b. Potential fire and explosion hazards should be identified and eliminated or minimised to the extent practical. Examples of how this may be accomplished include:

1. Module and equipment location selection.

2. Equipment spacing and orientation.

3. Ventilation (open modular or integrated deck design).

4. Early detection and isolation.

5. Fuel minimisation.

6.3.2. Hydrocarbon hazards

a. Assessment should be performed during layout development for potential for failure of equipment containing significant hydrocarbon inventories and critical structural elements (including main support structure). Examples include:

1. Firewalls, blast walls, explosion overpressure vent panels, etc., may be required to maintain integrity of platform low hazard area for a sufficient period to ensure evacuation of personnel (GP 44-70).

2. Firewater pumps, detection and alarm panels, shutdown logic panels, and other critical fire and safety system control equipment should be located in low hazard area.

3. Special consideration should be given to those installations that contain high concentration of toxic or corrosive materials, such as H2S or CO2, and/or abnormally high temperatures and pressures.

b. Heat radiation analyses should be performed at early phases of platform layout design regarding flares or ignited high pressure vents for worst case credible overpressure events to establish minimum separation distance from exposed areas on platform.

6.3.3. Explosion analysis

a. Explosion analysis should be used in developing platform layout.

b. Optimum blast wall locations can be determined based on results of explosion analysis.

c. Explosion analysis results can provide estimated effects of overpressure on structural design of walls, floors, and ceilings.

d. Mitigation options for explosion hazards may include:

1. Strengthening structural components to resist blast.

2. Reducing potential overpressures by improved ventilation.



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e. Consideration should be given to reducing confinement and/or congestion to reduce blast overpressure, improving ventilation, and deflecting blast away from critical areas.

f. Considerations to reduce confinement include the following:

1. Eliminating walls or using lightweight walls that relieve at low overpressure (e.g., loosely attached weather cladding).

2. Using blowout panels in walls, floors, or ceilings.

3. Using grating rather than solid plate for decks.

4. Using steel mesh rather than solid plate for heat shields.

5. Using louvered panels in walls.

6. Minimising number of obstructions in explosion vent path.

7. Overall platform layout

7.1. General platform design

7.1.1. General

Features in �7.1.2 through �7.1.4 are fundamental to achieving a safe and operable overall offshore platform layout.

7.1.2. Facility location

a. Location of wells, production, process, and pipeline facilities should be oriented to minimise exposure risk to personnel and adjacent facilities from potential events.

b. To the extent possible:

1. Open process areas

a) Production and process areas should be open and adequately ventilated.

b) Adequate ventilation is defined by API RP 500 as ventilation (natural or artificial) sufficient to prevent accumulation of significant quantities of vapour/air mixtures in concentrations above 25% of lower flammable limit (LFL).

2. Open sided modules

a) Open sided modules or integrated decks are preferred.

b) In extreme weather environments (e.g., Arctic) where enclosure is necessary, need for ventilating using concepts, such as partial enclosures, wind walls (including perforated plate type), and louvers, should be considered.

3. Large or high pressure hydrocarbon inventories should be separated to minimise knock on effects in event of an incident.

4. High and low risk equipment should be defined in an early design stage and be separated, with the higher risk equipment located maximum practical distance from low hazard area.

5. Unless piping is all welded construction, H2S process lines (above 250 ppm) should not be routed through enclosed areas with personnel access.

7.1.3. Flare and vent systems

Flare, vent, and drain systems should be released to a safe location as follows:

a. Flare or high pressure vent systems should be located downwind from low hazard area.



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b. Location of HVAC inlets and exhausts, engine air intakes and exhausts, control room air intakes, gas turbine air intakes, gas turbine exhausts, etc., should not vent onto escape paths or other normal operating areas.

7.1.4. Wellbay area

Wellbay area and risers should be located such that they are protected against impact from marine traffic as follows:

a. On production, drilling, and quarters (PDQ) platform designs, wellbay should be located within area outlined by platform legs.

b. Floating production facilities

1. On floating production facilities (where possible), wellbay should be located within perimeter of platform structure.

2. If 1. is not possible, risers should be protected against impact from marine traffic by location of berthing areas and berthing approach or by fender protection around risers.

c. Wellbay area should be naturally ventilated to maximum extent possible using barriers, floor grating, etc.

d. Facilities located within wellbay area should be limited to wellheads, flowlines, manifolds, and associated equipment.

e. Crude/gas risers and related first valve on/last valve offs (FVO/LVOs) should be located as far from low hazard area and emergency evacuation facilities as practical and protected from potential risks from falling objects, liquid hydrocarbon overflow, explosion, and flame impingement.

7.2. Typical platform layout options

7.2.1. General

a. Several typical platform layouts are provided in �7.2.2 through �7.2.5 to illustrate application of concepts in this GP.

b. Hazard evaluations and risk analysis should be performed to assist in evaluating tradeoffs for each design option (GP 44-30).

c. Selected platform configuration is in most cases site specific.

7.2.2. PQ platform

Typical arrangement for large production and quarters (PQ) platform is shown in Figures 1 and 2. Features of a PQ platform include:



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Figure 1 - PQ platform - topsides, south elevation

Figure 2 - PQ platform - topsides, east elevation

a. Production and compression modules in this design option are at the far end of the platform and downwind from low hazard area, providing maximum separation between higher hazard facilities (compression and process) and areas with occupied buildings and emergency response equipment.

b. Flare or high pressure vent header piping does not have to pass through wellbay area, further reducing risk of incidents that may damage the header and increase fire risk on platform.

c. Wellbay is closer to low hazard area but historically, wellbay area poses lower frequency events than compression or production areas.

7.2.3. PDQ platform

Typical arrangement for large production, drilling, and quarters (PDQ) platform is shown in Figures 3 and 4. Features of a PDQ platform include:



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Figure 3 - PDQ platform - production deck

Blast Wall

Low Hazard Area

Well Bay

Production and Compression Modules

Blast Wall

Low Hazard Area

Well Bay

Production and Compression Modules

Figure 4 - PDQ platform - elevation

Production and

Compression

Drilling

Low Hazard Area

a. Production and compression modules in this design option are at the far end of platform and downwind from low hazard area, providing for maximum separation between higher hazard facilities (compression and process) and areas with occupied buildings and emergency response equipment.

b. Flare or high pressure vent header piping does not have to pass through wellbay area, further reducing risk of incidents that may damage header and increase fire risk on platform.

c. Drilling and workover facilities are closer to low hazard area, but personnel working in production/compression areas are further away from low hazard area and pass through wellbay area in an emergency.



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d. Integrated PDQs often require large numbers of personnel due to labour intensive drilling operations, which puts higher number of personnel at risk from potential hazards of production module.

e. PDQs are not the most inherently safe design option and, in general, such integrated PDQs should be avoided.

7.2.4. Alternate PDQ platform

Alternate general arrangement for large PDQ platform is shown in Figure 5. Features of this alternate arrangement include.

a. Wellbay is at far end of platform but still downwind of low hazard area.

b. Distance between wellbay area and low hazard area is maximised.

c. Compression/production operating personnel are closer to low hazard area and do not have to pass through wellbay area during emergencies.

d. Higher frequency event facilities (compression and process) are closer to low hazard area.

Figure 5 - PDQ platform - alternate arrangement

e. Flare and high pressure vent piping cross wellbay area, posing risk of header damage in event of an incident in wellbay area.

7.2.5. FPSO

Figure 6 presents a general arrangement for floating production designs based on a floating production, storage, and offloading (FPSO) vessel. Features of an FPSO include:

a. Risers are located on either side of the vessel to aid in vessel stabilisation.

b. Subsea drilling is performed separately with no drilling or workover facilities required onboard the platform.

c. Process area is at the opposite end of platform from low hazard area.



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d. Storage of crude and other materials is below deck in vessel hull compartments.

e. Work vessel berthing is a safe distance from well risers.

Figure 6 - FPSO - functional diagram

f. Crane operation is outside riser envelope to minimise drop object risk to risers.

g. Flare (or high pressure vent) is at opposite end of vessel from low hazard area.

8. Platform decks and systems layout

8.1. General

a. Requirements on layout of platform decks, layout of various functional areas on each deck, and integrated systems, such as fire and blast protection and emergency egress pathways, is provided in this clause.

b. General requirements are provided for how areas of the facility should be placed with respect to other areas, which areas are appropriate to be grouped together, and which areas should be separated from one another.

c. For some equipment, specific layout details are provided, such as separation distances to other equipment.

8.2. Platform orientation and elevations requirements

a. A number of factors can affect orientation of an offshore platform, including local wind and sea conditions, subsea topography, routing of subsea pipelines, and tender vessel mooring requirements.

b. Local prevailing winds and sea conditions typically determine the final orientation of an offshore platform.

c. In any case, offshore platform low hazard area should be upstream of prevailing wind direction from flares, vent plume, and all equipment containing hydrocarbons that can release hydrocarbon vapour on loss of containment.

8.3. Decks

8.3.1. Production deck

a. Production deck is the deck level where most process equipment is located.

b. Minimum elevation of production deck is at design wave height plus appropriate allowances above mean sea level (MSL).



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c. In some designs, such as a semisubmersible with large topsides and hull, it may be advantageous to locate quarters below production deck if quarters can be located such that they are protected by structural support and location from explosions, thermal radiation, smoke, and gas.

8.3.2. Main deck

a. Main deck (or weather deck) is generally from 6 m to 10 m (20 ft to 33 ft) above production deck.

b. Drilling rig or workover rig, platform cranes, primary laydown areas, and platform living quarters are generally located on main deck level.

c. Platforms with simple process equipment and no living quarters may have a combined production and main deck (i.e., single deck).

8.3.3. Other decks

Platforms may have other intermediate deck levels that cover all or only a portion of platform length or width, including the following:

a. Cellar deck

1. Cellar deck is directly below production deck.

2. Cellar deck level may contain pig launchers and receivers, potable or fresh water storage tanks, closed drain vessel and transfer pumps, selected process and utility equipment, and other miscellaneous items.

3. If cellar deck is exposed to storm waves, inclusion of tanks and process vessels should be avoided.

b. Seadeck

1. Seadeck is lowest deck on the platform.

2. Seadeck should be at least 3 m (10 ft) above MSL.

3. Purpose of the seadeck is to provide access (boat landings) and/or platform support structure inspection.

4. On floating production facilities, this is the berth platform level.

c. Mezzanine decks

1. Mezzanine decks are intermediate deck levels between production and main platform deck levels and cover either a portion or entire platform area.

2. Mezzanine level provides additional area for equipment and/or access to equipment located on production deck.

d. Helideck

8.4. Decking and stairways construction

a. Options for decking material include solid decking (pattern floorplating, such as chequer plate or nonskid coated plate) or open decking (grated decking).

b. When choosing between open decking and solid decking, the following points should be considered:

1. Use of open decking allows induced updraft in the event of a fire. Induced draft aids in protection of process equipment adjacent to fire and reduces toxic smoke production, but also increases the concern of flame impingement and fire damage of equipment above fire.

2. Use of open decking yields lower strength explosion overpressures.



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3. Use of open decking improves natural ventilation.

4. Use of solid decking promotes containment of spills.

c. Final consideration should be based on benefits and concerns analyzed through fire and blast studies.

d. If dropped object damage and mud spills are a concern during drilling, temporary, removable wellhead hatches made from plate may be considered as alternative.

e. Each deck level around platform perimeter should have open decking walkways. Potential exceptions include:

1. Areas where crane access to lower decks may be blocked by walkways.

2. Materials laydown and work areas where plating is more appropriate to protect against drops and spills.

f. Stairways connecting each deck level should be provided (minimum of two per deck level).

g. For manned platforms, external stairways near each corner of platform at each deck level (except sea deck) should be provided.

h. Additional stairways may be required for larger platforms.

i. Layout should comply with requirements for normal equipment and personnel traffic, security, emergency evacuation, firefighting, and access for operation, maintenance, and workovers.

9. Potential low hazard area

9.1. General

a. Low hazard area should be designated on platform for location of LQ, TR, and main control rooms (MCRs).

b. Low hazard area should be upwind and at extreme end of platform, with maximum possible distance from drilling, production, and process facilities.

c. Workshops, switchgear, and MCCs may be located in low hazard area.

d. Location of low hazard area should comply with the following criteria:

1. Orientation should normally be upwind of hazardous facilities, including drilling, production, storage, gas compression, flow lines, and transfer equipment.

2. Low hazard area should be outside hazardous areas and may not be above crude oil storage tanks, process areas, or other large inventories, such as risers or wellheads.

3. Location of LQ on a separate platform with bridge connected to hazardous areas should be given careful consideration.

4. The only equipment permitted in low hazard area is safety and evacuation equipment, central control panels, uninterruptible power supply (UPS), emergency power generation equipment, and nonhazardous platform utilities (e.g., compressed air).

5. Process equipment or utilities handling combustibles, such as heating medium oil, should not be within or below low hazard area.

6. Storage of diesel fuel in low hazard area should be limited to day tanks for firewater pumps and emergency generators.

7. Diesel fuel piping should:

a) Be as short as practical.



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b) Contain minimum number of flanges.

c) Have emergency isolation.

d) Be operated at lowest practical pressure.

9.2. Buildings within low hazard area

Buildings within low hazard area may include LQ, TR, MCR, emergency switchgear, MCC, and other emergency support facilities that do not pose a hazard to other low hazard area. Specific requirements for buildings within the low hazard area include:

a. Firewalls or blastwalls should be constructed to protect occupied buildings within low hazard area, or the buildings should be designed for credible fire and blast loads in accordance with GP 04-30. A holistic design approach is required, because blast and fire barriers may impair natural ventilation, leading to increased risk of gas cloud development and increased blast overpressure.

1. Firewalls should be designed:

a) To comply with hydrocarbon fire test requirements (H rated).

b) For a minimum H-60 rating, but this requirement may vary, depending on estimated evacuation duration for the platform. This also applies to combined fire and blast walls.

2. Blastwalls should comply with design or evacuation event blast loads predicted by explosion analysis, in which case wall may deform but should not be breached by blast pulse.

3. Firewall and blastwall may be combined into a single wall design.

4. Firewalls built into exposed wall facing process/drilling areas should not have windows or penetrations.

5. Number of doors and windows in other firewalls (not directly facing high hazardous equipment) should be minimised.

b. Floor, roof, and walls of buildings in low hazard area should be sealed/protected against flame and/or smoke ingress and may also have designated H ratings.

c. Emergency escape of personnel from LQ or MCR to TR or muster area following a major accident should be demonstrated, including escape from these buildings (number of exits, location to avoid major accident effects) and escape routes to TR.

d. Fire loads from helicopter crash or helifuel incident should be considered if LQ, MCR, or TR is beneath or near helideck.

e. Local, not normally manned control rooms and drilling facility controls may be located in hazardous areas and adjacent to respective equipment where appropriate.

f. LQ, MCR, TR, switchgear, and MCCs should be pressurised with air intakes in a safe location.

g. Combustible gas detection instrumentation should be installed in HVAC intakes to alarm and shutdown HVAC systems upon gas detection at preset percent of lower explosive limit (LEL).

h. If potential toxic releases can occur (sour platforms), toxic gas detectors may also be installed in HVAC intakes to alarm and shutdown air intake at predetermined concentration levels.

i. Workshops



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1. Workshops, storerooms (warehouses), offices, etc., may be adjacent to LQ, MCR, or TR and should be located in protected area on platform (e.g., behind firewall or blast wall) whenever practical.

2. Workshops housing equipment that is a potential ignition source and located in hazardous areas should be pressurised or purged with air from a safe location.

3. Workshops should have protection from immediate effects of a major accident for any personnel who may be in enclosure.

4. Workshops should be located to allow time for personnel to escape from immediate effects of a major accident to designated muster area or TR.

5. Workshops should not be in hazardous areas.

6. Air intakes on workshop HVAC systems should be located in low hazard areas to minimise possibility of toxic gas ingress.

7. Workshops should have safe protected emergency access to TR and muster areas.

j. Temporary stores

1. Temporary stores housing explosives should be located on outer edge of deck away from low hazard area and critical escape routes.

2. Temporary stores should be maintained under lock and key, accessible by deck cranes, and capable of being jettisoned.

3. Temporary stores housing radioactive material should be suitably located but securely attached to deck floor.

4. Stores housing explosive or radioactive material should be marked with warning signs.

k. Utility enclosures

1. Utility enclosures should be located to allow time for personnel who may be in the enclosure to escape immediate effects of a major accident to designated muster area or TR.

2. Utility enclosures should have protection from immediate effects of a major accident for any personnel who may be in enclosure.

3. Utility enclosures should perform hazard management role of ignition prevention by preventing ingress of flammable gas to areas where nonrated equipment may be operating.

4. Utility enclosures should be outside of hazardous areas, if possible.

5. It shall be demonstrated that personnel are able to escape to TR or muster point following major explosion or fire event

6. Explosion protection

a) Unless a separate blast barrier is provided, utility enclosures located in close proximity to risk of explosion should have sufficiently robust boundary walls and doors to withstand impact of identified design or evacuation event blast loads predicted by explosion analysis (see GP 24-22).

b) Boundary may deform but should not be breached by blast pulse.

c) It shall be demonstrated that personnel inside will not be injured by such explosive events.

7. Passive fire protection



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a) Boundary walls should have passive fire protection coating or fire rated walls as necessary to withstand effects of direct jet flame/pool fire loads identified for design or evacuation events over period considered necessary for escape to TR (see GP 24-22).

b) Passive fire protection includes requirement for heat insulation to avoid intolerable heating inside the building.

c) It shall be demonstrated that personnel inside will not be injured by such fire events.

9.3. Temporary refuge (TR)

a. TR design should provide protection for all personnel from immediate effects of a major accident and delayed effects for specified endurance period.

b. Environment inside TR should not be impaired by immediate damage due to explosion or delayed impairment due to heat or ingress of smoke, flammable gas, or other toxins. This provides a safe atmosphere such that it is possible for rational behaviour and decision making to take place.

c. Location

1. TR for integrated facilities should be in close proximity (50 m [165 ft]) to production plant, risers, drilling, or dry wellheads.

2. TR should be located in area of least risk, which is likely as low as possible (cellar deck level) on upwind end of installation.

3. Lifeboats should be where TR structure provides protection, which is likely on the lowest level close to TR boundary and facing away from hazardous areas.

4. TR for FPSOs should be at opposite end to that of risers and high risk process plant. This applies whether vessel is turret moored or spread moored.

5. Distance between primary hazards and TR should be maximised to the extent possible, with consideration given to maximising this distance during early design phases.

d. Other features

1. Entry doors should be easily accessible for personnel escaping from other areas and protected from heat radiation as necessary.

2. TR should have a suitable muster area with sufficient room for personnel to prepare for evacuation.

3. TR should have a central control room capable of providing feedback of information from process systems, fire and gas detection (GP 30-85), ESD systems, and other systems necessary for incident controller to understand the nature of a major accident and judge whether to order evacuation or remain on board while incident is brought under control and plant stabilised.

4. TR should have a public address (PA) broadcast facility to ensure that incident controller can keep everyone informed of developments and plans for evacuation or provide instructions to remain on board.

5. TR should have access to primary evacuation facilities (lifeboats) as a minimum at any time during endurance period and without exposing personnel to major accident effects (heat, gas, or smoke).

e. Stairwells and elevator shafts for machinery spaces or utility rooms should not enter TR space. This is to avoid smoke ingress to TR from machinery fire.



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f. TR should have mechanical ventilation sufficient to provide breathable air during endurance period.

g. Air intakes

1. TR shall have two air intakes.

2. Air intakes should be located low down on the face of TR in nonhazardous areas and furthest from hazardous areas.

Smoke and gas dispersion analysis has indicated this is the location least likely to be affected by a large process gas release or smoke from a fire.

h. TR and LQ combined

1. TR and main LQ may be a combined building.

2. If part of an LQ building is to be designated as TR, then TR boundaries (including decks below and above) should have an effective seal to prevent ingress of smoke or gas and in some cases heat.

3. TR HVAC system area shall be separate from that of LQ such that it does not draw on air within parts of LQ outside TR.

10. Emergency escape

10.1. General

a. Access routes from low hazard area to TR and muster area should be fully protected from fire hazards.

b. Escape routes should be behind and protected by H rated firewalls, but additional heat shields or firewall extensions may be necessary to provide full protection.

c. At least two emergency access routes from LQ to emergency assembly area should be provided, each located on opposite sides of the platform.

d. Escape routes to low hazard area may require protection from direct exposure to intense heat.

e. Firewalls or heat shields may be used, but care should be taken not to significantly reduce natural ventilation.

10.2. Muster areas and evacuation facilities

a. Muster area is designated area on platform for final assembly of personnel before evacuation.

b. Muster areas are typically located adjacent to lifeboats for fast efficient platform evacuation.

c. Main muster area should be clearly identified within TR such that all personnel can be made aware of where to assemble in an emergency.

d. Means should be provided for personnel to be kept informed during an emergency and for direct, reliable, and two way communication with incident control area as follows:

1. Communications with shore base, other installations, external emergency, and rescue services should be reliable such that communication with these services is always available.

2. Drilling module and lifeboat stations should have communications link.

3. Muster area should have facilities to raise alarms, evaluate, and monitor an incident.

4. Functions should be provided to control and mitigate effects of an incident.



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e. Muster area should have sufficient space to enable emergency command personnel to make effective and informed decisions regarding incident control, manage emergency response teams via radio, and organise controlled evacuation.

f. Muster area should be sufficient for emergency firefighting teams to assemble and don fire suits, breathing air, etc.

g. Lifeboat embarkation points should be clearly marked and have adequately protected access.

h. Muster area should have sufficient free floor area to accommodate maximum number of personnel on board and allow donning personal protection equipment (PPE) (e.g., breathing air, fire gear, survival gear). Floor area should be at least 0,75 m2 (8 ft2) per person.

i. Main muster area should have additional lifejackets and “grab bags” to cover those personnel who may be unable to obtain their own set of PPE if required for possible evacuation.

j. Provision should be made for monitoring air quality in enclosed muster areas (portable CO2 detector).

10.3. Alternative muster area

a. Alternative muster area (AMA), if necessary, should provide muster facilities and protection from immediate effects of major accident and delayed effects for specified endurance period for a defined number of personnel.

b. AMA should be considered if some personnel may not be able to move along egress route to TR under some major accident conditions.

For example, a major accident in centre section of an FPSO may render all routes to TR impassable, often due to a natural human reluctance to approach such an incident.

c. If AMA may be subject to major accident effects similar to those determined for TR, enclosed space should be designed to same standards as TR.

d. AMA may be open shelter if this is acceptable under accident conditions for which it may be used.

10.4. Open shelter

a. Open shelter design, if appropriate, should provide muster facilities and protection for a defined number of onboard personnel from radiated heat effects of a major accident for specified endurance period.

b. If personnel are not accomodated on the facility and it can be shown that they would be able to survive major accident effects for specified endurance period, open shelter for the primary muster area may be acceptable instead of a TR.

Open shelter will generally provide protection against radiated heat but not gas or smoke.

c. Open shelters should have communications facilities for contact with shore base, other installations, external emergency, and rescue services. Reliability should be such that communication with these services is always available.

d. Open shelters should have safe and protected access to sea for evacuation in emergency, with type of facility a project decision based on number of personnel and likely prevailing environmental conditions.



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10.5. Evacuation facilities

a. Design should allow all personnel to evacuate from facility under emergency conditions without undue exposure to effects of major accident (heat, smoke, or gas) during specified endurance period.

b. Evacuation facilities

1. At least one egress route should be available for personnel sheltering in TR muster area to reach evacuation facilities (totally enclosed motor propelled survival craft [TEMPSC]) under all identified accidental event conditions.

2. At least one egress route should be available under all relevant identified accidental event conditions for all personnel who may be required to take refuge in AMA.

c. Egress routes

1. Emergency evacuation egress routes should be wide and high enough to allow rapid egress of personnel.

2. Routes should have adequate width and height to allow transit of stretchers.

3. Landings and changes of direction should be avoided.

4. Emergency egress routes should be readily accessible, unobstructed, nonslip, marked and signposted and have markings and signs that are clearly visible if there is loss of artificial lighting during darkness.

5. Routes should be clearly marked, with illuminated and/or photoluminescent direction signs showing route to lifeboats.

6. Doors should be designed for opening by one person from either side.

7. Hinged doors should open in the main direction of evacuation.

8. Sliding doors should show direction of opening on both sides of the door.

10.6. Lifeboats or escape craft

a. Lifeboats or other escape craft should be located adjacent to muster area.

b. Unimpeded visual contact between lifeboat launch stations is preferred.

c. Large platforms and platforms located in frequent severe wave environments may require lifeboat and life raft launch stations at several locations around the platform.

d. Launch mechanisms should provide lifeboat with adequate clearance from any fixed object throughout descent path and at sea level.

e. Davit launched life rafts (DLLRs) may be required in accordance with local regulations on normally manned platforms to enable escape directly from process area.

f. Special considerations are necessary to provide for personnel evacuation by helicopter for facilities handling hydrocarbons containing heavier than air gases (H2S, CO2, etc.).

10.7. Helideck

a. Helideck should be designed in accordance with local regulations and reviewed by BP aviation services or a qualified aviation consultant early in the project planning process.

b. Helideck should be oriented to extent practical to take advantage of predominant prevailing wind.

c. Helideck should have unobstructed access for landing and takeoff areas.

d. Helideck should have unobstructed dropdown zone from outer edges of helideck for at least 180 degree splay of landing/takeoff sector to sea level.



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10.8. Boat landings and cargo transfer areas

a. Boat landings (if provided) should be located on sheltered side of platform based on prevailing weather conditions.

b. Cranes and cargo laydown areas should be located to optimise favourable vessel motions during cargo transfer.

c. Cargo vessel positioning should minimise potential for vessel impact on platform in event of vessel engine failure.

10.9. Emergency fire protection equipment in low hazard area

a. Active and passive fire protection systems and fire and gas detectors should be located in low hazard areas such that maintenance activities can be performed while platform is active (GP 24-23).

b. Firewater pumps should be located in low hazard area and separated by adequate distance and/or by firewalls to avoid potential of a single fire/explosion in low hazard area rendering firewater pumps inoperable (GIS 24-233).

c. Firewater pump engine air intakes should be located in well ventilated locations to reduce possibility of smoke or hydrocarbon vapour ingestion.

10.10. Firewalls and blastwalls

a. Firewalls used to segregate low hazard areas and buildings within low hazard area from process equipment and other hazardous exposures should comply with the following:

1. Firewalls should have no firedoors or other openings.

2. Structural elements within firewalls should be fully fire protected.

3. Penetrations of low hazard area firewall should be minimised.

4. Penetrations that are absolutely necessary should be totally sealed to prevent flames, heat, and smoke ingress into low hazard area and quarters.

b. Blastwalls

1. Blastwalls may be required to segregate potential sources of overpressure from other process equipment, utility systems, and/or low hazard areas.

2. Need for and location of blastwalls should be determined during explosion studies performed in early platform design stage.

3. Blastwalls should be fit for purpose and therefore may vary significantly in materials of construction, dimension, and shape.

c. Combination firewall and blastwall

1. Blastwall may double as firewall if it complies with a.

2. Combination firewalls and blastwalls should be designed such that distortion from blast overpressure does not impede function of fire protection insulation.

3. Equipment should not be attached to or located adjacent to blastwalls.

11. Potential high hazard areas

11.1. Wellbay area

a. Platform wellbay area contains wellheads, manifolds, and flowlines.

b. Wellbay area is generally on main deck and on larger platforms is separated from production equipment.



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c. Splash walls are typically used for protection against contamination of other areas from drilling fluids but do not provide protection against fire or overpressure.

d. Wellbay area of main deck for drilling and workover rigs should be clear of permanent equipment for full width of platform.

e. Wellbay area should be accessible for personnel escape and firefighting from both sides of platform.

11.2. Wellhead area

11.2.1. Spacing and dimensions

a. For combination drilling/production platforms, wellhead area location and size are determined by type of drilling or workover rig and number of wells drilled.

b. Actual spacing of wells depends on drilling rig and wellhead to be used.

c. Wells can be laid out on a rectangular or circular grid.

d. Wellhead layout is typically rectangular.

e. Circular grid is more common if ice flows or mudslides are a consideration or wellheads are located inside legs of condeep (concrete deepwater) type platforms.

f. Minimum well spacing is as follows:

1. For rectangular wellhead spacing, minimum required grid is 2,3 m by 1,5 m (7,5 ft by 5 ft) centre to centre in each direction to provide adequate clearance for access to all wellheads.

2. For rectangular arranged wellheads located along parallel rows, minimum spacing between rows of wellheads should be:

a) 3 m (10 ft) for two rows.

b) 2,3 m (7,5 ft) for three or more rows.

3. For circular pattern within one platform leg, wellheads can be laid out to fit every 0,6 m to 0,9 m (24 in to 35 in) around circumference.

g. Spacing and configuration of wellhead areas depend on:

1. Dimensions and shapes of specific components required for tree and flowlines.

2. Whether wells are to be completed as single zone or dual zone.

11.2.2. Wellhead pressures

Wellheads usually contain the highest pressures on an offshore platform. Minimum requirements necessary for protection against potential damage to or from the wellheads are as follows:

a. Wellhead area should be protected against impact from fires or explosions resulting from failures elsewhere on the platform.

b. Wellheads should be protected against dropped objects from crane lifts and other construction activities.

c. Remainder of the platform should be protected against potential failures in the wellhead area. This is usually accomplished by providing a firewall to separate wellhead area from rest of the equipment. Production manifold may be located within the firewall.

d. No equipment should be located in wellhead area other than wellhead fittings (including wing valves), flowlines, individual gas lift, gas injection, well kill, water or chemical injection lines, and parts of platform safety systems that serve wellhead area.



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e. Process piping required to traverse wellbay area should be routed outside wellhead area.

f. Valves (other than wing valves), instruments, vent lines, and drain lines should be outside wellhead area if practical.

g. Clearance should be provided above wellheads for wireline blowout preventer (BOP) installation.

h. Injection manifolds

1. Manifolds for chemical injection, gas injection and lift, water injection, well kill, and blowdown of wellhead piping systems are permitted in production deck wellbay area but should be outside wellhead area.

2. Manifold should be at least 4,6 m (15 ft) between outside well rows and skid trusses.

i. Well control panels are permitted in production deck wellbay area.

j. Safety equipment specific to protection of wellhead area is permitted in surrounding wellbay area.

k. Test separators may be located in wellbay area if they do not restrict explosion venting in wellhead area.

11.3. Drilling rigs

11.3.1. General

a. Drilling rig size and selection may vary depending on size of platform and drilling programme.

b. Spacing and layout requirements depend on drilling rig selected and required service components.

c. Drilling rig options include the following:

1. Self contained drilling rig integral to platform.

2. Self contained drilling rig either packaged in modules or handled as individual components that can be set and removed via derrick barge or platform cranes.

3. Derrick set temporarily installed onto platform and tender assisted by floating vessel or jackup.

4. Drilling from jackup temporarily positioned over portion of platform.

11.3.2. Drilling rig design and layout

a. Hazards analysis and risk assessment should be performed to analyse potential hazards associated with a specific drilling rig option selected in consideration of the following:

1. Drilling rig installation.

2. Drilling rig operation (particularly with simultaneous drilling and production), including drilling, completions, and workovers.

3. Drilling rig maintenance.

4. Transfer of drilling materials and equipment to and from workboats.

5. Operation during bad weather.

b. Spacing and layout should take required service components into consideration, including power, storage of supplies, and additional personnel quarters.

c. Drilling related platform interfaces that are typically required should be considered, such as disposal chutes/downcomers, drain tie ins and sump location, vent lines, consumables loading station, and crane access.



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d. Rig equipment should be arranged to maximise access to major escape routes and minimise alleyways with only a single escape route.

e. Adequate main deck space should be allocated for drilling service company instrumentation/data processing units for mud logging, measurement while drilling (MWD), and auxiliary wireline services.

f. Deck space may be needed for cement unit, associated equipment, and mud lab.

g. Mud logging unit should be as close as practical and safe to shale shakers.

h. Diverter system should be arranged in accordance with API RP 64.

i. Adequate layout and location of major drilling rig components is required for safe operation and emergency response, including:

1. Well control equipment.

2. Choke/kill manifold.

3. Choke control panel.

4. Mud/gas separator.

5. Gas discharge line.

6. Trip tank.

7. BOP closing unit and control panels as follows:

a) At least two BOP control panels are required.

b) One BOP panel should be located on rig floor near driller console.

j. On self contained drilling rigs or tender rig derrick sets, independent offshore fire protection system, alarm and ESD systems, relief, flare, vent, and drain systems should comply with platform minimum requirements.

k. Independent systems listed in j. should be integrated with overall platform fire protection system, alarm and ESD systems, relief, flare, vent, and drain systems (GP 04-10).

11.3.3. Reservoirs containing H2S

a. Hazard and operability (HAZOP) and risk assessment study for reservoirs that contain H2S is recommended to address possible H2S release.

b. Equipment should be arranged to mitigate or minimise risk to personnel.

c. Rig components should be located upwind to permit prevailing winds to blow across rig in a direction that will disperse vented gas away from low hazard area and/or tender vessel.

d. If potential release of H2S may exceed atmospheric concentrations greater than 20 ppm, locations of potential H2S release should have mechanical blowers to disperse vapours. Blower ventilation should be considered for the following areas:

1. Rig floor.

2. In low and confined areas, such as under derrick substructure and adjacent wellheads and BOP stack.

3. At shale shakers.

4. Above open mud tanks.

e. Rig layout and auxiliary equipment, including primary and remote auxiliary choke control panels, remote kill lines, mud/gas separators, degassers, and flare system, should comply with API RP 49.



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11.3.4. Electrical equipment

a. Electrical equipment associated with drilling rig, if located in Class 1, Division 1 or Zone 1 area, should be explosion proof.

b. Electrical area classification for drilling rig should comply with API RP 500 or API RP 505.

11.4. Pipeline equipment

11.4.1. General

Pipeline equipment includes risers, FVO, LVO, and facilities, such as pig launchers, receivers, and associated kicker line piping and valves.

11.4.2. Risers and FVO/LVOs

a. Risers and FVO/LVOs should be located as far from low hazard area as practical.

b. To prevent damage to valves, actuators, and instrumentation, FVO/LVOs should be located in areas to minimise potential risks from falling objects, liquid hydrocarbon overflow, explosions, or flame impingement.

c. FVO/LVOs should generally be located in vertical portion of risers below production deck and consideration may be given to locating these valves at seadeck level to reduce exposure to riser leak.

d. If FVO/LVOs are located at seadeck level, access and/or maintenance platforms will be required and valve instrumentation should be protected from storm waves and corrosion.

e. FPSOs

1. If flow lines (risers) connect to platform from over side of hull on floating production platforms (e.g., FPSOs), FVO should be located as close to edge of platform vessel as possible.

2. Platform should be protected against uncontrolled loss of containment in event of riser failure upstream of FVO.

11.4.3. Pig launcher/receiver equipment

a. Lateral and vertical access and maintenance space should be provided for pig launcher, receiver facilities, and pig handling equipment.

b. Launchers and receivers should be located away from wellbay area, higher risk process equipment, known ignition sources, highly travelled personnel routes, and material handling areas.

c. Launcher or receiver doors should face outboard and away from quarters or low hazard areas to reduce potential of exposing personnel or other equipment to projectiles.

12. Equipment layout

12.1. Arrangement of equipment

Arrangement of offshore platform equipment may vary depending on type of equipment required and design basis for platform, with the following equipment layout considerations:

a. Similar equipment (except firewater pumps) should be grouped if practical.

b. Separation of equipment containing large inventories of combustibles (such as oil/gas separators) should be considered to reduce risk of escalating events.



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c. Equipment should occupy minimum space consistent with function, maintenance, operational, and inspection access requirements.

d. Process equipment should be arranged and oriented in a manner consistent with main process flow to minimise length of piping runs.

e. The following support structures and equipment should be considered during design and layout:

1. Platform access to remote valves, instruments, and safety relief valves.

2. Protective frames around equipment with crane lift risk.

3. Eyewash stations and safety showers adjacent to chemical and acid handling units.

4. Monorails to assist dismantling during routine maintenance.

5. Operator control stations and local instrument panels.

6. Enclosures around engines.

7. Deck hatchways and porches for lifting access to equipment below.

8. Small diameter drain and vent piping.

9. Equipment auxiliaries, such as pump seal systems.

f. Areas around equipment should be designed to allow maintenance, such as disassembly of pumps and compressors.

g. Maintenance areas in f. should not interfere with escape routes.

h. Material in transit should have laydown areas in locations readily accessible by crane.

i. Crane location should be selected such that equipment loaded to or from supply boats is not lifted directly above process equipment.

j. Permanent overhead lifting points or monorails should be provided to facilitate horizontal traverse of heavy items to laydown areas for crane access.

12.2. General piping arrangement (API RP 14E)

a. Piping should comply with ASME B31.3 and applicable BP piping specifications.

b. Piping should generally be routed in north/south and east/west directions and grouped together for piping support purposes.

c. Clearance should be provided for maintenance access and personnel protection as follows:

1. Expansion loops between piping and vessels, piping in piperacks, pipe flanges, and other equipment.

2. Headroom over access routes or access platforms.

3. Accessibility for suitable support points and valve orientation.

4. Clearance for operation and accessibility.

5. Clearance to permit removal of inline equipment with minimal dismantling of equipment.

6. Extra space for piping insulation.

d. Piping should not be located near explosion vent areas, since an explosion will produce high gas velocities and hence high drag forces on piping at such locations.

e. Process piping should not be routed through nonhazardous areas. If necessary to route piping in low hazard area, piping should be:

1. Appropriately labelled.



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2. Protected from dropped objects.

3. Welded construction.

4. At least 38 mm (1.5 in) nominal diameter.

12.3. Layout and spacing

12.3.1. Vessels and exchangers

a. To permit access to instrumentation, maintenance, and visual inspection, minimum of 1 m (39 in) around vessel and heat exchanger footprints is recommended.

b. Horizontal vessels handling hydrocarbons should be oriented such that vessel heads point toward open sides of platform.

c. Large vessels should be located such that they do not block major explosion venting paths.

d. Sufficient clearance should be provided around shell and tube exchangers to permit removal of tube bundles for maintenance, inspection, or replacement.

e. Unless equipment is part of exchanger system, equipment should not be installed immediately under aircooled heat exchangers.

f. Equipment located near aircooled heat exchangers should not impede exhaust air stream above exchanger.

12.3.2. Rotating equipment

a. Large rotating equipment, such as compressors, condensate pumps, and main oil line (MOL) pumps, should be located in well ventilated areas and as far from low hazard area as practical.

b. Rotating equipment layout should permit maintenance, removal, and replacement of rotors and other major components.

c. Vertical pumps should have access, clearance, and lifting capability (preferably with platform crane).

d. Gas turbine air intakes should be located and arranged as follows:

1. As high an elevation as practical to minimise salt ingestion.

2. Arranged to avoid intake or recirculation of exhaust air from air fin heat exchangers.

e. Gas turbine exhaust stacks should be located at least 6 m (20 ft) vertically from inlet air system to avoid recirculation of hot exhaust gases.

f. Gas turbine cooling

1. Gas turbines should be enclosed, cooled, and ventilated by forced, filtered air.

2. If cooling air is not drawn from a safe location, gas detectors should be located in inlet and exhaust air passages.

3. If air is drawn from low hazard area, gas detectors should only be located in exhaust air passages.

4. Alarm and shutdown should be provided on high concentration of combustible gas in air inlet or exhaust air passages.

g. Effects of gas turbine exhaust plume on helicopter and crane operations should be considered in selecting location for gas turbine exhaust outlets.



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12.3.3. Area classification, electrical equipment, and utilities (API RP 14F)

12.3.3.1. General

a. Areas of offshore platforms should be classified for purposes of selection and installation of electrical equipment in accordance with API RP 500 (GP 44-60) or API RP 505.

b. Either API RP 500 or API RP 505 can be used but not both on any single platform facility.

12.3.3.2. Exceptions

Practices described in API RP 500 or API RP 505 should be complied with except as follows:

a. API RP 500, 5.5, or API RP 505, 5.5: Areas of offshore platforms will generally be electrically classified as Class I (flammable gases), Group D [Group IIA] (hydrocarbon) hazards, except that Group C [Group IIB] (H2S) classification may apply to platforms that handle sour gases.

b. API RP 500, 6.3.2.4.8, and API RP 505, 6.6.2.4.8: Adequate ventilation of enclosed areas is described in API RP 500, 6.3.2.4, or API RP 505, 6.6.2.4, except that method described in API RP 500, 6.3.2.4.8, or API RP 505, 6.6.2.4.8, for calculating required ventilation rate based on estimated rate of fugitive emissions within enclosure should not be applied.

c. API RP 500, 6.5, or API RP 505, 6.8, should not be applied in use of gas detection equipment to allow less stringent electrical classification of an area.

d. Division 1 [Zone 1] areas should include the following in addition to those specified in API RP 500 and API RP 505:

1. Production deck areas within 3 m (10 ft) of wellhead.

2. Entire area on wellhead side of wellbay barrier walls or within 3 m (10 ft) of wellhead grating on main deck.

3. Areas within 3 m (10 ft) of pipeline launcher, receiver barrel enclosures, and flammable storage tank vents.

e. Division 2 [Zone 2] areas should include the following in addition to those specified in API RP 500 or API RP 505:

1. Adequately ventilated general process areas.

2. Adequately ventilated areas of production deck that are greater than 3 m (10 ft) from wellheads, unless separation walls are provided.

3. Process areas on opposite side of wellbay barrier wall.

4. Gas compression modules.

5. MOL pump modules.

f. Areas in e. may require a Division 1 [Zone 1] classification in accordance with API RP 500 due to other equipment installed in the area.

g. Alternate area classification method in Appendix D of API RP 500 and API RP 505 should not be used.

h. If approved by applicable electrical specification and industry code, devices that are not intrinsically safe or otherwise unsuitable for installation in Division 1 or 2 [Zone 1 or 2] areas may be installed within suitable purged/pressurised enclosures within those areas.

i. Ventilation air for enclosures that are purged or pressurised for electrical area classification purposes should be ducted from unclassified areas.

j. Electrical generators for normal platform power should be located outside low hazard area and should be as remote from process as practical.



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k. Switchgear and MCCs may be located outside low hazard area and should be housed in pressurised enclosures with humidity control.

l. Generators should be enclosed for noise control and cooled by forced, filtered air (unless watercooled).

m. Electrical equipment associated with platform control and safety systems, including backup power supplies, should be located in low hazard area, except for end devices, etc., which are distributed throughout platform.

n. Platform operating areas of normally manned platforms should be well illuminated such that night operations do not normally require use of flashlights.

o. PA points and platform telephone/page system should be distributed at strategic locations on manned platforms and sound attenuation phone booths provided in noisy areas.

p. Breathing air facilities

1. Manned platforms handling toxic gases (H2S concentrations above 250 ppm) should have breathing air facilities.

2. Breathing air should be reticulated from utility area to strategic locations about platform in areas subject to toxic gas releases and to facilitate supply of air to breathing apparatus.

3. If toxic gas exposure is isolated and does not pose a threat to low hazard area, quarters, emergency assembly areas, or muster areas, portable breathing air facilities may be substituted for a reticulated system.

12.3.4. Flares and vents (API RP 14, API RP 521)

12.3.4.1. Flare and vent relief

a. Flares and/or vents should be provided to relieve hydrocarbon gas (GIS 22-201, GP 22-20, GP 44-80).

b. Purpose of relief is for disposal of waste gas operating below compressor suction pressure, emergency relief disposal in event of process upset, or platform pressure control during periods when main compressor is out for maintenance.

c. Flare and emergency relief systems may consist of a vertical stack, remote flare pile, or cantilevered boom.

d. In some small shallow water locations, gas may be routed subsea and allowed to vent and bubble through column of water at safe distance from platform.

e. System in d. places minimum backpressure on relief system equal to water depth at location.

f. System in d. should be supplemented with on platform relief.

12.3.4.2. Flare gas

a. Gas may be either flared (burned) or vented directly to atmosphere.

b. Flare boom or tower and/or high pressure, cold vent stacks should be downwind of low hazard area.

c. Flare boom or vent stacks should be located such that release of flammable unburned vapour does not impose exposure hazard to personnel or platform.

d. Flares should be located such that:

1. Heat radiation intensity is within acceptable limits in accordance with API RP 500 or BP criteria.



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2. Probability of burning liquids falling on platform or on normal boat or barge traffic areas is low.

e. Vents should be checked to ensure that, if accidentally ignited, radiation levels are acceptable.

12.3.4.3. Relief system

a. Relief system height and location should be determined considering volume of gas to be relieved under both continuous and emergency conditions and prevailing wind direction.

b. Other critical areas and equipment that should be considered in choosing location and height of flare and/or vent stacks include:

1. Other equipment, including quarters.

2. Fresh air intakes.

3. Drilling and workover rigs.

4. Helicopter flight paths and helideck.

5. Ignition sources (fired heaters, nonintrinsically safe electrical equipment, hot work areas, etc.).

12.3.5. Fired heaters

a. Fired heaters on offshore platforms should be avoided.

b. Fired heaters, if necessary, should be located only on main deck in open, well ventilated areas away from inventories of flammable materials and low hazard area.

c. The following safeguards should be used for fired heaters (GP 22-10):

1. Combustion air should be supplied by forced draft fans with reverse flow checks installed.

2. Forced draft fans should be spared.

3. Programmed purge system should be used in fuel/air delivery system and automatically start combustion process.

4. Combustible gas detectors should be located near combustion air fan intakes.

5. Fuel gas trip and isolate fan discharges should be activated on 25% of LEL measured at fan air inlet.

6. Minimum of 4,5 m (15 ft) spacing should be maintained between fire heaters and other process or mechanical equipment, unless protective barriers (firewalls) are used for fire heater isolation.

7. Direct fire heaters should be isolated behind firewalls.

8. Maintenance space should be provided for pulling fire tubes.

9. Hoisting equipment should be provided for fired heater maintenance, or heater should be accessible by platform crane.

12.3.6. Conductors, caissons, and other sea penetrations

a. Jacket platform designs

1. Intake and discharge lines on jacket platform structures should be inside jacket structure and supported by jacket structure members.

2. Firewater intake lines and well conductors should be inside jacket structure.

b. Condeep designs



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1. Intake and discharge lines on condeep designs should be inside one of the structure support legs.

2. Firewater intake lines should be inside riser or utility shaft leg.

3. Locating firewater intake lines inside a drill shaft is not recommended.

c. Intake and discharge lines on floating platform designs should be inside a moon pool or over the side of the platform in an area protected from marine vessel traffic and maintenance activity.

d. Bottom ends of discharge lines and inlets of intake lines (between sea and platform) should be located to minimise risk of recirculation.

e. Platform discharges to sea should comply with regulations of governments having jurisdiction and local company approved practices.

f. Typical overboard lines operating on a platform include:

1. Discharge lines

a) Drilling and completion fluid waste during drilling.

b) Drill cuttings during drilling.

c) Drilling bulk materials (vented dust).

d) Formation water from produced water treating system.

e) High salinity water from desalination system.

f) Excess firewater pump discharge, one per pump, full discharge during pump testing.

g) Deluge drains.

h) Domestic waste from quarters.

i) Kitchen scraps from quarters.

j) Deck drain overflow.

k) Platform skimmer piles or caissons.

2. Intake lines

a) Firewater pumps (one per pump).

b) Service water or seawater for cooling as required.

c) Drilling fluid makeup during drilling.

12.3.7. Liquids (NFPA 30, NFPA 497)

12.3.7.1. Atmospheric pressure storage tanks

a. Atmospheric pressure tanks may be required for stabilising liquid hydrocarbons or storage of materials, such as lube and fuel oil, diesel fuel, and potable water.

b. Horizontal “gun barrel” tanks for oil treating and large water skim tanks may be used on smaller facilities, although these are less common due to large size and weight.

Space consideration is most important on an offshore platform. Therefore, tanks that are rectangular in plan view (as opposed to circular) are more typically used.

c. Large rectangular tanks with internal walls to permit storage of multiple materials are common. For example, one tank can be used to store wet (slop) oil, clean (saleable) oil, and liquid fuels or to serve as a produced water skimmer vessel.

d. Gas release



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1. Atmospheric tanks containing produced crude oil and produced water should be vented to allow release of gas that comes out of solution.

2. Vented gas should be either recovered or routed to vent stack downwind of platform for safety.

e. If sectioned tanks are used, nonflammable liquids may be kept between stored fuel and potential ignition sources to act as a safety buffer.

f. Storage tanks containing hydrocarbons should be separated from fired vessels and other continuous ignition sources by firewall or minimum of 15 m (50 ft).

g. Tanks containing hydrocarbons should be isolated from areas where heavy equipment is maintained.

h. Large hydrocarbon tanks should be located on top deck with nothing above them (due to risk of roof blowing off in the event of internal overpressure).

i. Deck legs/crane pedestals used for liquid storage of diesel, lube oil, drill water, potable water, or glycol should:

1. Have proper safety equipment.

2. Be designed for all associated loads.

j. Floating production facility hull storage tanks should be:

1. Vented to low hazard area.

2. Protected from dropped objects.

12.3.7.2. Liquid storage

a. Liquid storage, such as diesel fuel for firewater pumps and emergency generators, corrosion control chemicals, hydrate inhibition chemicals, deaeration and biocide chemicals, solvents and cleaning agents, and process fluids, such as glycol and amines, may be required to support operations.

b. Minimum storage volume required depends on daily use and time between supply trips as follows:

1. In the Gulf of Mexico, maximum length of time during which a platform cannot be resupplied can be 1 d or 2 d. Therefore, 1 wk or 2 wk of storage should be sufficient.

2. However, in the Arctic Ocean, where bulk supply may be prohibitive except during summer months, 1 yr supply may be required.

c. Drum storage

1. On small platforms, liquids are generally stored in 208 l (55 gal) drums and transported by hand carts.

2. Drum storage should be well ventilated and easily reached by crane.

d. Bulk storage

1. On larger installations, bulk storage in cylindrical or rectangular tanks may be required, along with pumps to distribute liquid to various locations within the facility.

2. Adequate space and location for bulk storage of materials should be crane accessible and allocated outside low hazard area in a lower risk area.

12.4. Clearance requirements

12.4.1. General

a. Items that should not block operating aisles or maintenance access include:



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1. Projecting piping.

2. Valve spindles (valve wheels).

3. Instrumentation and instrument air manifolds.

4. Local panels.

5. Transducer stations.

6. Pneumatic and electrical junction boxes.

7. Grouped steam tracing supply and condensate manifolds.

b. Minimum of 1 m (3 ft) clear working space should be maintained around equipment that requires frequent servicing, such as pumps, exchangers, control valves, instruments, and vessel manways.

c. Horizontal and vertical clearances for maintenance and operations should at minimum comply with those recommended by equipment Vendors.

d. Clearances should be measured from furthest projection on equipment, including associated pipe work with flanges and insulation boxes, filters, valves in open position, drains, cabling, and instruments, between grade and 2 m (6 ft) above grade.

12.4.2. Vertical clearance

Overhead clearances should be at least:

a. 3,7 m (12 ft), if carry deck crane access is required.

b. 3,1 m (10 ft), if 1,8 tonne to 2,7 tonne (2 ton to 3 ton) forklift truck access is required.

c. 3,7 m (12 ft) for main pipe racks.

d. 2,2 m (7 ft) from grade or elevated platform for personnel passageway.

12.4.3. Horizontal clearance

Unless approved otherwise by BP, minimum horizontal clearance to piping, equipment, and instrumentation should be as follows:

a. 1,5 m (5 ft) for aisles at equipment and machinery.

b. 1,2 m (4 ft) for operating and maintenance areas at grade.

c. 1,2 m (4 ft) for workspace on platforms servicing heads of shell/tube exchangers mounted on structure.

d. 0,9 m (3 ft) for workspace on platforms servicing manways.

e. Centreline of manway at elevation of 1,5 m (5 ft) from platform.

f. Machinery workspace

1. 2,1 m (7 ft) for workspace around compressors, turbines, and large motors for operating and maintenance clearances to handle casings, rotors, crankshafts, flywheels, etc.

2. Minimum spacing should be validated by equipment Vendor and subject to BP approval.

g. Storage tank access

1. 0,9 m (3 ft) for access around storage tanks to level gages, controls, and access into tank through manways.

2. If no piping or controls are located on one side of tank, only a walkway may be required.



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h. Clearances should be measured from the furthest projection on equipment, including associated pipework with its flanges and insulation boxes, filters, valves in their open positions, drains, cabling, instruments, etc. between grade and 2 m (6,6 ft) above grade.

Documents

GP 44-15 14 August 2007 - Offshore Platform Layout