BGAS-CSWIP Painting Inspector Grade 1 ATC89 PDF

BGAS-CSWIP Painting Inspector Grade 1 ATC89 Training & Examination Services Granta Park, Great Abington Cambridge CB21 6AL, UK Copyright © TWI Ltd  Rev 1 January 2010...

BGAS-CSWIP Painting Inspector Grade 1 ATC89 Training & Examination Services Granta Park, Great Abington Cambridge CB21 6AL, UK Copyright © TWI Ltd  Rev 1 January 2010 Contents Copyright  TWI Ltd 2013 BGAS-CSWIP Painting Inspector – Grade 1 Contents Section Subject 1 Corrosion Electrical circuit The chemical reaction 2 Rig/Platform Details 3 Conditions for Offshore Inspection 4 Structures and Definitions Definitions Other related definitions 5 Survival and Offshore Induction Training Category A Category B Category C Category D 6 Health Requirements for Offshore Working 7 Offshore Safety Requirements General restrictions Chain of responsibility Permit to work system Permit for vessel entry (enclosed space) Scaffolding requirements 8 Offshore Passive Fire Protection (PFP) Classes of fire divisions A-60 class divisions B-15 class divisions H-120 class divisions Materials used for fireproofing 9 Anti-fouling Paints 10 Alarms and Escape Routes 11 Safety Signs and Relevant Colours to BS 5378 (1980) Specification for Colour and Design 12 Product Identification by Pipe Colour Coding to BS 1710 (1975) 1 www.twitraining.com  Rev 1 January 2010 Contents Copyright  TWI Ltd 2013 13 Cathodic Protection Interference Monitoring CP Cathodic disbondment 14 Revision Questions BGAS Grade 1 Paper 1 Paper 2 Paper 3 CP-C-155 Specification Appendices PWCI part 1 - Cladding for gas pipe 2 equipment CPC 155 - Painting systems for offshore structures TSPPWC - Thermal insulation of above ground pipework and equipment 2 www.twitraining.com Section 1 Corrosion  Rev 1 January 2010 Corrosion Copyright  TWI Ltd 2013 1 Corrosion Corrosion can be generally defined as degradation of a metal by chemical or electrochemical means. From this definition it is clear that two mechanisms are involved, firstly an electrical circuit and secondly a chemical reaction. 1.1 Electrical circuit In a corrosion circuit the current is always direct current (DC). It is conventionally thought that a current passes from positive + to negative - ie from anode to cathode, but electrons are flowing the opposite direction, from cathode to anode. For a corrosion circuit to exist three things are needed: Anode An anode is a positively charged area which becomes positively charged because the atoms release two electrons each, thus causing an imbalance between protons and electrons, positive and negatively charged units. In its passive state, the iron atom has 26 of each, protons and electrons, when the two electrons are released the atom still has its 26 protons, but only 24 electrons. In this state the atom is now an ion, overall positively charged by two units and written as Fe++. (An ion is a charged particle and can be positive or negative, a single or a group of atoms, known as a molecule.) This losing of electrons can be shown as: -Fe  Fe++ + 2e. The Fe++ is called a positive iron ion. An ion can be positive or negative and is a charged particle, an atom or a group of atoms. A passive iron atom Fe An iron ion Fe++, 26 protons and 26 electrons. 26 protons and 24 electrons Nucleus Figure 1.1 Iron atoms. Cathode A cathode is a negatively charged area where there are more electrons than needed in its passive state. These are electrons released from the anode. At the cathode the electrons enter into the electrolyte to pass back to the anode. 1-1 www.twitraining.com  Rev 1 January 2010 Corrosion Copyright  TWI Ltd 2013 Electrolyte An electrolyte is a substance, which will conduct a current and be broken down by it, (dissociate into ions). Water is the most abundant electrolyte and also very efficient. Acids, alkalis and salts in solution are also very efficient electrolytes. As the electrons pass into the electrolyte it is dissociated into positive and negative ions, as shown by the formula: -2H2O2H+ + 2OĦ. Simultaneously the electrons couple back with the hydrogen ions to form two full hydrogen atoms, which join together diatomically to form hydrogen gas. This is called being evolved, or given off from the cathode. The hydroxyl ions return to the anode through the electrolyte carrying the electrons. The corrosion triangle below illustrates the electrical circuit. The electron circuit can be seen to be from A-C, through E, back to A. Electrolyte Anode Cathode Figure 1.2 Corrosion triangle. 1.2 The chemical reaction From the above we can see that no chemical reaction, (combination of elements) has occurred at the cathode or in the electrolyte. The chemical reaction, the formation of corrosion products, only occurs at the anode. The positive iron ions, Fe++, receive the returning hydroxyl ions and ionically bond together to form iron hydroxide, which is hydrous iron oxide, rust and is shown by the formula: Fe++ + 2OH Fe(OH)2 It is now apparent that corrosion only occurs at the anode, never at the cathode, hence the term cathodic protection (CP). If a structure can be made to be the cathode in a circuit, it will not corrode. The corrosion triangle shows the three elements needed for corrosion to occur, anode, cathode and electrolyte. If any one of these is removed from the triangle, corrosion cannot occur. The one most commonly eliminated is the electrolyte. Placing a barrier between the electrolyte and the anodic and cathodic areas, in the form of a coating or paint system does this. If electrolyte is not in direct contact with anode and cathode, there can be no circuit and so no corrosion. 1-2 www.twitraining.com  Rev 1 January 2010 Corrosion Copyright  TWI Ltd 2013 The basic corrosion reaction, explained above, occurs fairly slowly at ambient temperatures. In common with all chemical reactions certain factors can increase the reaction rate, listed below are some of these. 1 Temperature Steel, like most metals, is thermodynamically unstable. The hotter the steel is the faster the corrosion will occur. 2 Hygroscopic salts A hygroscopic salt will attract water and dissolve in it. When salts are present on a substrate and a coating is applied over them, water will be drawn through the film and the resulting solution builds up a pressure under the film. Eventually the film is forced up to form blisters. These blisters are called osmotic or hygroscopic blisters and are defined as pinhead sized water filled blisters. Sulphates and chlorides are the two most common salts, chlorides predominant in marine environments and sulphates in industrial areas and sometimes agricultural. 3 Aerobic conditions: (presence of oxygen) By introducing oxygen into the cathodic reaction the number of hydroxyl ions doubles. This means that double the number of iron ions will be passivated and therefore double the corrosion rate. Shown by 2H2O + O2 + 4e  4OH- 4 Presence of some types of bacteria on the metal surface, for example sulphur reducing bacteria (SRBs) or metal eating microbes (MEMs). 5 Bi-metallic contact: Otherwise known as bi-metallic corrosion. Metals can be listed in order of nobility. A noble metal is one, which will not corrode. In descending order, the further down the list the metal is, the more reactive it is and so, the more anodic it is, the metal loses its electrons to become reactive ions. The degree of activity can be expressed as potential, in volts. The list can be called a galvanic list, but when the free potentials of the metals are known it can also be called the electromotive forces series or the electrochemical series. On the following page is a list of some metals in order of nobility with potentials measured using a copper/copper sulphate half-cell reference electrode, in seawater at 25°C. 1-3 www.twitraining.com  Rev 1 January 2010 Corrosion Copyright  TWI Ltd 2013 Material Known potential AV. values Graphite +0.25v Titanium 0.0v Silver -0.1v Nickel 200 -0.15v Lead -0.2v Admiralty brass -0.3v Copper -0.35v Tin -0.35v Mill scale -0.4v Low alloy steel -0.7v Mild steel -0.7v Aluminium alloys -0.9v Zinc -1.0v Magnesium -1.6v Mill scale is formed during the rolling operation of steel sections eg RSC, RSA, RSJ. The oxides of iron form very quickly at temperatures in excess of 580oC. The first oxide formed is FeO, iron oxide, the next is Fe3O4 and last of all Fe2O3. Common names in order are wustite, magnetite and haematite. These oxides are compressed during the rolling operation to produce blue mill scale. The thickness of mill scale varies from 25-100m. Because it is only produced during rolling, when it has been removed by any surface preparation method, it can never recur. 1-4 www.twitraining.com  Section 2 Rig/Platform Details  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 2 Rig/Platform Details 2-1 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Crown block Derrick Travelling block Hook Swivel Standpipe Kelly Motion compensator Drawworks Flexible hose Drilling line Power unit Ingoing mud Mud tanks Mud pumps Rotary table Drill string BOP stack Returning mud Figure 2.1 Derrick and other main components of a drilling rig. 2-2 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Directional drilling Directional drilling Multiple well platform Sea bed Deviation at about 1,500 feet (460m) Angle build-up Vertical typically 30-60° Deviated holes holes Reservoir Figure 2.2 Directional drilling. 2-3 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Elevation Figure 2.3 Plan view and elevation of the jack-up drilling unit Neptune 1. 2-4 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Drilling rig Derrick Derrick Heliport Accommodation Box girder deck Flow pipe to well Steel column Sea surface Bracing conductor Water outflow Oil tower Water tower Oil inflow Oil outflow Riser Water inflow Caisson Seabed Skirt Figure 2.4 View of ANDOC gravity structure showing oil intake, storage and flow system. 2-5 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Automatic master valve Well compartment with up to 6 wells Flowline oil/gas Manual master Casin valve g Firewall Firewall Space between casings filled with cement 18⅝" casting Downhole safety valve 77' 13⅝" casting Sea level 420' Seabed 9⅝" casting 200' 4" tubing for Buried 32" oil/gas Oil bearing production sandstone pipeline oil to 7000' Cruden Bay Oil flow Oil flow Casing cemente d in Figure 2.5 Oil flow diagram for Forties field platform showing position of cement in spaces between casing. 2-6 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Accommodation, production and Derrick equipment modules Steel deck Concrete towers Conductor pipes Concrete base caisson for oil storage, with water ballast Figure 2.6 Sea tank gravity structure. 2-7 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Figure 2.7 Mat supported jack-up drilling rig. 2-8 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 72 ton capacity crane 25,000ft capacity derrick 54 ton capacity cranes Overall height 325ft Living quarters for 65 men Deck Deck height 146ft 9ft diameter tubular members Caisson 35ft diameter Mooring system stabilising column 9 lines of 3 inch chain each 2,500ft Pontoon 80ft diameter long with 30,000lb and 30ft deep anchor Figure 2.8 Pontoon type semi-submersible drilling rig (Sedco 1). Drill floor Main deck Brücker survival capsule CL well Forward Figure 2.9 Twin-hull semi-submersible drilling rig (Zapata). 2-9 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Figure 2.10 Cut-away drawing of a Forties field production platform in the North Sea. 2-10 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Figure 2.11 Casub structure tension leg platform. 2-11 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Derrick Elevating Logging racks unit Cranes Drawworks Helicopter deck Shale shaker desanding and Living degassing unit quarters Anchors Legs tilting hinges Gear units Metres Feet Legs Spud tanks Figure 2.12 Slant leg jack-up Neptune Gascogne. 2-12 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Steel jacket Concrete base Figure 2.13 Hybrid gravity structure (RDL). 2-13 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Deck Intermediate columns Pontoon Stabilising column Figure 2.14 Semi-submersible drilling rigs Aker H-5 showing the intermediate columns. 2-14 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Derrick Helideck Deck Columns containing risers Storage/ballast cells Protective skirt Figure 2.15 Subtank design for a gravity storage platform. 2-15 www.twitraining.com  Rev 1 January 2010 Rig/Platform Details Copyright  TWI Ltd 2013 Derrick Helipad Module Flare bridge Pipeline to shore or SPBM, single point body mooring Figure 2.16 Piled steel platform. 2-16 www.twitraining.com  Section 3 Conditions for Offshore Inspection  Rev 1 January 2010 Conditions for Offshore Inspection Copyright  TWI Ltd 2013 3 Conditions for Offshore Inspection Regardless of geographical location, surface preparation and the subsequent painting of these areas are subject to inspection procedures and offshore working is no exception. Many other factors need to be taken into consideration when working offshore and stringent safety rules and systems are in operation to safeguard all personnel. Breach of these rules can result in an individual being sent back to the beach on the next available helicopter. The working environment is different in every aspect. Accommodation is at a premium, so long working hours are the norm, typically 12 hours per day for seven days per week with a work pattern of two weeks on the platform and one week home. The actual work programmes are also influenced by different factors. The jacket legs in the splash and tidal zones must be worked to suit the tides. For instance, surface preparation follows the tide down and the subsequent painting has to be done starting at the bottom and letting the tide follow, upwards but is better done on neap (lowest) tides, as areas further down the leg can be treated. (There are two neap and two spring (highest) tides per month and are governed by the earth/moon positions.) The helideck can only be painted when no flights are due and it is not permitted to dispose of cans and expended abrasives over the side, they must be stored and taken ashore by service boat. Because of the shorter application window, production demands are higher and it may be required to blast and paint in an encapsulated area. (Totally enclosed so as not to interfere with everyday operations, the enclosure may be made of wood or plastic but not tarpaulin, the purpose being to pose no threat or hazard to working plant or operators during blasting operations.) 1 The highest proportion of problems encountered are directly due to the environmental conditions, among which are: 2 Salts, fog or sea frets are common in summer months and salt from the seawater is deposited on the structure. 3 High relative humidity because of the proximity of the sea. 4 Ultraviolet light: The seawater reflects UVA and B so in effect the structure suffers double exposure. 5 Erosion and impact damage from flotsam and moving water, lateral water flow due to tides is moderate in most areas but still erodes away coatings. 6 Winds: Because of the different thermal characteristics of water and land, the air pressures cause severe wind changes. 3-1 www.twitraining.com  Rev 1 January 2010 Conditions for Offshore Inspection Copyright  TWI Ltd 2013 7 Fast changing weather patterns, again due to temperature, pressure and humidity changes. 8 Tide changes: High and low tides vary from season to season as well as during each month so the most advantageous time should be chosen for tidal work. Turbulence from swell and tides is high. 9 The different areas on a platform require a different approach to maintenance, varying from submerged areas, areas in the splash zone and the atmospheric zone. 3-2 www.twitraining.com  Section 4 Structures and Definitions  Rev 1 January 2010 Structures and Definitions Copyright  TWI Ltd 2013 4 Structures and Definitions 4.1 Definitions  Rig Technically a rig is not moored to the seabed, but is a movable structure, usually jack ups. The legs are lowered on to the seabed and the deck raised above water level. When the required operation is completed the legs are raised (lowering the deck to flotation level) and the rig can be towed or self-powered to another position. Usually used in relatively shallow waters.  Platform Moored or fixed to the seabed, a platform is constructed in several sections and can be fixed to the seabed by piling or can be semi- submersible and fixed by tension legs.  Jacket The legs or support structure, this is constructed onshore and floated out to position, where it is lifted and put in exact location using a derrick barge. These are huge floating platforms which house cranes capable of lifting thousands of tons, counterbalanced by water filled tanks. The cranes are also used to pile the jacket into position.  Modules Modules are then placed in position on the jacket. These are purpose- built sectional buildings incorporating compressor or process units, accommodation or dining modules and when all are joined together (hooked up) they form an offshore factory with all required facilities. Modules are erected up to three units high and sometimes the accommodation is on a separate platform joined via a bridge or walkway.  All platforms and rigs have to undergo rigorous examination and tests to ensure that they can withstand the extremes of tide and temperature, sea depth and seabed conditions, before being issued with a certificate of fitness to operate.  Riser The vertical pipe which joins the production facility to the subsea pipe to carry the product back to the beach to the processing plant. This pipe will previously have been laid by means of a lay barge. 4.2 Other related definitions  Atmospheric zone Area above the splash zone up to the cellar deck.  Blow out preventers (BOPs) Special type of valve which prevents loss of oil or gas from the well during drilling operations. 4-1 www.twitraining.com  Rev 1 January 2010 Structures and Definitions Copyright  TWI Ltd 2013  Caisson Subsea oil storage facility usually on the seabed, a watertight chamber is the dictionary definition.  Casing tubing Pipes which are drilled through and subsequently, cemented in place to conduct the product, oil/gas from the well to the platform.  Cellar deck The first deck on the platform above the spider deck. The area below the rotary table on a drilling rig.  Conductors Pipes from the wells to the topside pipe work.  Helideck Special deck area allocated to helicopter landing.  Node Point at which a number of cross bracings and tubular members, are joined to a vertical column. In a large offshore structure, node building calls for high quality, precision engineering and intricate welding.  Spider deck Substructure beneath the main deck which usually gives access to safety boats and standby boats.  Splash zone Generally above the water line but liable to be affected by wave action. The area of jacket between -2.5 and +12m of the lowest astronomical tide (LAT). The splash zone is a loose demarcation boundary, which dictates the type of anti-corrosion coating.  Submerged zone Area between the seabed and -2.5m of LAT.  Spud can Tank on the bottom of the jack up legs to strengthen the legs and prevent it sinking into the seabed.  Slug catcher Very long large diameter pipe long enough to create a pressure drop and allow slugs of hydrocarbons to condense. As pressure drops so does temperature causing condensation. 4-2 www.twitraining.com  Rev 1 January 2010 Structures and Definitions Copyright  TWI Ltd 2013  Survival capsule Totally enclosed life-saving capsule, some can seat up to 50 men. They are self-propelled and are usually stocked with food, water and first aid equipment.  Top deck Uppermost deck on the structure.  Topsides General term describing anywhere above cellar deck.  Xmas tree Complex of pipes and valves installed at the well head to control the flow of oil or gas. So called because the pipes form several branches and are festooned with valves and control mechanisms. It enables a well to be closed off and allows servicing.  Typical sea depths The seabed around the British Isles slopes away in various gradients over various distances from the shore. Stretching for up to 1200km, but on average 65-100km from the shore is the continental shelf. The depth varies from 50-550m with an average depth of 130m. In coastal regions of 50m depth, drilling would be done by a drilling barge. Further offshore (about 120m) a jack up would be more appropriate, whereas further out on the continental shelf, fixed platforms would be the norm. Semi-submersible platforms (working at an average depth of 300-500m with 1000m being exceptional) would be favoured on the extremes of the continental shelf and into the next plateau area, the continental rise. Further out still on the abysmal plain starting at about 600km plus from the shoreline, average depths are 3800m with the deepest areas at 11,000m plus. At such depths a drilling ship would be more likely.  Coding for identification The system used for platform identification first gives the owner/operators name eg British Gas, Conoco, Shell, etc, followed by the gas/oil field name eg Viking, Forties, Rough and finally a code letter designating the platform. Connecting platforms are identified by function eg distribution, production. 4-3 www.twitraining.com  Section 5 Survival and Offshore Induction Training  Rev 1 January 2010 Survival and Offshore Induction Training Copyright  TWI Ltd 2013 5 Survival and Offshore Induction Training All categories of personnel working offshore must possess an offshore survival certificate, attained by attending survival courses at approved training centres. The course must be approved by the petroleum training validation service operated by offshore petroleum industry training organisation (OPITO). Such centres operate at Aberdeen, Lowestoft, Hull, Fleetwood and Montrose, the most widely used being the RGIT. Offshore personnel can be split into four different categories according to UK offshore operators association (UKOOA) document, guidelines for offshore emergency training. 5.1 Category A Permanently (usual place of employment is offshore.) or regularly assigned (normally work onshore but may have to spend more than 15 days or nights offshore per year as part of their normal duties) personnel without specialist fire fighting duties. 5.2 Category B Permanently (usual place of employment is offshore) assigned personnel with specialist fire fighting. 5.3 Category C Those who work offshore occasionally (personnel who normally work onshore but who in the course of their normal duties may have to spend up to 15 days or nights offshore during a twelve month period). 5.4 Category D Visitors (personnel who may visit offshore, but not spend the night and who would normally not spend more than four days offshore in a twelve month period, when outside the platform accommodation, would be accompanied at all times by a category A or B personnel. The category, which is applicable to the individual, will dictate only the minimum training required. The offshore operators may have their own specific training requirements. Categories A-D must attend CAA approved helicopter safety briefing before boarding regardless of any other requirement. Regularly and permanently assigned and the occasional category of personnel, must, in addition, have survival certificates. 5-1 www.twitraining.com  Rev 1 January 2010 Survival and Offshore Induction Training Copyright  TWI Ltd 2013 Prior to actually working offshore, personnel should receive safety related training which can be given in four situations. 1 With the exception of the visitor classification, at initial and refresher courses approved by OPITO. 2 All personnel, before boarding helicopters. 3 Before going out to, or just having arrived at, a platform for the first time. 4 Through the exercises and safety drills peculiar to each installation. The above represents the minimum requirements for survival, fire fighting and emergency safety training. Personnel not fulfilling the minimum requirements would not be permitted to work offshore. There are obviously different requirements for each category but all categories have general requirements including:  Helicopter escape procedures.  Use of survival equipment on helicopters.  Survival techniques.  Fire fighting. Details can be found in UKOOA section 3. 5-2 www.twitraining.com  Section 6 Health Requirements for Offshore Working  Rev 1 January 2010 Health Requirements for Offshore Working Copyright  TWI Ltd 2013 6 Health Requirements for Offshore Working The United Kingdom offshore operators associations (UKOOA) document, guidelines for medical aspects of fitness for Offshore Work requires all personnel engaged to work offshore must have a certificate of medical fitness before even attending the emergency training courses. Personnel under the age of 40 must be passed as medically fit every three years. Between 40-50 years the medical must be every two years and for personnel over 50, they are annual. The platform operator has the final decision to make on who can or cannot work offshore, but should take into account the information from the medical. Certain medical conditions automatically disbar personnel from offshore work (and it is not uncommon for operators to apply other stringent conditions eg breathalysing prior to outbound flight). One operator actually requires certificates of dental fitness because of the expense involved in returning personnel to the beach. Personnel under the age of 18, declared diabetics and coeliacs (flour aversion) cannot work offshore. Regulations govern exactly what an offshore medical kit should contain, even down to specific size and type of safety pin. The regulations also specify which medicines and tablets should be stocked for a specific number of personnel and which are allowed to be dispensed by the qualified first aider. 6-1 www.twitraining.com  Section 7 Offshore Safety Requirements  Rev 1 January 2010 Offshore Safety Requirements Copyright  TWI Ltd 2013 7 Offshore Safety Requirements The offshore installations managers (O, I&M) (operation safety, health and welfare) regulations SI 1019 (1976) or a copy must be available on the platform for all personnel to refer to, if required. It provides the rules (statutory) for safety, health and welfare of personnel working offshore. (All required information has been extracted and is contained within these notes.) 7.1 General restrictions Safety is of paramount importance for personnel working offshore, every individual is responsible for his/her own safety and the safety of others. The platforms are producing and processing highly flammable hydrocarbon compounds and as such are at high risk of explosions, fire and also from individuals falling into the sea. Every conceivable precaution is taken to avoid these occurrences, including. 1 Smoking is only allowed in specified areas. 2 Anti-static cotton overalls to be worn along with light rubber soled rig boots, easily kicked off without having to use hands. Some operators even insist that steel toecaps should not be visible through scuffed leather. 3 Battery operated cameras, gauges, radios; etc must be intrinsically safe to avoid risk of sparks. 4 All work must be done under a permit system. It is the employer’s (contractors) responsibility to ensure that all personnel are conversant with permissible work conditions and safety considerations offshore. 7.2 Chain of responsibility Offshore, the man in charge is the offshore installation manager (OIM). In accordance with SI 1019 under regulations 30 every offshore Installation, has a number of competent personnel appointed by the OIM responsible for the safety and control of structure, equipment, operations or substances. Regulations 30 Of SI 1019 relates to operational staff. Regulations 7  This relates to written instructions.  W.I’s for all offshore practices to ensure installation safety and the staff use of equipment. 7-1 www.twitraining.com  Rev 1 January 2010 Offshore Safety Requirements Copyright  TWI Ltd 2013 Regulation 30 (1) continues. There shall be on every offshore installation a sufficient number of competent persons appointed by the installation manager to be responsible for the control and safety of: a The structure of the installation. b The electrical equipment of the installation. c The mechanical equipment of the installation. d Lifting appliances and lifting gear. e Drilling operation. f Production operations. g Handling and storage of acids, caustic alkalis, explosives, radioactive and other dangerous substances and: h Any other unusual or dangerous operations. The quote continues and the installation manager shall ensure that a list of all such persons on the installation is maintained on the installation at a place where it can be conveniently read by persons on the installation. Where it can be conveniently read is usually referred to as the station bill and is usually located at the radio office/heli administration/arrival lounge. Also on the station bill will be other essential information, such as: a A plan of the platform. b Location of lifeboats. c Location of fire fighting equipment. d Details of the warning system. e SI 1019. And of course the list of responsible persons. A good check list for new arrivals on a platform, after booking in and being allocated their accommodation, is to check: a What is the evacuation signal? b What is the evacuation procedure? c Where the fire alarms are. d Where the fire fighting appliances are. e Location of the evacuation equipment eg Brückers. f Where the emergency points are. 7-2 www.twitraining.com  Rev 1 January 2010 Offshore Safety Requirements Copyright  TWI Ltd 2013 7.3 Permit to work system An inspector is not a designated permit (to work) holder. The supervisors of a working group are the persons responsible for obtaining and holding work permits. Work permits are needed for all types of work carried out on a platform and fall into two categories. 1 Hot work permit Issued to personnel performing tasks that involve a possible local source of ignition capable of igniting flammable products on the platform. This covers blasting, spraying, hand and power tool cleaning. 2 Cold work permit Issued for housekeeping, manual abrasion or working in elevated positions and any situations where there is no risk of spark and therefore no possible ignition. Even tasks like radiography require a cold work permit. Note: Whilst a hot work permit is issued in the knowledge that moving machinery is involved and sparks may occur, every conceivable precaution is taken to cut the occurrence or possibility to a bare minimum. eg compressors are fitted with spark arresters and as required. (BGAS - approved painting systems for offshore structures) CP C 155, blast cleaning and spraying equipment shall be continuously electrically bonded from the nozzle to the surface being painted (blasted) and backwards from the nozzle to the compressor, which shall be earthed. (Earth wire bolted to the structure.) Some equipment has special threaded fittings for this purpose) and compressors shall meet Health and Safety requirements. A permit to work system may seem extreme, but the underlying reason for it is a safeguard in many different ways. The objectives of a permit to work system are to: 1 Prevent injury and accidents to personnel and damage to plant and equipment. 2 Enable non-routine work to be carried out using a company-wide procedure. 3 Ensure proper authorisation of non-routine work. 4 Clarify risks to personnel and specify required precautions before work is done in an area of work outside normal responsibility. 5 Ensure that equipment or systems have been made safe so that work may proceed. 6 Provide a record showing that required precautions have been fulfilled. Permits are normally issued for one day duration only and should be signed off at the end of the period by the person designated as a responsible person. 7-3 www.twitraining.com  Rev 1 January 2010 Offshore Safety Requirements Copyright  TWI Ltd 2013 7.4 Permit for vessel entry (enclosed space) It should be stressed that an entry permit is not a permit to work; it is purely a permit to allow an individual to enter a vessel or a confined space after air tests have been carried out. If any work is to be done, then a work permit of the required category must be obtained. An entry or enclosed space permit will only be issued after a competent person has conducted air tests to verify the oxygen content. This must be above 20% (in normal conditions air contains 21% oxygen with 3.76 times that percentage of nitrogen. At concentrations less than this the body loses functionality until eventually at approximately 12% we become unconscious, below this we suffer heart failure). It is also a requirement that there be a standby person with all vessel entry permits at the point of entry in case of emergency. 7.5 Scaffolding requirements SI 1019 states certain requirements for scaffolding safety, among them being the certification of personnel and qualifications required by personnel before being able to certify scaffolding as safe for use. Scaffolding is a very responsible job requiring trained personnel, as the safety and well-being of all trades and workers on a platform relies on scaffolding for access. All scaffolding must be inspected every seven days or after inclement weather which could affect the integrity of the structure. A green tag should be signed by the scaffolding inspector and placed in a weatherproof plastic wallet, visible to all. A red tag means that the scaffolding is not safe to access. This is known as the scaftag system and is just one of many ways of verifying scaffold safety. In the scaftag system the requirement is that the scaffolding must be inspected by a competent person, being one who has attained the advanced scaffolding certificate, although the competent person can be a supervisor. One of the requirements of SI 1019 is working platform width; the minimum should be 65cm with a toeboard height of 15cm where practicable. When the platform working height is more than 2m or where personnel can fall into the sea the requirement is that there should be three guard rails. Whenever it is impractical to comply with three rails, a safety net should be employed. In the event of a safety net being considered impracticable each operator should be secured to the structure by means of a safety belt and line. Life jackets should be worn when the safety nets, belt and line are not practical and especially when there is a danger of falling into the sea. (Life jackets must be worn when so requested by a responsible person.) 7-4 www.twitraining.com  Rev 1 January 2010 Offshore Safety Requirements Copyright  TWI Ltd 2013 Over the side working is not specifically restricted by British Gas, but when it takes place (on the jacket and external modules, etc) a radio man/ watchman/firewatcher, must be in attendance, in radio contact with a standby (safety) boat. All scaffold boards on tidal and splash zone areas should be removed after the work period and replaced when next required. Scaffolding would not, normally, be permitted to be erected at night. SI 1019 also states: All scaffolding on the installation shall be so secured as to prevent accidental displacement. Every ladder shall be so fixed so that the stiles or sides of the ladder are evenly supported or suspended and so secured as to prevent slipping. 7-5 www.twitraining.com  Section 8 Offshore Passive Fire Protection (PFP)  Rev 1 January 2010 Offshore Passive Fire Protection (PFP) Copyright  TWI Ltd 2013 8 Offshore Passive Fire Protection (PFP) Fire protection should not to be confused with fire prevention. Fire prevention equipment is extinguishers and hoses to sprinklers, etc to prevent a fire. PFP is the materials used to minimise the effects of a fire when the prevention has been unsuccessful and the fire is established. Fireproofing needs to be applied to areas, such as accommodation, production and compressors modules; escape routes and the primary structure of the platform, where there is risk to personnel and production plant. Whether the platform is producing oil or gas is no concern, both hydrocarbons and hydrocarbon fires produce a huge amount of heat, especially when the material is under pressure. Hydrocarbon fire temperatures can reach 1250°C in a very short time; this is referred to as thermal shock. All materials used in the construction industry are given a classification for flame spread. Both ferrous and non-ferrous metals for construction purposes are non-flammable and are therefore given zero classification, but all metals have excellent properties for conducting heat and this is why it is necessary to apply PFP. The thickness of the PFP applied and in some instances, type, depends on four main factors: 1 Type of fire likely to occur in the vicinity, offshore the highest risk is hydrocarbon, but in accommodation modules cellulosic fire also. 2 Core temperature of the steel at which it will lose approximately half of its structural strength, usually around 400°C determined at design stage. 3 Length of time which the PFP has to maintain the core temperature below this critical figure, usually up to two hours to allow evacuation of personnel. 4 The Hp/A factor (section factor principle). This is the ratio of the exposed heated perimeter of the steel member, divided by its cross- sectional area. The smaller the cross-section of a member, the less steel there is to absorb the heat and so the member will conduct heat more easily. Therefore the smaller the cross-sectional area, the thicker the PFP will need to be. Calculations have already been made on every conceivable section and are listed in table form in a book called Fire Protection for Structural Steel in Buildings shortened commonly to the yellow book or Constrada. Offshore platforms often include specially constructed sections, eg plate girders and calculations will need to be done on these, but not by the inspector. 8-1 www.twitraining.com  Rev 1 January 2010 Offshore Passive Fire Protection (PFP) Copyright  TWI Ltd 2013 8.1 Classes of fire divisions Different fire ratings are given for bulkheads, underdecks and similar sections and are expressed in code form. Three types of code are used and the following explanations are extracts from the publication from the department of energy - offshore installations: guidance on design, construction and certification. 8.2 A-60 class divisions A-60 class divisions are divisions joined by bulkheads and decks which comply with the following: a They shall be constructed of steel or other equivalent material. b They shall be suitably stiffened. c They shall be so constructed as to be capable of preventing the passage of smoke and flame after 60 minutes exposure to a standard fire test. d They shall be so insulated that if either face is exposed to the standard fire test for 60 minutes the average temperature on the unexposed face will not increase at any time during the test by more than 139oC above the initial temperature. Nor shall the temperature at any point on the face, including any joint, rise more than 180oC above the initial temperature within 60 minutes. e All materials entering into the construction and erections of A-60 class divisions shall be of non-combustible materials. 8.3 B-15 class divisions B-15 class divisions are divisions formed by bulkheads, ceilings and linings which comply with the following: a They shall be constructed as to be capable of preventing the passage of flame to the end of the first 30 minutes of a standard fire test. b They shall be of such material that if either face is exposed to the first 30 minutes period of a standard fire test, the average temperature on the unexposed face will not increase at any time during the first 15 minutes of the test by more than 139oC above the initial temperature on the face nor shall the temperature at any point, including any joint, rise more than 225oC above the initial temperature. c All materials entering into the construction and erection of B-15 class divisions shall be non-combustible. 8-2 www.twitraining.com  Rev 1 January 2010 Offshore Passive Fire Protection (PFP) Copyright  TWI Ltd 2013 8.4 H-120 class divisions H-120 class divisions are divisions formed by decks and bulkheads which comply with the following: a They shall be constructed of steel or other equivalent material. b They shall be suitably stiffened. c They shall be so constructed as to be capable of preventing the passage of smoke to flame after 120 minutes exposure to a hydrocarbon fire test. d They shall be so insulated that, if the designated exposure face(s) (are) exposed to the hydrocarbon fire test for two hours, the average temperature on the unexposed face will not increase at any time during the test by more than 139oC above the initial, nor shall the temperature at any point on the face, including any joint rise more than 180oC above the initial temperature within two hours. e All materials entering into the construction and erection of H-120 class divisions shall be non-combustible. f Structures intended to be load bearing should either be tested under representative conditions of loading and restraint, or have the temperature of the load bearing medium monitored during the test to demonstrate that the maximum temperature attained would not have resulted in loss of strength or stiffness or excessive expansion such as to impair the load bearing capacity. The most frequently encountered fire ratings are the A and H ratings. A ratings relate to cellulosic fires, typically wood, paper and fabric as encountered in accommodation modules. This type of fire can take quite a long time to build up to high temperatures. H ratings relate to hydrocarbon fires which reach maximum temperature, within seconds, especially hydrocarbon jet fires (hydrocarbons from a well, under pressure also carry abrasive mineral particles which can exacerbate any damage). The number following the A or H rating represents the number of minutes for which that structure must insulate against the temperature rises stated above, from one side to the other. Jet fires can produce temperatures up to 1400oC and are extremely dangerous. The classification which covers this, eg J-10, H-45 means that jet fire conditions may last for 10 minutes, after which the emergency shutdown valve (ESDV) will have operated, reducing the pressure and producing hydrocarbon fire conditions for 45 minutes. At the design stage a risk analysis will have been conducted and it will have been determined which areas need higher protection factors. At no stage is the inspector involved with this. 8-3 www.twitraining.com  Rev 1 January 2010 Offshore Passive Fire Protection (PFP) Copyright  TWI Ltd 2013 8.5 Materials used for fireproofing Fireproofing materials or materials for PFP are many and varied. Epoxy intumescent, cementitious and mineral wool, pre-formed panels, vermiculite compounds and special foams are just a few. The two most widely used materials offshore being epoxy intumescent and cementitious. PFP coatings are often referred to as fire resistant or flame retardant coatings but are actually the same thing. PFP coatings have no anti-corrosion properties and are therefore applied over an anti-corrosion coating, but other systems can be applied over the PFPs. Consideration needs to be given to several factors when selecting systems to be used on structures, among them being:  Material’s ability to withstand flame, especially jet fire.  Ability to insulate against heat transfer into the steel.  Ability to provide the protection required for the length of time required.  Thickness of material needed to provide the protection required.  Material’s anticipated life span and maintenance requirements.  Toxicity of any smoke or fumes produced in the event of a fire. Methods used by PFPs to comply with the above requirements are by:  Exclusion of oxygen from the surface area.  Providing an insulating layer retarding heat transfer.  Forming non-combustible materials on the surface.  Production of non-combustible gases through chemical reaction between the constituents of the material.  Providing a surface which will ablate and expose a new reactive area to continue to reaction. 8.5.1 Cementitious materials Usually applied in a thick layer of 12-50mm (sometimes thicker) and mainly works on the insulation principle. The material is usually Portland cement mixed with low density fillers and either perlite or vermiculite (anhydrous mica) which acts as an insulating medium. Unlike the epoxy intumescent this material does not rely on chemical reactions but allows the locked in water to evaporate, which uses some of the heat from a fire and also performs its insulation function. Supplied as dry powder, these materials are mixed with water (potable) to stipulated proportions in special units, putzmeister being one, a hopper with a built in mixer, so that continuity of supply can be maintained. The mixer mixes the material for required minimum time of typically three minutes, with a calculated amount of potable water to ensure the correct consistency. Slump and density tests are conducted at specified intervals to ensure correct mixing. The material is then tipped into the hopper, at the bottom of which, is a rotating screw to carry the material into a housing, 8-4 www.twitraining.com  Rev 1 January 2010 Offshore Passive Fire Protection (PFP) Copyright  TWI Ltd 2013 where it is pressurised and forced along a hose, similar to a blast hose. As the mix exits the hose it is carried on to the substrate by compressed air/ water jets similar to the atomisation principle of paint spraying. Surface preparation standards can vary and in some cases the material is applied over wire brushed substrates coated with a vinyl primer. (Being cementitious these materials are very alkaline, up to a pH of 12.5 in some instances.) Due to the thickness of the material needed to provide protection, reinforcing is required, achieved by pinning and wire mesh. The studs, or pins, are stud or friction welded on to the component, usually before primer application, in a diamond pattern approximately 300mm apart. The mesh, usually plastic coated, is clipped or tied in position so that it lies approximately half way into the required thickness. The coating is then applied by spray, trowel or hawk. The spray application finish is not unlike pebbledash and some users prefer the surface is trowelled over to give a smooth finish, following the profile of the original section whilst maintaining the required thickness over every face. Whichever finish is required; the material is very porous and needs application of a sealer coat to prevent ingress of water, when cured. Common faults occurring are typically like for concrete, eg cracks, voids and spalling. Repair can be by cutting with a circular disc so that the damaged or faulty material can be removed, like a cross hatch, with a reverse chamfer on the outer edges to provide a key. Depending on the area involved, pins and mesh can be fitted if required. With cementitious coatings, when subjected to fire conditions they must be replaced, not repaired. 8.5.2 Intumescent epoxies Intumesce means to swell and intumescent PFPs are used because of this and other properties. Intumescent epoxies are two pack 100% volumetric solids (VS) high viscosity coatings, (some manufacturers permit small amounts of solvent, but only in certain situations). To bring the materials to suitable spraying viscosity, heat is required and when mixed, this considerably shortens the pot life. Storage should ideally be around 20oC for normal spray application, as most materials will be difficult to mix below this. (Mechanical stirring is recommended but care should be taken not to raise the temperature of the mix.) Using a plural spray, typically a hydrocoat and the materials can be heated to around 30oC because the base and activator are not mixed together until seconds before exiting the spray gun. 8-5 www.twitraining.com  Rev 1 January 2010 Offshore Passive Fire Protection (PFP) Copyright  TWI Ltd 2013 The base and activator are heated as separate components in small tanks (some equipment has heater jackets to fit around the cans) and fed through heated lines to the metering pumps. The metering pumps are set to feed the material in the correct ratio, activator to base, into a mixing unit like a series of baffles. The mixer head is as near to the spray gun as possible with a very short line to the gun because as soon as the hot materials mix the cure rate is very fast and any delay can result in the epoxy curing in the equipment. To avoid this there is also a solvent feed line into the mixer head. The base/activator feeds are closed, the solvent feed opened and the mixer, line and gun are flushed through. When application of the epoxy is to re- commence the solvent is closed off and the base/activator mix pumped through again. The solvent should be cleared from the system completely before application on the substrate. Because of the viscosity of the material a fairly large tip is necessary, around 35 thousand. The material can be applied in coats up to 7mm. It is normal practice to trowel out areas of overlap to avoid over thickness and a reinforcing mesh of synthetic material can be rolled in at the same time. Intumescent epoxies work by softening the resins when submitted to flame action at 200-250oC, releasing acid, which reacts with spumific materials, releasing non-combustible gases such as CO2 and NH3 and H2O vapour. These cause the material to swell to many times its original thickness. The materials form a carbonaceous char which insulates against temperature rise. As the char progressively ablates it exposes new surfaces to react in the same way hindering temperature increase and avoiding access of air, so avoiding combustion, thus retarding the temperature rise of the steel. Application thickness can vary between typically 4-15mm, dependant on specification requirement and these materials can be repaired and brought back to required thickness after exposure to fire. Epoxy intumescents are applied over a primed surface, normally zinc phosphate epoxy, but the materials must be tested and approved for use together. The tests are carried out at NAMAS/UKAS approved laboratories and are usually a lap shear test to test for adhesion between the primer and PFP. Inspectors should be aware that some EPFP material manufacturers do not recommend full DFTs of the primers, as measured in the manner specified by BGAS over the peak, instead preferring flat plate calibration giving readings from part way down the profile. 8-6 www.twitraining.com  Section 9 Anti-Fouling Paints  Rev 1 January 2010 Anti-Fouling Paints Copyright  TWI Ltd 2013 9 Anti-fouling Paints Substantial growth of foulants on a ship’s hull or an offshore structure such as a jacket considerably roughens the surface and in the case of a ship can considerably increase the drag factor. Even moderate fouling can reduce speeds by 10%. Economically this means loss of trading days and fewer payloads, through having to carry more bunker fuel. Fouling organisms exist when conditions are favourable, eg correct light intensity (photosynthesis for seaweed), salinity, temperature, available food, lack of competition, predators and aerobic and anaerobic conditions and are more likely to occur in static conditions, eg whilst at anchor, or in dock. Typical foulants are barnacles, mussels and tubeworms. Plant growth in the form of weed will be green (enteromorpha) on the vertical sections to red and brown (ectocarpus) on shaded areas. Bacteria and moulds are also classed as foulants. All the plant and animal fouling organisms mentioned above reproduce by forming spores or larvae which go through a free swimming stage prior to cementing themselves onto a ship’s hull or structure (or anything else convenient). Barnacles can take up to four days whereas the green and brown weeds take only a few hours. A ship with a quick turnaround in port therefore will be less liable to sustain barnacle growth. Anti-fouling coatings release materials toxic to the foulants. Roughly based on the theories of critical pigment volume concentration (CPVC), the materials work efficiently under certain specified conditions and release calculated amounts of toxic material, usually by leaching into the sea water, forming a thin layer of water around the hull or structure, in which spores and larvae cannot survive. A leaching rate of 10 microgram/cm2/day of cuprous oxide was considered sufficient for most foulants, but some moulds required slightly higher concentrations. Various toxins have been employed including lead, arsenic, mercury, copper, zinc and tin, but for obvious reasons use of heavy metals has been discontinued although use of tri-butyl tin (TBT), was prevalent until recent legislation. 9-1 www.twitraining.com  Rev 1 January 2010 Anti-Fouling Paints Copyright  TWI Ltd 2013 Anti-fouling coatings can be loosely categorised into four types. 1 Self-polishing or ablative Acrylic polymers are co-polymerised with organotin groups (which have biocidal properties), this breaks down due to hydrolysis and the toxin is released in a controlled manner. The surface of the polymers formed slowly erodes (ablates), revealing a smooth surface beneath, (hence the term self-polishing). This type, although expensive, gives a longer service life. 2 Soluble matrix type The binder in this type of anti-fouling is slightly soluble in the alkaline seawater and as the binder dissolves, toxins are released into the surrounding seawater. The slow process of the binder dissolving maintains the toxins in the surface, which presents itself also to standing water. These films are generally soft and only have a short expected lifetime (in the region of two years), so dry docking intervals are planned around that frequency. 3 Contact leaching type or insoluble matrix With this type of anti-foulant, the binder/bioactive ratio is virtually 1:1. The toxin, usually cuprous oxide, is in the structure of the film. As the particles progressively dissolve throughout the film they leave behind a honeycomb structure of non-soluble binder. 4 Foulant release coatings With this type of coating there are no toxins involved, based on silicon technology, these systems provide a very low surface energy on to which the foulants cannot adhere properly. The foulants can be easily removed by scrubbing with brushes or sponges and leave the substrate intact. This way is obviously far less expensive. All anti-foulants are applied over anti-corrosion coatings and are selected according to specific situations. 9-2 www.twitraining.com  Section 10 Alarms and Escape Routes  Rev 1 January 2010 Alarms and Escape Routes Copyright  TWI Ltd 2013 10 Alarms and Escape Routes A statutory requirement for alarm systems is there should be a bank of accumulators capable of operating it for a minimum of 60 minutes, able to operate visual and audible signals, eg flashing lights and a hooter. There is no specific requirement for what intermittent or continual lights and hooter signify, but the usual format is flashing or intermittent means be prepared to abandon, continual means abandon, although it is generally accepted that abandon must be by word of mouth from the OIM or his deputy. Whichever alarm is sounded the format is that initially, make the job safe and don life jacket and walk quickly to muster point. Illuminated escape signs are provided at low level along escape routes, so that in the event of inundation by dense smoke, the route may be followed at deck level. It is also usual to include deck lines (reflective strips or coatings, 100mm wide for primary routes and 50mm wide for secondary routes) so that if the line is followed in any direction it leads to a muster point. For the abandon signal, survival craft are required. These are usually Brücker capsules, totally enclosed capsule, which hold approximately 25 personnel and carry supplies of food and water and a radio for contact with rescue services. There is normally a minimum of two Brücker craft per platform, as well as other devices. 10-1 www.twitraining.com  Section 11 Safety Signs and Relevant Colours to BS 5378 (1980) Specification for Colour Design  Rev 1 January 2010 Safety Signs and Relevant Colours to BS 5378 (1980) Specification for Colour and Design Copyright  TWI Ltd 2013 11 Safety Signs and Relevant Colours to BS 5378 (1980) Specification for Colour and Design This is an internationally accepted standard that provides information by colour coding and symbols with minimum wording. All safety signs should comply with the standard (not just offshore) and it specifies colours and recommended shapes for all situations. Its primary function is to identify any hazard and thereby prevent accidents and to meet emergency requirements. The specified safety colours used on safety signs have a specified contrast colour for the symbol used on the sign and are:  BS 4800, 04 E 53 (red) has a contrast colour of white. The signs are circular with a white background and a red diagonal bar and red circumferential band. The black safety symbol should be placed centrally but should not obliterate the red cross bar. The sign should have at least 35% of its total area in red. These are generally prohibitive signs eg stop, but also show location of fire fighting equipment, etc.  BS 4800, 08 E 51 (yellow) has a contrast colour of black. The signs are triangular with a yellow background and a peripheral strip of black. Any symbol required should be centrally positioned. Allowing for lettering or symbols the total area of yellow should be at least 50%. These signs are used as caution signs, where there is a risk of danger, eg radiation from gamma or X-ray sources, low headroom, etc. This colour coding is also used for handrails offshore.  BS 4800, 14 E 53 (green) has a contrast colour of white. These signs are in the form of a square or rectangle of green, with a symbol or text in white positioned centrally. The sign should show be least 50% of its area green. Used to identify escape routes and emergency exits, first aid points, etc. Generally they are emergency and safe condition signs.  BS 4800, 18 E 53 (blue) contrast colour white. A circular sign with a blue background and any symbol or text in white placed centrally. At least 50% of the sign area should be blue. These are signs which are mandatory, eg must wear goggles or safety hats. Any of the above may also have a supplementary sign in the form of a rectangle or square with a white background with the text in black. It is also permissible for the supplementary sign to be in the same colour as the main sign, in which case the lettering must be in the specified contrasting colour. 11-1 www.twitraining.com  Section 12 Product by Pipe Colour Coding to BS 1710 (1975)  Rev 1 January 2011 Product Identification by Pipe Colour Coding to BS1710 (1975) Copyright  TWI Ltd 2013 12 Product Identification by Pipe Colour Coding to BS 1710 (1975) This system uses the BS 4800 colour standard to identify the product in a pipe, allowing easy traceability for maintenance work and ease of shutdown in the case of an emergency. Pipes can be coded in two ways. Paint the complete pipe in the appropriate colour for product identification, or paint colour coded strips (or apply coloured adhesive tape) on the pipe. The strips should be applied at such a frequency that from any position the product coding can be seen, eg both sides of valves, where the line changes direction, bulkhead/wall penetrations, etc. In some cases the codings have two or three strips to be more specific, sometimes supplemented with an arrow to indicate direction of product flow. Typical examples of colour coding are: BS 4800 Product Named colour App. Ref Air Light blue 20 E 51 Acids and alkalis Violet 22 C 37 Gases (except air) Yellow ochre 08 C 35 Fluids Black 00 E 53 Fresh water Auxiliary blue 18 E 53 Water Green 12 D 51 Electrical services Orange 06 E 51 Minimum vegetable and animal Brown 06 C 34 oils and combustible liquids 12-1 www.twitraining.com  Section 13 Cathodic Protection  Rev 1 January 2011 Cathodic Protection Copyright  TWI Ltd 2013 13 Cathodic Protection Cathodic protection is a secondary line of defence against corrosion, the primary defence being the coating. When damage to the coating occurs, eg through impact on the coating during back filling on a pipeline, sling damage during lowering, or flotsam impact on an offshore platform leg, the underlying steel can then be in contact with electrolyte and corrosion can occur. But if these areas can become cathodic, ie receive current, corrosion can be avoided. For CP to be applied, an electrolyte must be present, eg the external surface of a tank cannot have CP, but internal surfaces can if the tank is holding an electrolytic medium, only up to the level of medium, not above. Underground and subsea pipelines can be protected, but steelwork above ground in an AGI needs painting. Cathodic protection can be applied in two ways.  Sacrificial anode system.  Impressed current system. Sacrificial anode system This system, sometimes called galvanic anode system, works on the principle of bimetallic corrosion, the natural potential between metals. Any metal that is more electronegative (less noble), or below steel on the galvanic list can be used as an anode. The choice of metal would depend on the potential required to protect the prescribed area. Sacrificial systems only protect small areas and the anodes need changing regularly as they corrode. Approximately 50m maximum Connecting wire of copper. Minimum resistance Aluminium zinc or magnesium or alloys of these + Figure 13.1 Sacrificial system. Impressed current system This system will protect long lengths of pipeline from one installation, a distance of approximately 10 miles. The current to run the system comes from the national grid and is connected through a transformer rectifier (TR). The national grid is very high voltage, very high amperage and also AC. Anti-corrosion currents need to be DC so the TR rectifies the current to DC and transforms it to low voltage and amperage. 13-1 www.twitraining.com  Rev 1 January 2011 Cathodic Protection Copyright  TWI Ltd 2013 The positive side of the TR is connected to a ground bed (anode system) and the negative to the pipe, making the pipe the cathode. The current is released into the electrolyte at the ground bed, passes through the electrolyte and is received at areas of coating damage on the pipe. A typical ground bed will be approximately 50m in length, at the same depth as and running parallel to the pipe. The cables carrying the current are of substantial diameter and pure copper to produce a circuit of little or no resistance at the anode. The resistance encountered comes in the soil/clay/rock bearing the electrolyte and governs the driving voltage required and number of anodes required to maintain negative potential on the buried pipe. The voltage required varies, usually 10-50V at an amperage of around 0.15A. CP does not eliminate corrosion, it controls where corrosion occurs. To national grid supply Transformer rectifier Current received at cathode. Protected. Ground bed releases current into electrolyte Figure 13.2 Impressed current system. 13.1 Interference When a buried steel structure is near to or passes above or below another pipeline which is cathodically protected, problems can occur. This is interference but the term can be misleading. The offending structure does not adversely affect the CP system, but s affected by it. The interference structure picks up the current released from the anode bed and conducts it through a circuit of minimal resistance and re-releases the 13-2 www.twitraining.com  Rev 1 January 2011 Cathodic Protection Copyright  TWI Ltd 2013 current into the electrolyte near the protected line. The interference therefore becomes a secondary anode and can suffer severe corrosion. If there is a possibility of a structure causing interference then precautions need to be taken. With the permission of the owner of the offending structure, three main methods can be used. 1 Attach isolation joints one pipe length either side of the nearest point of the offending line to the protected line. Join the two pipe lengths to the protected line with insulated wire and doubler plates, thus making them the same potential. 2 Attach isolation joints to both lines, one pipe length either side of the nearest point. Join the two isolated sections together and install a sacrificial anode to protect both sections. 3 Double and contra-wrap the protected line giving four tape thicknesses with cold applied laminate tape for one pipe length either side of the nearest point. The method chosen is at the discretion of the engineer. 13.2 Monitoring CP It is considered that -850mV will maintain a pipeline in a passive state but most CP engineers will require a more negative value, -1 to –2V being typical. Checks need to be carried out at regular intervals to ensure the required potential is maintained. One method of monitoring is known as half- cell reference electrode, with the most commonly used being the copper/ copper sulphate half-cell electrode. It is used for measuring the pipe to earth potential, ie cathode to earth, the other half of the circuit being anode to earth. Periodically along the line, CP monitoring posts are installed, with a direct wire connection to the pipe, accessed from a stud on the CP post panel. A voltmeter is connected to the stud and to the copper/copper sulphate half- cell, which is then pushed into the earth directly above the pipe, providing a circuit for electrons from the pipe, into the electrolyte, back to the anode bed. 13-3 www.twitraining.com  Rev 1 January 2011 Cathodic Protection Copyright  TWI Ltd 2013 Half-cell reference electrode filled with copper sulphate solution Voltmeter CP post Ground level Porous plug Pipe Figure 13.3 Monitoring CP. 13.3 Cathodic disbondment Part of the electrical circuit of the corrosion reaction is the release of hydrogen gas from the cathode. Hydrogen is a very powerful gas and can cause cracking in steel, (HICC). If hydrogen gas can penetrate underneath a coating it can easily disbond it - cathodic or hydrogen disbondment. Over- protection of damaged areas on a pipe results in over-production of hydrogen and subsequent disbondment of more of the coating, resulting in a larger area to protect, needing more current. All material used on a pipeline have to undergo tests to determine their resistance to cathodic disbondment. The test method is: A 6mm diameter hole is drilled into a plate coated with the material to be tested, through the coating and into but not through the underlying steel. A short length, approximately 50mm, of plastic tube approximately 50mm diameter is fixed in position, typically using Araldite™ epoxy or elastomeric sealant with the drilled hole central to the tube. This is then part filled with 3% solution of common salt (sodium chloride) and a lid fitted. The lid can be machined from a block of polyethylene with a suitable diameter hole drilled through. The plate is connected to the negative pole of a battery, an anode connected to the positive pole and inserted through the hole in the lid into the salt solution. When the circuit is switched on the plate is the cathode and hydrogen (and chlorine) will be released from the steel and also at the interface of the steel/coating, enabling hydrogen to penetrate under the coating, simulating areas of coating damage. 13-4 www.twitraining.com  Rev 1 January 2011 Cathodic Protection Copyright  TWI Ltd 2013 Plastic Lid ring Elastomeric sealant Battery Coating Plate 6mm diameter Salt hole solution Figure 13.4 Cathodic disbondment. The circuit is stopped after 28 days, stripped down, dried off and using a craft knife, two cuts made at an inclusive angle of approximately 30° radiating from the centre of the hole, through the coating to the substrate. Where disbondment has occurred the coating will chip off as the cuts are being made. The distance from the edge of the hole to the disbondment is measured and should not exceed the stated requirements, for example FBE maximum 5mm after 28 days. 13-5 www.twitraining.com  Section 14 Revision Questions BGAS Grade 1  Rev 1 January 2010 Revision Questions BGAS Grade 1 Copyright  TWI Ltd 2013 14 Revision Questions, BGAS Grade 1 14.1 Paper 1 1 Give the names of three different decks on an offshore platform. 2 Give the identification system for offshore platforms. 3 Name two types of work permits. 4 Who is responsible for the issue of permits to work? 5 What is the number of the statutory instrument relating to offshore safety? 6 What should be the first thing done on arrival on a platform? 7 How often are medicals needed for offshore working? 8 Name three methods of attaching a platform to the seabed. 9 What are the safety aspects of boarding and travelling in helicopters? 10 What method is used to identify escape routes on an offshore platform? 11 What documentation is required to allow work inside a vessel offshore? 12 Who has the ultimate responsibility for safety offshore? 13 Are drilling muds acidic or alkaline? 14 What is the system used for identification of safe/unsafe scaffolding? 15 What qualifications are required to be able to inspect scaffolding offshore? 16 In descending order, list the safety precautions for over the side working when the use of scaffolding is considered to be impractical. 17 What is the timescale before it becomes compulsory for an offshore worker to have an