Health and Safety Executive - June 2015 · Web viewFor NON-PROCESS releases, e.g. Methanol, Glycol, Diesel, Lube oil, Seal oil, Bottle gas, Hydraulic oil, Fuel oil, Heat transfer

Final Draft 7.2 – Issued 13th July 2015 2015/150261

Guidance on reporting offshore hydrocarbon releases

Issued by the Offshore Safety Directive Regulator [OSDR]June 2015

Contents

1. Introduction

2. Background

3. EU Guidance on what constitutes an Event A

4. Guidance on completing Event A notifications

Appendices

Appendix 1 – Further guidance on System & Equipment Types

Appendix 2 – Reporting Criteria for Hydrocarbon Releases

Appendix 3 - References

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1. Introduction

Following the Deepwater Horizon incident in the Gulf of Mexico in April 2010, the European Commission [EC] published the Directive on Safety of Offshore Oil and Gas Operations [Offshore Safety Directive/OSD]. This Directive defines minimum requirements for preventing major accidents related to offshore oil and gas operations and to limit their consequences.

The Directive [2013/30/EU] requests the Commission by means of Implementing Regulations to develop a common data reporting format for the sharing of information on major hazard indicators by operators and owners of offshore oil and gas installations.

The Implementing Regulations are directly applicable to Member States who are bound by the wording of the new reporting criteria and the reporting forms.

Member States are required to ensure that operators and owners of offshore oil and gas installations provide to the competent authority, as a minimum, the data on major hazard indicators as specified in Annex IX of the Directive, to the level of detail required by the Implementing Regulations.

The Directive lists 10 major hazard indicators, which are described as “Events” on the EU reporting form:

Event A. Unintended release of oil, gas or other hazardous substances, whether or not ignitedEvent B. Loss of well control requiring actuation of well control equipment, or failure of a well

barrier requiring its replacement or repairEvent C. Failure of a safety and environmental critical elementEvent D. Significant loss of structural integrity, or loss of protection against the effects of fire or

explosion, or loss of station keeping in relation to mobile installationEvent E. Vessels on collision course and actual vessel collisions with an offshore installationEvent F. Helicopter accidents, on or near offshore installationsEvent G. Any fatal accident to be reported under the requirements of Directive 92/91/EECEvent H. Any serious injuries to five or more persons in the same accident to be reported under

the requirements of Directive 92/91/EECEvent I. Any evacuation of personnelEvent J. A major environmental incident

For each Event, the relevant Section of the Directive notification form must be completed. This guidance is in relation to type A events and Section A of the Directive notification form for the unintended release of oil, gas or other hazardous substances, whether or not ignited - hydrocarbon releases [HCRs].

However, in the event of an “Unintended release of oil, gas or other hazardous substances...” [i.e. an incident reportable under Section A], it is likely that Section C [failure of a Safety and Environmental Critical Element] will also have to be submitted. Section I [Evacuation of Personnel] may also be relevant.

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There are significant differences between Section A of the Directive notification form and its predecessors [the OIR9B and OIR12 forms]. In order to ensure continuity of HCR data there are additional voluntary fields within the Event A notification form [which are clearly indicated].

Whilst these additional fields are voluntary, OSDR encourages operators to complete all parts of Section A, as they have done with OIR12 notification forms since 1992. This will ensure consistency of HCR intelligence and compliance with Recommendation 39 of the Cullen Report [see below].

The purpose of this Guidance is to provide operators and owners with useful supporting information and examples to assist in completing Event A notifications, in a consistent way. It will also detail the preferred taxonomy to ensure continuity of data and to aid consistent completion. Whereas the EU reporting form generally has free text fields, the equivalent UK form will request that, where appropriate, the reporter selects from a predefined list in order to maintain consistency and avoid similar situations being reported differently. By completing the UK form, operators are complying with the requirements of the EU.

2. Background

Since 1992 operators and owners of offshore oil and gas installations in UK waters have voluntarily notified HSE of detail in relation to HCRs which are additional to those required in the mandatory OIR9B form. This is in compliance with Recommendation 39 of the Cullen Report, following the Piper Alpha disaster in 1988.

Recommendation 39 of the Cullen Report

The regulatory body should be responsible for maintaining a database with regard to hydrocarbon leaks, spills and ignitions in the industry and for the benefit of the industry. The regulatory body should:-

discuss and agree with the industry the method of collection and use of the data,

regularly assess the data to determine the existence of any trends and report them to the industry, and

provide operators with a means of obtaining access to the data, particularly for the purpose of carrying out quantified risk assessment [para 18.43].

This additional voluntary detail is included within the equivalent UK reporting form.

HSE has hosted the HCR database [HCRD] since 1992. This has been the main repository for notified HCR detail. The HCRD will continue to be populated by Event A notifications and there will be no loss of continuity in data pre-Directive and post-Directive providing operators continue to co-operate in providing the relevant data.

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3. EU Guidance on what constitutes an Event A

A: Unintended release of oil, gas or other hazardous substances, whether or not ignited;

[1] Any unintentional release of ignited gas or oil on or from an offshore installation;

[2] The unintentional release on or from an offshore installation of:

[a] not ignited natural gas or evaporated associated gas if mass released ≥ 1kg

[b] not ignited liquid of petroleum hydrocarbon if mass released ≥ 60 kg;

[3] The unintentional release or escape of any hazardous substance, for which the major accident risk has been assessed in the report on major hazards, on or from an offshore installation, including wells and returns of drilling additives.

A: Unintended release of oil, gas or other hazardous substances, whether or not ignited;

This includes reporting of process or non-process petroleum hydrocarbon fluids in 1 and 2 below.

In order of the reporting requirements of the Implementing Regulation above:

[1] Any unintentional release of ignited gas or oil on or from an offshore installation;

Any release must be reported, irrespective of the potential to cause a major accident. Exclusions: (no requirement to report under this Regulation) controlled ignited releases

which are part of recognised safe operations such as flaring.

[2] The unintentional release on or from an offshore installation of:

[a] not ignited natural gas or evaporated associated gas if mass released ≥ 1kg

1 kg means 100% natural gas.

Exclusions: (no requirement to report under this Regulation)

Gas releases which are recognized as safe operations (emergency-shutdown, venting gas manually to depressurize equipment in a controlled manner) or which is part of the designed process (automatic release via a blowdown system or venting system) should not be reported. However, where an intentional gas release, which is considered a safe operation, escalates to the extent where immediate actions in addition to the arrangements for safe operation result either automatically or are required by manual intervention to reduce risks then this release should be reportable.

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Example:“ During a routine manual blow-down of some gas lines routed to the atmospheric vent, vapour from the vent drifted toward a local equipment room ventilation intake. Gas was drawn into the room and local gas detection in the ventilation ducting shutdown the equipment automatically. The weather was abnormally calm and still.”

Fugitive emissions (ref. part 2 definitions) shall not be reported under this Regulation as long as they are less than 3 kg/h or a 20% LEL at 50 cm is not reached. Emissions of this nature are unlikely to present a significant safety hazard, and consequent risk of fire/explosion.

[b] not ignited liquid of petroleum hydrocarbon if mass released ≥ 60 kg;

[3] The unintentional release or escape of any hazardous substance, for which the major accident risk has been assessed in the report on major hazards, on or from an offshore installation, including wells and returns of drilling additives.

This includes the release of any dangerous/hazardous substance identified in the assessment of major accidents in the RoMH as defined in OSD Article 2 sub (1) which would lead to a significant potential to cause fatalities or serious personal injury.

GeneralThe information requested in the reporting form in section A includes:-

- A1.I type of substance leaked [non-process, crude oil, condensate, gas or 2-phase], - A1.II estimated quantity released,- A1.III estimated initial release rate,- A1.IV estimated duration of leak. The estimate of rate and quantity released must take into account the substance leaked, the physical & process conditions and the successful operation or otherwise of SECEs intended to limit the quantity released. The methodology can be based on the physical effects modelling used in the Report on Major Hazards for the installation or on recognised formulae and standard assumptions as referenced or validated by competent person[s]. Find below reference examples:

http://www.irfoffshoresafety.com/country/performance/scope.aspx http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/HS021.pdf

However, care should be taken to ensure that the assumptions inherent in these methods are valid for the cases being reported.

NotesIf the owner/operator considers that a release is likely to be judged by the competent authority to be a major accident and a SECE has failed, then section C should also be completed.

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http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/HS021.pdf

http://www.irfoffshoresafety.com/country/performance/scope.aspx


If a release might have significant adverse effects on the environment then the owner/operator should complete all the relevant fields in section A.

4. UK Guidance on completing Event A notifications

Brief Description of EventPlease describe the circumstances, causes, and consequences [nature, scale/ extent] of the event and the emergency actions and response taken. Please provide an indication of the timeline of the event and also note any unusual or significant features relating to the event. The level of detail is dependent on the complexity of the situation but a small paragraph is expected as a minimum.

An example is provided below:

During well metering operations and oil sampling activities sample point isolation valve left open following an unexpected vent of gas / liquid initiating a GPA.

Type of InstallationTick one box for the production type of Installation i.e. Production or non-Production. Tick one box to indicate the Occupancy type, Function Type and the Structure type.

Position of the installationThese apply to both Fixed and Subsea Installations.

The Quadrant and Block No. are stated on the registration documents, and are needed to categorise the general location of the Installation, e.g. Northern, Central, Southern North Sea, etc.

Water Depth is self-explanatory, and should be given in metres.

A1 - Was there a release of hydrocarbon substances?If there was a release of a hydrocarbon substance then the operator should complete the whole of Section A [A1 I-XV and A2, A3 & A4].

If the release was hazardous but not a hydrocarbon substance then the operator should only complete Sections A2, A3 and A4.

i. Hydrocarbon [HC] ReleasedFor NON-PROCESS releases, e.g. Methanol, Glycol, Diesel, Lube oil, Seal oil, Bottle gas, Hydraulic oil, Fuel oil, Heat transfer oil, Helifuel, Oil based mud, or other, tick the NON-PROCESS Release box and specify which type of hydrocarbon is involved.

For PROCESS releases, tick the appropriate box for Oil, Condensate, Gas or 2-phase [includes multi-phase fluids].

Releases of unprocessed hydrocarbon fluids [from wells, flowlines, manifolds and drilling/workover operations] should be reported as 2-phase.

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Releases downstream of separation [such as oil/gas/produced water releases, for example] should be reported as the hydrocarbon type related to the parent stream i.e. gas, oil, or condensate, not as 2-phase.

H2SFor either gas or 2-phase please state the level of hydrogen sulphide [H2S] content in the process stream in parts per million [ppm]. If the H2S is of a low value[less than 5 ppm] then please state “insignificant”. The aim of this input is to assess the relative toxicity of the gas, so approximate values would be sufficient.

Gas Molecular WeightFor gas, estimate the molecular weight. This should be the average or indicative molecular weight of the gas or vapour being released, and allows the calculation of the density of the gas in a manner that is independent of the pressure at which the density may be stated.

Gas/Oil Ratio [GOR]For 2-phase releases please state the Gas to Oil Ratio [GOR] as this will indicate the relative fractions of gas and oil in the fluid [preferably by mass], which may be important in understanding the nature of the release and any dispersion or ignited hazards. Preferred unit is kg gas/kg hydrocarbon.

Liquid DensityPlease state liquid density at working conditions in kg/m3. This can be used to calculate the release rate and/or for use in further conversions.

Water CutWhere relevant please state the water cut, expressed as a percentage by mass of water in the liquid phase.

The water quantity should then be deducted from the “Estimated quantity released” in the subsequent section, as this quantity relates to the hydrocarbon or hazardous substances only.

Was the release limited/stopped due to a local manual intervention / isolation, separate from the ESD system? It is known that in many cases of loss of hydrocarbon containment, the quantity actually released is rather less than the isolated volume and that therefore the consequences of a release of the reported hole size is less than would otherwise be assumed given the inventory, the operating conditions and the implementation, or otherwise, of isolation and blowdown systems reported elsewhere in the form. This may be because it was possible to isolate the leak closer to the point of release than the ESDVs or because while the emission was from a relatively large final aperture, the flow was choked by a much smaller orifice, such as a valve not properly closed.

This question is intended to identify if such a situation was relevant to the incident being reported. If so, the details should be provided in the event description.

Some examples of a local manual intervention / isolation, separate from the ESD system are; activating a local pump stop, or closing a manual valve.

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Liquid spray / mistPlease indicate whether or not a liquid spray / mist release occurred [i.e. where droplets / aerosol were generated by the release].

ii. Estimated Quantity ReleasedThis is required to indicate the size of the leak, and also for estimating the percentage of overall process inventory lost. It is therefore important to give an estimate for this, in whatever units are available. The value entered should be for hydrocarbons and not include water content The preferred unit is kg.

The following graphs and tables help give guidance on estimating the mass of gas released for different leak hole sizes, pressures, pipe system inventories etc.

Definition: Nm3 [normal cubic metres] - volume at normal temperature and pressure.

Basis for estimation If the actual amount released cannot be readily estimated, then an acceptable way of determining this in many cases, given that the "normal" total inventory is known, would be to subtract the remaining inventory from the normal inventory to obtain the estimated amount lost. This should also allow for the flow into and out of the section prior to isolation and the amount flared or drained.

Again, if the percentage of inventory lost can be estimated, then the amount released can be found from comparing this to the normal total inventory, remembering to state the units used.

This section requires an estimate of the size of the hydrocarbon release only and should not include water and/or other non-hazardous substances. If the quantities of water and other non or low hazard substances is not significant then the impact of these on the estimate of the quantity released these can be ignored.

Total gas and liquid HC inventory in systemThe total hydrocarbon inventory in the system may be defined in general terms as that quantity of inventory held in the system at the time of release, which is isolatable from other systems, for example between ESD valves. Preferred unit is kg, but other available units will suffice. Significant water or other non-hazardous substance inventories should not be included in this total system inventory estimate.

The calibre of information quoted in this field is variable, and sometimes difficult to relate to the “estimated quantity released”. Since there is a need to relate estimated quantity released to the total HC inventory, in terms of estimated percentage inventory lost, the units used should preferably be the same. The preferred unit is kg.

Extent of dispersion / liquid spreadThis information will be particularly helpful for modeling release behavior in certain cases and under certain conditions. Please give details of how the hydrocarbon accumulated or dispersed in the area. Ideally this should include, where possible, the extent of the gas cloud to a given concentration, preferably LEL and ½ LEL or some limit of detection, and a broad indication of the extent of any spray

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jet or liquid jet in terms of its length and width or pool or resulting gas cloud in terms of its area, and whether any liquid was discharged to sea.

An indication of which detectors were activated and their distance from the source may be useful.

As well as giving details of how hydrocarbons accumulated or dispersed in the area, this box may also be used to describe details of gas detection [in terms of LEL etc.] together with details of why fixed gas detection failed to detect a particular leak.

iii. Estimated initial release rateThe initial release rate can be estimated from standard release rate calculation techniques based on the operating conditions at the time of the release, the fluid properties and the estimated hole diameter. It is recognized that estimating the release rate for 2-phase or flashing releases can be complex. Such releases can be modeled using suitable consequence software or alternatively a conservative estimate can be made based on assuming a liquid only flow. The calculation should be based on the conditions at the start of the release, and not take account of any subsequent isolation or blowdown. It is recognized that some releases from large hole sizes at high pressure may give very high initial release rates, which are unsustainable when compared to the inventory within the system. The preferred unit is kg.

The release rate can be back calculated, e.g. from the extent of any gas dispersion, to estimate the release rate and equivalent hole diameter [see below].

Equivalent hole diameterHole size should be recorded as the diameter [preferred unit is mm] of a circular hole of the same cross sectional area as the release. Please also indicate whether the hole size was measured or estimated.

The preferred method is a direct measurement of the actual hole size. If this is not practical, back calculation methods maybe needed to estimate the hole size.

Hole size is important in the estimation of release rate. In order to standardize the calculation of these within the database, the actual size of hole involved in the leak of hydrocarbons needs to be related to an equivalent round hole of the same area and thence to its diameter.

Hole sizes are used to determine hole size distribution per type of system or equipment, which then gives an indication of probability of the hole size in a loss of containment event.

iv. Duration of leakThe release starts when the fugitive emission limit is detected as having been exceeded. The duration of the leak is the estimated elapsed time between start of leak and time of termination.

Where the start time cannot be readily determined, then estimate the time from discovery e.g. alarm, electronic log or by visual means, etc.

Termination of the leak is defined as the time that the release was stopped, not simply when it was brought under control, or when an ESD was initiated.

The preferred unit is seconds.

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v. Location of LeakIn the free text box please indicate the name in most common use for the Area or Module involved, including subsea if appropriate. For example “underside of flange located 3.5 metres along the gas outlet line from the first stage separator in process module P1”.

In the system/equipment drop down boxes for:

Systems Equipment

and where relevant

Valve type Flange type/rating/size category

It is essential that only one system and one item of equipment is indicated on the form for any one hydrocarbon incident. Appendix 1 to this guidance gives further guidance on the definition of each system, and equipment type.

For valves, flanges, pumps, tubing, pipework, pipelines and other fittings please also specify the actual size in terms on nominal bore in mm, which may mean the nominal bore of the piping that the equipment is connected to.

It is essential that the single system from which the release emanated be chosen.

A number of hydrocarbon releases are "carry-over" type incidents, where a release occurs and the hydrocarbon passes through other systems / equipment before subsequently being released to atmosphere. [E.g. via the flare system].

Where possible, the system [and equipment] selection should represent the items from which the hydrocarbon emerged [e.g. piping within the flare system]. In “carry over” incidents, the causation details may then be used to reflect the mode of failure of the system and/or equipment item that caused the release.

System Selection Hints:Incidents involving Drilling Operations should be recorded as "Drilling" from the system list. They must also be further described as either Exploration or Appraisal or Development or Completion, by selecting the appropriate parameter from this section of the form. The selection should also show whether the operation was on an Oil or Gas well, and one of the water depth ranges [viz: <100m, 100-700m, 700-1000 metres, >1000 metres] should also be selected.

Incidents involving Well Operations [i.e. wireline, workovers] should also be coded as "Drilling" from the system list. They must also be further described as either Wireline or Coiled Tubing or Snubbing or Well Test or Recompletion or Abandonment [or Other if necessary]. The selection should also show whether the operation concerned was on an Oil or Gas well, and whether the operation was With Tree or Without Tree.

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Incidents involving permanent drilling equipment should also be coded as "Drilling" from the systems list, but no further system related information is required in this instance. The equipment type should then be specified using only the Mud / Shale / Drilling option on the equipment list.

“Well Control” system should be selected for BOP equipment releases.

“Well” system should be selected for Wellhead or Xmas Tree equipment releases. The type of well should then be indicated from oil production or gas production or gas injection, and whether surface or subsea.

Avoid coding all topsides incidents as "Processing".

“Processing” systems should be either oil or gas.

“Utilities” systems should be either oil or gas.

“Flowlines Other” includes choke and kill lines.

“Manifolds Other” includes choke and kill manifolds.

Incidents involving a fuel line to a turbine should be recorded as either the “Diesel” or “Fuel Gas” system, rather than the “Power Generation” system.

Equipment Selection HintsSelect a Primary equipment type from the drop down list.

Depending on choice of Primary equipment, a Secondary choice may be needed. Select this from the drop down list. Again, depending on Primary and Secondary choices, a Tertiary choice may be required. Select this from the drop down list.

Example: 2” compressed joint flange is selected as follows:

Primary Choice: Flange Secondary Choice: Compressed joint Tertiary Choice: D < = 3”

It is essential that the single equipment item from which the release emanated be chosen.

Equipment lists are based on the definitions quoted in Appendix 1 of this guidance and the choices made should best describe the equipment item considered to be responsible for the release.

No equipment type need be selected for Drilling Operations, since the equipment population in the database excludes down hole components.

No equipment classification is required to be selected for Well Operations [or workover] as these are characterized by the use of temporary equipment, which is not a permanent part of the installation.

For a permanent drilling system failure [i.e. not Drilling/Well Operations] the equipment type should then be specified using only the Mud / Shale / Drilling option.

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“Well Control” system incidents should only ever be related to BOP equipment [and not component flanges / valves etc.].

“Well” system incidents should only ever be related to Wellhead or Xmas Tree equipment [and not component flanges / valves etc.]

Incidents involving a fuel line to a turbine should be coded as either the “Diesel” or “Fuel Gas” system, rather than the “Power Generation” or “Gas Compression” system.

Topsides flowline incidents should be associated with piping, rather than pipelines.

Swivels, as employed in FPSO turrets, are a special type of flange and should be chosen from the list of flange types given.

It is important to distinguish between major equipment items such as compressors / turbines / pumps, and the piping connected to them. Only select the major equipment if the release was from the actual vessel, pump or compressor, otherwise choose the actual flange, piping, valve or instrument as the piece of equipment involved.

vi. Hazardous area classificationInformation on the zone classification at the location of the incident is required here, to give an indication of likely ignition sources. Please tick the appropriate box.

Zone 1: An area in which hydrocarbons, in the form of an explosive vapour/air mixture, is likely to occur in normal operation [drill floor, vent or flare area].

Zone 2: An area in which hydrocarbons are not likely to occur in normal operation, and if occurring will exist only for a short time [process, wellhead area].

Unclassified: Non-hazardous area [e.g. accommodation].

vii. Module ventilationAn example of forced ventilation is HVAC controlled.

How many sides enclosedThe number of sides enclosed should be entered in the box provided. Score 1 for each complete side including floor and ceiling, but only score as 0.5 if floor and/or ceiling involve open grating.

Allowances should also be made for louvres or other openings affecting ventilation by similarly "factoring" the effectiveness of the side involved, e.g. entering 0.8 for a louvred wall, or 0.75 for one which has an opening at the top of the wall for its entire length.

A module will therefore have a maximum of 6 sides for a fully enclosed module not involving grating, louvres, etc.

Module volume & air changesGive the approximate module volume in m3, and also estimate the number of air changes per hour.

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viii. Weather conditionsAs for module ventilation, this information is used in modeling the behavior of leaks, and also to check against the actual reported behavior.

Wind speedThe preferred unit is m/s.

Wind direction Wind direction is required as a heading compared to True North, in degrees, to nearest whole number. The direction indicated should be that from where the wind is blowing.

Other weather conditionsThe type of other weather conditions could include cloudy, overcast, raining, snowing, or foggy, etc. Air temperature could also be stated here, and sea state and visibility where relevant.

For weather-vaning FPSOs please state heading at the time of release.

ix. System Pressure

Design pressureFor Design Pressure please state the maximum allowable operating pressure [MAOP] of the system or equipment involved. This may not necessarily be the same as the original design pressure, because there may have been a down rating involved at some point.

The preferred unit is barg.

Actual pressureFor Actual Pressure please state the pressure that the equipment was operating under at the time of release. This is not necessarily the normal working pressure, since some change in pressure may have been experienced prior to failure.

The preferred unit is barg.

Design Temperature [maximum]For Design Temperature [maximum] please state the maximum design temperature of the system at which it is safe to operate. This may not necessarily be the same as the original design temperature, because there may have been a down rating involved at some point.

The preferred unit is oC.

Design Temperature [minimum]For Design Temperature [minimum] please state the minimum design temperature of the system at which it is safe to operate. This may not necessarily be the same as the original design temperature, because there may have been a down rating involved at some point.


Actual TemperatureFor Actual Temperature please state the temperature that the system was operating under at the time of release.

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x. Means of detectionPlease tick the appropriate box [or boxes if more than one means of detector was involved].

xi. Cause of leakIn the free text box please give a brief description of the cause of leak.

Cause of leakPlease see the Cause of Leak Checklist [which also includes the operational mode in the area at the time of release].

Any amount of boxes can be ticked to indicate the cause[s] of leak.

This information is helpful in determining trends in design, equipment, operational and procedural failures related to hydrocarbon releases.

Further details of each of the 4 cause of leak types are given as follows:

DesignIf there is a suspected design fault in the equipment or related system which contributed to the hydrocarbon release, then tick the relevant box.

This option is intended to include failure to design against anticipated levels of corrosion, erosion, fatigue and wear. However, where the corrosion etc. that caused the leak is greater than anticipated in the design then this shouldn’t be classed as a design failure.

EquipmentFailure of equipment is a common contributor to hydrocarbon leaks, and the main categories are listed on the form. If the mode of equipment failure is not included here then tick OTHER and specify the fault.

OperationThe main operational failure modes are listed in the form, but if the leak is attributable to one not on the list, then tick OTHER and specify.

ProceduralAny procedural failure should be notified if it contributed to the release of hydrocarbons. Please tick the relevant [most appropriate] box[es], or add details to OTHER if required.

Operational mode at the time of releaseCompletion of this section helps to identify those operational modes prone to hydrocarbon releases. Operational Mode should be used to confirm the status of work ongoing in the area of and at the time of the release. This means that if some maintenance, construction, pigging, workover, sampling, equipment start-up, or other operation was being carried out on or around the equipment when it leaked, then that box should be ticked, even if the remainder of the Installation was in normal production. For some Operational Mode selections, further factors may need to be specified during selection as given below.

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It is important to record the mode of operation at the incident site not the mode of operation of the installation as a whole, which may be different.

From the drop down list, choose one of the following:

Blowdown Cleaning Commissioning Construction Drilling Flushing Inspection Installation Maintenance Routine Maintenance Normal Production Pigging Reinstatement Removal Replacement Sampling Shutdown Shutting down Start Up Temporary Testing Top Up Well Operations with tree Well Operations without tree

Drilling or Well Operations The choice here should match the system selection [see section on system selection above].

Normal ProductionUse this only where everything was normal with no intervention going on in the area.

Note for non-production installations the category “normal production” should be selected to indicate normal operation of that non-production installation.

Reinstatement / Start upReinstatement should be used where the system was re-started following work carried out on the item or plant from which the release emanated including maintenance / construction operations, inspection, testing, venting etc. including planned shutdowns.

Start-up should be used where the system was re-started following an operational shutdown such as a plant trip etc., and where no intervention work was carried out.

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If the Reinstatement / Start-up is known to have followed a shutdown but it is not clear whether this was following maintenance or construction etc., then REINSTATEMENT should be assumed.

If it is not known whether the Reinstatement / Start-up followed a shutdown or not, then START-UP should be assumed.

xii. Did ignition occur?If there was ignition, then tick if it was immediate or delayed. The ignition type should be classed as immediate where the cause of the leak and the cause of ignition were the same, e.g. a hot work / cutting incident, or if some form of auto-ignition occurred due to the stream temperature or instant contact with a hot surface or other ignition source at the point of release.

Delay timeIf delayed, then please add estimated delay time, i.e. time between start of leak and the point when it ignited, [preferred unit is seconds].

Where the ignition was of a continuous operational release [e.g. accidental ignition of a cold vent] or in a location where a flammable mixture is normally present then enter the ignition timing as ‘immediate’ and tick the ‘continuous operational release’ box. . This will signify that the release would not have been reported if it had not ignited.

Where the leak start time cannot be readily determined, then use the detection time, where “detection" means the first instance of detection of the leak e.g. alarm or by visual means, etc.

If the release needed to disperse to reach its ignition source, then this should be recorded as delayed ignition and an estimate of the time to ignition provided.

Sequence of ignition eventsIt is important to know the actual SEQUENCE of events during ignition, and therefore the order of occurrence should be indicated by numbering the appropriate boxes accordingly.

For example, if there was an explosion followed by a jet fire, put "1" in the EXPLOSION box, and "2" in the JET FIRE box. If, however, there was a flash fire followed by a pool fire, and then by a jet fire, the sequence would be "1" in FLASH FIRE, "2" in POOL FIRE and "3" in JET FIRE.

An ignited spray fire should be recorded as a Jet Fire.

Where some form of blast damage or indication of a blast wave was present [e.g. persons felt blast wave], record this as an explosion. Otherwise, the ignition of the gas or vapour cloud should be categorised as a flash fire.

xiii. Ignition SourceThis information is useful for modeling ignitions, and for analyzing ignition probabilities. If known, details of the source[s] should be given here. For example, hot work in area, spark from electrical contact, hot exhaust, spark from metallic impact, etc.

xiv. Emergency ActionThis information contributes to the estimation of frequencies of SAFETY SYSTEMS intervention, and to the frequency and extent of MUSTERS as a result of hydrocarbon releases.

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Call to Muster at stations includes all designated muster stations on the installation including the Temporary Refuge area.

Shutdown and Blowdown emergency action codes do not solely relate to the shutdown and/or blowdown of an entire system, but may also be used to describe instances of shutdown/blowdown of individual items of machinery and sections of process, rather than describing these in the "other emergency actions" field [though isolation activities can be coded as "other emergency actions"].

Shutdown is either a full platform or system shutdown but also includes a much smaller isolation of a system part, i.e. any closure of a valve which limits the inventory available. If any of the ESDVs fails to close this should also be reported in section C.

If the section where the release occurred was already isolated e.g. due to maintenance in progress, Shutdown can still be selected.

Tick the appropriate boxes for any actions taken, and whether they were automatic or manual. The aim of this is to assess if shutdown was by automatic instigation of an actuated valve, manual instigation of an actuated valve or local isolation as a result of an operator closing a valve.

In the case of any other type of emergency actions taken, tick other and specify e.g. fire teams deployed.

If relevant please tick the evacuation box [es] for any partial down- man or full evacuation by helicopter, lifeboats, or other.

xv. Any additional commentsPlease describe the circumstances, causes, and consequences [nature, scale/ extent] of the event and the emergency actions and response taken. Please provide an indication of the timeline of the event and also note any unusual or significant features relating to the event which are not covered in the brief description at the beginning of the form.

There are invariably some relevant facts pertaining to the incident which are not quite covered by the headings on the form. Please add these details in this box which may be pertinent, e.g. details of any damage and/or fatalities sustained, etc. This should include details of impairment of walls, decks and support structures and escalation to other hydrocarbon containing equipment.

A2 Description of circumstances, consequences of event and emergency responsePlease describe the circumstances, causes, and consequences [nature, scale/ extent] of the event and the emergency actions and response taken. Please provide an indication of the timeline of the event and also note any unusual or significant features relating to the event.

Current [June 2015] intentions are for this section to be left blank in the UK form because it will be auto populated with the text from the initial brief description section.

A2.1 Non-hydrocarbon hazardous substance releaseNon-hydrocarbon hazardous substances include H2S, CO2, Amine.

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A2.2 Non hydrocarbon fireIf a non-hydrocarbon fire occurred such as an electrical fire, with a potential to cause a major accident then please describe the circumstances here.

A2.3. Likely to cause degradation to surrounding marine environmentIf the incident is likely to cause any degradation to the surrounding marine environment then please outline the environmental impacts that have either already been observed or are likely to result from the incident.

A3 Preliminary direct and underlying causesPlease indicate preliminary direct and underlying causes of the event.

Direct CausesDirect [or immediate] causes are the unsafe acts or conditions that initiated the release.

The operator may answer this part of the question by simply referring to his answer in A.1.XI – Cause of Leak checklist.

Underlying CausesUnderlying [or root] causes are the failings that allowed the unsafe acts or conditions that initiated the release.

Underlying causes may need to be explored further as they usually arise from organisational or safety management system failings.

When completing sections A3 operators and owners should use causes listed in Annex II section 4.5 of the IR (copied below) to assist in the preparation of the annual publication report (Annex II of IR)

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Identifying deficiencies in risk control management systems will enable operators to improve their management of risk in the future, and this will feed into lessons learnt and recommendations to prevent recurrences of similar incidents. As such it is important to effectively identify relevant underlying causation.

A4. Initial lesson learned and preliminary recommendations to prevent recurrence of similar incidentsThe operator’s investigation and analysis of incidents forms an essential part of how they manage safety. However, learning the lessons from what is uncovered and making recommendations is at the heart of preventing recurrences.

As such it is imperative to be as candid as is possible and to get to the “heart” of the issue.

It is also important to note that a poor response to this question may reflect a flawed investigation process.

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Appendix 1 – Further guidance on System & Equipment Types

System type categorizationIn order to indicate which system is involved in the incident, select from the first drop down box the relevant [most appropriate] system category. Then select from the 2nd drop down box, then the 3rd drop down box to further define the system.

For example, if a subsea oil production well is involved, then select WELL in the first drop down box select OIL PRODUCTION in the 2nd drop down box and select SUBSEA in the 3rd drop down box.

A list of system definitions is provided below. The boundary limits for each system will generally be at the ESD valve isolations between systems, unless otherwise indicated.

It is important that the chosen system interfaces are adhered to when reporting hydrocarbon releases, since these are then matched to the relevant population data which should also adhere to these same interfaces.

BLOWDOWN:The equipment associated with process blowdown and depressurization, usually situated between the respective Process and the Vent/Flare system.

The blowdown system ends and the vent or flare system starts at the blowdown valve.

DRAINS:Includes transfer pumps, de-gasser vessels and piping, valves and flanges, with caissons included in drains piping. Note that oil and condensate are assumed to share common drains.

DRILLING:This category comprises mud, shale, kill, de-gasser, diverter, riser [incl. lower riser package] and workover equipment including any piping, valves, and flanges, but excluding BOP stacks, wellhead connections and xmas trees.

EXPORT:This category includes all export pipeline/risers and associated equipment out of the 500 meter safety zone.

In the case of crossovers between export and import systems, there would normally be an agreed interface between the systems [usually at a common isolation valve] which should also be adhered to for reporting purposes.

Tankage used for storage of stabilized crude prior to export should be included here.

FLARE:An LP flare is usually the system handling all [low pressure] process effluent gases.

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An HP flare is for handling all [high pressure] process upset releases from blowdown due to overpressure etc.

The Flare system is defined as being from the header and anything downstream. The Blowdown system would then be from the BDV to the flare header.

FLOWLINE:In this case the boundary is not at a valve but at the manifold connection.

Flow lines are lines that have been designated by the operator as Major Accident Hazard Pipelines [MAHPs].

Comprises the piping, flanges, valves and instrumentation between the wing valve [and the annulus valve for lift gas] and the relevant manifold [or pipeline isolation valve in the case of a subsea satellite well].

This category includes all flow lines, with the potential of carrying hydrocarbons, both topsides and subsea. It should be noted that the lines between subsea satellite wells or manifolds and the parent installation are counted as pipelines. Choke and kill flow lines should be included under "other".

GAS COMPRESSION:This includes all interstage scrubbing/cooling equipment associated with the compression process, as well as the compressors themselves, and including piping, valves, and flanges.

"Gas" means product gas compression for export, injection, or gas lift purposes.

IMPORT:Includes all import pipelines/risers and associated equipment in from the 500metre limit, plus all piping etc. from the recognized pipeline [valved] interfaces up to the interfaces with the systems being served, which may include export cross-overs [see above].

MANIFOLD:The common gathering or distribution header, topsides or subsea, for all flow lines of a particular type, e.g. gas lift manifold, oil production manifold, gas injection manifold, etc.

This category includes piping, valves, flanges, and instrumentation forming the manifold and terminating at the next downstream isolation valve, for import manifolds or upstream isolation valve for well injection and gas lift manifolds.

Choke and kill manifolds should be included under "other".

METERING:This category includes prover loops, densitometers and other equipment specifically supplied as part of the metering package. The meter runs themselves, i.e. excluding valves, flanges and instruments, should just be counted as piping within the metering system.

All turbine meters and/or fixed orifices located in other processes are to be counted as instruments in those processes.

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PROCESSING:These are the downstream processes associated with gas and/or oil treatment, but excluding all other systems stated elsewhere in the form [e.g. separation, compression, utilities, etc.].

Oil Processing systems are: Oil Treatment; Produced Water Treatment; Methanol Injection; Chemical Injection.

Gas Processing systems are: Dehydration; Produced Water Treatment; Methanol Injection; Chemical Injection; LPG/Condensate; Sour [CO2, H2S] Treatment.

SEPARATION:This category includes all vessels, valves, piping etc. associated with product separation as distinct from other "downstream" processes which are covered in processing systems [see below].

It should be noted that test separation systems are to be treated as separate from production separation systems.

A distinction is also made between gas separation and oil separation, but this applies only to the main feed product being treated, i.e. if the majority, by mass, of inflow hydrocarbon is gas then it is a gas separator and if not it is an oil separator.

Gas and condensate lines and other equipment associated with oil separation are therefore counted as oil separation, and not as gas separation.

UTILITIES:This category mainly includes the non-process systems which involve hydrocarbons.

OIL utilities are: Helifuel/Jet fuel; Diesel; Heat Transfer Oil; Power Generation Turbines [oil only].

GAS Utilities are: Fuel Gas and Power Generation Turbines [including dual fuel].

VENT: An LP vent is also known as the atmospheric vent.

An HP vent is any vent system working at higher than nominally atmospheric.

Both categories also include any associated vessels, piping, valves, and flanges.

WELL:This category also includes Xmas tree, wellhead connection, and the well itself.

Note that a gas injection well means one where gas is injected into the reservoir. A gas lifted well is one where lift gas is employed to assist flow, and should be counted as a production well.

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WELL CONTROL:This category includes all BOP stacks permanently held on the Installation, both Surface and Subsea, but not the piping, valves, and flanges connected to them [which will either be in flowlines or drilling systems].

Equipment categorizationThe information given here will ensure that the release is allocated to the appropriate item of equipment.

It is essential that only one equipment item is indicated on the form for any one hydrocarbon incident.

From the first drop down box select the relevant [most appropriate] EQUIPMENT category, select sub-categories from the 2nd and 3rd drop down boxes to further define the equipment item involved.

For example, for a leak on a 24” flexible pipeline select PIPELINE from the 1st drop down box, FLEXIBLE from the 2nd drop down box and D>16 from the 3rd drop down box.

A list of equipment definitions is provided below.

BOP STACKSThis category includes valves, flanges, rams, etc. down to the wellhead connection and up to the first flange, but excluding all piping, valves and fittings beyond the first flange [e.g. flowline or choke/kill connection] and excluding the flange itself. Please also indicate the design pressure rating, e.g. 5,000 psi.

COMPRESSORSThis category comprises the COMPRESSOR itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

CRUDE OIL STORAGE TANKSThis category comprises the CRUDE OIL STORAGE TANK itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

DEGASSERSThis category comprises the DEGASSER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

DIVERTERSThis category comprises the DIVERTER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

DRAIN OPENINGDrain openings are included as a separate equipment type. The remainder of the drain system would be piping, valves, etc.

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DRAIN PLUGSNo further guidance on this category

EXPANDERSNo further guidance on this category

FILTERSThis category comprises the FILTER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

FIN FAN COOLERThis category comprises the FIN FAN COOLER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

FLANGEAn individual flange is considered to be a single face rather than a flange joint. Please also indicate Flange type [see below].

HEAT EXCHANGERSThis category comprises the HEAT EXCHANGER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

INSTRUMENTThis category includes instrument tubing. One Instrument comprises the instrument itself, plus up to 2 valves, up to 4 flanges, 1 fitting and associated small bore piping / tubing [usually I" dia. or less]. Should the hydrocarbon leak occur anywhere between the fitting and the instrument itself, then it should be recorded as an instrument leak.

MUD/SHALEThis category is for the major equipment items associated with drilling activities; including mud pumps, mud tanks, and shale shakers.

PIG LAUNCHERSThis category comprises the PIG LAUNCHER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

PIG RECEIVERThis category comprises the PIG RECIEVER itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

PIPELINEA "Pipeline" is beyond the riser, on the sea bed and up to the 500 metres safety zone. It excludes SSIV component parts [valves, flanges, etc.] which are reported under the appropriate equipment category.

Please specify whether steel or Flexible, and add the pressure rating.

PIPING"Piping" includes all process pipes between the last valve on the wells and riser ESDVs, excluding all valves, flanges, and instrument fittings.

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PRESSURE VESSELThis category comprises the PRESSURE VESSEL itself, but excludes all valves, piping, flanges, instruments and fittings. However, blanked off flanges fitted directly to the pressure vessel should be part of the PRESSURE VESSEL category.

PUMPSThis category comprises the PUMP itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

RISERThe “Riser" is from the last point of isolation on the installation to the point where it touches the seabed. Thereafter it is the pipeline.

STORAGE TANKThis category comprises the STORAGE TANK itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

TURBINEThis category comprises the TURBINE itself, but excludes all valves, piping, flanges, instruments and fittings beyond the first flange and excluding the first flange itself.

VALVE MANUALThis category comprises the valve body, stem and packer, but excludes any flanges, controls, and instrumentation.

MANUAL Valve FUNCTIONS include block [includes isolation, shut-off, and kill], bleed, choke, and check. Please indicate whether it is a Bleed, Block, Choke or Check valve and its size.

Please also indicate further valve type [see below].

VALVE ACTUATEDThis category comprises the valve body, stem and packer, but excludes any flanges, controls, and instrumentation.

ACTUATED Valve FUNCTIONS include ESDV [Topsides and Pipeline to be separately identified], control [FCV or PCV], block, choke, blowdown, relief, and pipeline SSIV. Please indicate whether it is a, Block, Blowdown, Choke, Control, ESDV, PL/ESDV, PL/SSIV Assembly or a Relief valve. Please also indicate its size.

Please also indicate further valve type [see below].

WELLHEADJoint between xmas tree/BOP stack and the well itself. This category comprises the WELLHEAD itself.

WORKOVER EQUIPMENTThis category comprises the WORKOVER equipment itself [such as coiled tubing units, snubbing units or wireline units.

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XMAS TREEEntire unit including valves, flanges, rams, etc. down to the wellhead connection and up to the first flange, but excluding all piping, valves and fittings beyond the first flange [e.g. flow line or choke / killconnection] and excluding the flange itself.

Flange TypeNote that a flanged joint comprises two flanges and a gasket [where fitted]. Only the flange need be indicated since its type will indicate the type of joint employed.

Flange types include Ring type joint, compressed joint, Spiral wound, Clamp [Grayloc], Hammer union [chicksan].

Valve type It is essential that only one valve type is indicated on the form for any one hydrocarbon incident.

Please indicate whether the valve was a ball, globe, butterfly [for check valves], gate, plug, needle or pig valve.

Additional Notes to Location of Leak ChecklistFor valves, flanges, pumps, tubing, pipework, pipelines and other fittings, please specify their size in terms of nominal bore, inches [i.e. the nominal bore of the piping they connect to.

For PIG LAUNCHER/RECEIVERS and PRESSURE VESSELS give both the LENGTH and the DIAMETER in mm or inches, as available.

For BOP Stacks indicate the design pressure rating, e.g. 5,000 psi.

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Appendix 2 – Reporting Criteria for Hydrocarbon ReleasesThe 2 tables below summarises the criteria applicable to the “Unintended release of oil, gas or other hazardous substances, whether or not ignited”. For each table, one or more rows may be applicable, however for releases from Wells, Pipelines and releases of Petroleum Hydrocarbons, the outcome is the same if a release meets either or both RIDDOR and Implementing Regulation [EU] reportability criteria. For non-petroleum hydrocarbons, the four possibilities are explicitly listed.

Further guidance on RIDDOR Reportability Criteria is available in Oil & Gas UK Supplementary Guidance on the RIDDOR Reporting of Hydrocarbon Releases – Issue 2 [2014]

Reporting Requirements for Unignited Releases

Unignited release RIDDOR Reportability Criteria

Implementing Regulation [EU] No 1112/2014 Reportability Criteria

Reportable

Wells[RIDDOR DO 20 and/or IR [EU] Event A2 and B]

All releases All releases Yes

Petroleum Hydrocarbon Pipelines[RIDDOR DO 21 and/or IR [EU] Event A-2]

Is a dangerous occurrence and within 500m zone

Yes

>=1kg gas or >=60 kg liquid of petroleum hydrocarbon. Release must be within 500m zone

Yes

Non-Petroleum Hydrocarbon Pipelines[RIDDOR DO 21 and/or IR [EU] Event A-3]


Yes

>=1kg gas or >=60 kg liquid of petroleum hydrocarbon. Release must be within 500m zone

Yes

Petroleum hydrocarbons[RIDDOR DO 75 and/or IR [EU] Event A-2]

Is a dangerous occurrence

Yes

>=1kg gas or >=60 kg liquid of petroleum hydrocarbon

Yes

Non-petroleum hydrocarbons[RIDDOR DO 77 and/or IR [EU] Event A-3]


The unintentional release of … for which the major accident risk has been assessed in the report on major hazards

Yes


NOT an unintentional release of … for which the major accident risk has been assessed in the report on major hazards

Yes

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http://www.oilandgasuk.co.uk/publications/viewpub.cfm?frmPubID=792



Not a dangerous occurrence


Yes

Not a dangerous occurrence


No

Reporting Requirements for Ignited Releases

Ignited release RIDDOR Reportability Criteria

Implementing Regulation [EU] No 1112/2014

Reportable

Wells[RIDDOR DO 20 and/or IR [EU] Event A-1 & B]

All releases Any unintentional release of ignited gas or oil

Yes

Petroleum Pipelines[RIDDOR DO 21 and/or IR [EU] Event A-1]


Any unintentional release of ignited gas or oil

Yes

Non-Petroleum Pipelines[RIDDOR DO 21 and/or IR [EU] Event A-3]



Yes



Yes

Petroleum hydrocarbons[RIDDOR DO 75 and/or IR [EU] Event A-1]

All fires and explosions

Any unintentional release of ignited gas or oil

Yes

Non-petroleum hydrocarbons[RIDDOR DO 76 and/or IR [EU] Event A-3]



Yes



Yes

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Appendix 3 – References

1. International Regulators’ Forum [IRF] Performance Measurement Project.2. Oil & Gas UK Supplementary Guidance on the RIDDOR Reporting of Hydrocarbon Releases –

Issue 2 [2014] 3. http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/HS021.pdf 4. Directive on Safety of Offshore Oil and Gas Operations [Offshore Safety Directive] [better

hyperlink required when available]5. COMMISSION IMPLEMENTING REGULATION [EU] No 1112/2014 [better hyperlink required

when available]6. EU Guidance on Commission Implementing Regulation No 112/2014 [hyperlink required]7. Offshore hydrocarbon release – investigation policy [ SPC/Tech/OSD/48] 8. Investigating accidents and incidents - A workbook for employers, unions, safety

representatives and safety professionals [HSG245]9. The Public Enquiry into the Piper Alpha Disaster by the Hon Lord Cullen [Department of

Energy 1990].10. International Association of Oil & Gas Producers Safety Performance Indicators 2013 Data

Report No. 2013S, dated July 2014.

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http://www.ogp.org.uk/pubs/2013s.pdf

http://www.ogp.org.uk/pubs/2013s.pdf

http://www.hse.gov.uk/pubns/priced/hsg245.pdf

http://www.hse.gov.uk/pubns/priced/hsg245.pdf

http://www.hse.gov.uk/foi/internalops/hid_circs/technical_osd/spc_tech_osd_48/index.htm

http://faolex.fao.org/docs/pdf/eur139363.pdf

http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32013L0030

http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/HS021.pdf



http://www.irfoffshoresafety.com/country/performance/scope.aspx

Documents

Health and Safety Executive - June 2015 · Web viewFor NON-PROCESS releases, e.g. Methanol, Glycol, Diesel, Lube oil, Seal oil, Bottle gas, Hydraulic oil, Fuel oil, Heat transfer