The purpose of this document is to describe the design philosophy for the flare, vent, relief, and blowdown systems. This philosophy helps to establish the design basis for each of these systems.

1. Overall Design Philosophy

The processing facilities should be designed to normally operate without the need to flare hydrocarbons. The facilities should be designed such that there should be no production flaring for operational purposes. The flare and vent systems should be designed to safely dispose of relieving hydrocarbon fluids as may be required during start-up, operational upsets, emergency shutdown, and maintenance activities. The flare and vent systems should be designed in accordance with API RP 520 and API RP 521, latest revisions. The facilities process design should also be in accordance with API RP 2G and API RP 14C.

Compression outages that result in flaring should be minimized by design, to aid flow assurance by avoiding shutting in subsea wells. The Local Governing Authority (LGA) may place even more stringent flaring limitations. Once the allowable period is over, oil production should be curtailed to match available compression capacity. A Reliability, Availability and Maintainability (RAM) study should be conducted to ensure spares for equipment and controls are adequate towards satisfying these flare limitations while maintaining the Client’s target reliability / availability for the delivery of oil. In any event, the flare system should be designed for emergency flaring due to compression unavailability.

Measures should also be put in place to minimize the emissions of volatile organic components. Philosophies specific to crude oil and other cargo tanks are described elsewhere.

2. Overpressure Protection / Relief Philosophy

Two levels of overpressure protection should be provided for pressurized equipment items. These levels generally include protection by high pressure or high level switches that shutoff inflow or stop rotating equipment, with secondary (ultimate) protection afforded by self-acting mechanical relief devices such as pressure safety valves (PSV).

Primary protection should comply with the requirements of API RP 14C.

Secondary protection should comply with the requirements of API RP 14C, and in the case where a PSV is required, with API RP 520 and API RP 521.

Special circumstances may dictate HIPPS (type) systems (in lieu of PSV) to prevent over-pressurization of downstream equipment and/or to minimize impacts to the flare systems.

3. Flare System Design Philosophy

Two flare systems should be provided on the Offshore Facilities as follows:

  • HP Flare System – for relieving / de-pressuring pressure sources equivalent to or greater than the design pressure of the IP (or second stage) Separator
  • LP Flare System – for relieving / de-pressuring pressure sources greater than the design pressure of the IP (or second stage) Separator

The progression of natural engineer design may flush out issues with the above general rules; therefore, exceptions may need to be accommodated.

Once the flare relief network has been modeled, back-pressure calculations should be performed to validate the destination of each source. The LP flare system should also collect releases for final manual depressurization (from residual pressure) of equipment prior to maintenance. The requirement for final manual depressurization should apply only to items or trains of equipment that can be taken out of service during continued production operations (i.e. where there is risk of coincident release into the HP flare system).

Discharges from the HP and LP flare headers are routed to their respective HP/LP flare scrubber, where any liquids are separated. The gas is routed via the flare stack to the HP and LP flare tips.

Since the simultaneous occurrence of two or more unrelated contingencies is unlikely, unrelated contingencies should not be used as a basis for determining the maximum system load. Therefore, while lines from individual relief valves should be sized for the maximum calculated design flow, sections of a main header or sub-header should be sized for a specific maximum contingency. Care should be taken to ensure that one contingency could not remain undetected for a long period of time; otherwise, a coincidental second contingency should then be considered.

The sections below include design criteria and philosophy for performing the necessary sizing and calculation routines to design flare/relief system.

3.1 Relief Valves

The pressure relief requirements, relief valves sizing, and selection should follow the recommendations of API 520, API 521 and API 526 in general. However, the following lists the major basis and assumptions used for relief valve sizing:

  • The gas blow-by / control valve failure case of relief valve sizing should consider the upstream pressure for the control valve at PAHH setting of the upstream system and the downstream pressure as the relieving pressure of the relief valve.
  • For the wetted fire case sizing, the latent heat of vaporization should be calculated for the liquid. In case of three phase separators, the hydrocarbon liquid should be considered. The latent heat for multi-component liquid systems should correspond to the heat required (at the relieving pressure) to vaporize the first 5% by mass of the liquid from the bubble point of the liquid. The relieving temperature and properties for the vapor stream should consider the conditions (either the bubble point or the 5% vaporization point) where the density of the vapor stream is lower.
  • For liquid filled vessels exposed to fire, the fire should be assumed to progress up to point of vessel failure (coincident failure temperature at relieving pressure). That is, initial relief should be by thermal expansion by heat input while ultimate relief should consider vaporization of the liquid per above bullet point, assuming vaporization temperature occurs before vessel failure temperature.
  • For liquid filled exchangers with heat input from hot side of the exchanger, a thermal expansion / vaporization should be considered similar to above. However, the maximum temperature that should be considered for blocked-in, heat input scenario is the inlet temperature from the hot side of the exchanger.
  • For cases where liquid is not present at relieving conditions per the process simulation, an unwetted fire case should be considered for sizing the PSV.
  • The relief valve sizing calculation should also consider the wetted / unwetted surface area for the equipment’s associated piping.
  • The wetted area should be determined at relieving conditions.
  • If the wetted area represents a small fraction of the available surface area, relief valve sizing should be determined by the unwetted fire equations, but only if the resulting relief load is determined to be more conservative than that determined with the wetted equations.
  • Multi-phase relief valves should be sized using either the Omega Method (per API 520 Appendix D) or the HEM Method (DIERS Sizing).
  • In the evaluation of applicable relief scenarios, credit may be taken for the lacking of valves, provided 1) a register of valve tags with locking devices is maintained, and 2) there is a lockout and tag out philosophy / procedure en force for a particular project and it is strictly followed.

The selection / sparing philosophy for PSVs should be:

  • The use of conventional relief devices is preferred as the pressure relief device, especially if the oil to be relieved contains sand or wax.
  • Conventional relief valves should be specified only if the built up back pressure does not exceed 10% (21% for fire release cases and ASME VIII design code) of the set pressure (gauge) of the item protected.
  • Balanced relief valves should only be used if conventional relief valves are unsuitable. The use of balanced relief valves should be restricted to a built up back pressure of 50% of the set pressure (gauge).
  • For built up back pressures greater than 50% of the set pressure (gauge), the manufacturers should be consulted for advice. Ideally this should be designed out.
  • Pilot relief valves may be considered in clean services (e.g. fuel gas and compressed gas).
  • Pilot relief valves should be selected in clean services where a standard 10% margin has been provided between the nominal operating pressure and the design pressure AND the operating pressure is at the mercy of a compressor or pump curve which reduces the allotted 10% margin (e.g. for blocked outlet of a compressor and for blocked outlet of a seawater injection pump).
  • All dirty services (e.g. well fluid, crude oil/condensate, and produced water) may be provided with balanced bellows type PSV’s.
  • PSVs provided on heat exchangers (designed strictly for thermal relief) need not be spared and may be conventional type subject to back pressure limitations being met.
  • PSVs identified in critical services would normally be installed with a spare to allow valve maintenance while on live systems with the appropriate isolation.
  • Critical service can be taken as those "non-parallel" items of equipment critical to production availability, e.g. 1 x 100% separators, glycol contactor, manifold, etc. Generally, it would not be acceptable to cut back production (and so impact availability/ops efficiency) to maintain PSV’s where no spare has been installed.
  • Non-spared PSV’s are acceptable where an equipment item is installed in parallel. If the parallel item is not a spare, production should be reduced during PSV maintenance (offline) but the system does not shutdown.
  • Exceptions to the above sparing philosophy may be able to be justified so long as it can be proven that the reliability requirements for a project can be met. Where a spare PSV can be eliminated from a RAM analysis, bullhorn connections should be considered for the future installation of a PSV if and when required.

Relief valve installation should permit testing to the requirements of the Local Governing Authority. (Installed spares should also be dictated by LGA)

3.2 Blowdown

An emergency shutdown and blowdown system should be provided for the offshore processing facilities to prevent the escalation of abnormal situations into major hazardous events. Blowdown should be initiated automatically (with manual intervention and/or with blowdown hold) on confirmed fire or gas detection. Upon initiation of an automatic blowdown, all blowdown valves (BDVs) should open and cause the blowdown of all offshore facilities. It is not intended that a facility-wide blowdown scenario should govern the required flare stack height. Measures should be taken such that the opening of the blowdown valves should not exceed the emergency relief design capacity of the flare, which can be accomplished by sequenced or staged blowdown if necessary.

The blowdown process should be divided into sections by shutdown valves (SDVs) that result in the safe isolation of the facility in a logical manner.

The design should comply with the requirements of applicable Country regulations if more stringent blowdown requirements are dictated.

The standard installation for a BDV associated with offshore processing facilities should include the installation of a restriction orifice downstream of the BDV. A locked open full bore manual isolation valve should be installed downstream of the restriction orifice to allow isolation from the flare system.

An important aspect of performing blowdown calculations is to arrive at the blowdown load for the flare system design and the system minimum design temperatures, both upstream and downstream of the restriction orifice in order to determine the material selection.

Each of the production flowlines and associated gas lift flowlines’ gas export risers should also have blowdown capability. The blowdown system should be designed such that low temperatures can be accommodated. Blowdown of the flowlines should be manually activated and depressurized independent of the facilities-wide emergency blowdown associated with a confirmed fire or gas detection. Riser ESD valves should be provided at the top of each riser. Integrated gas lift lines should also be provided with ESD valves and manual blowdown valves.

The following two cases should be compared:

  • Hot Blowdown (Fire Case): Emergency blowdown from normal operating temperature. The initial liquid level should be based on either LAHH or NLL, whichever gives the maximum blowdown load.
  • Cold Blowdown (Adiabatic Case): Blowdown from the minimum ambient temperature (17°C) only if the gas inventory may be contained for extended durations, blowdown from minimum operating temperature if lower than minimum ambient, or blowdown from settle out conditions in the case of compression trains. The calculations should be done assuming initial liquid level as LAHH or NLL (whichever gives the lowest temperature).

The hot blowdown calculation should be first performed for each system starting from 100% MAWP individually in order to size the BDV / restriction orifice. For simultaneous depressurization calculations (after the BDV /restriction orifice has been sized for fire), a set of equipment items with a common fire circle should be assumed to be at 100% MAWP while the remaining equipment items to be depressurized should be assumed to be at their normal operating pressure.

The hot blowdown calculation should be using a target of 15 minutes to final pressure at 50% MAWP for selected carbon steel systems with wall thickness greater than 25 mm and 15 minutes to final pressure of 6.9 barg for all other carbon steel systems.

The cold blowdown calculation to obtain the minimum operating temperature should be performed using the selected orifice size based on the hot blowdown (fire) case and should not be stopped at the final pressure per the criteria, but should be allowed to continue to near atmospheric pressure (minimum flare back pressure) to be sure that the lowest temperature is obtained. This calculation should be performed assuming initial liquid level as LAHH or NLL, whichever gives the minimum temperature during blowdown.

The minimum design temperature should be calculated based on an 11.1°C margin on the minimum operating temperature obtained from the above calculations. An alternative minimum design temperature may be justified if demonstrated by standard engineering (heat transfer) calculations and applying a conservative set of assumptions. For example, a flare scrubber and stack may not necessarily have the same minimum design metal temperature as the piping immediately downstream of the blowdown valve.

Vessels should consider blowdown events in determining appropriate minimum design metal temperatures. Consideration of blowdown does not necessarily mean that the metal temperature should be the same as the fluid temperature predicted by thermodynamic blowdown calculations. When very cold fluid temperatures are predicted, it is generally a result of assuming no heat transfer to the metal.

Design of the blowdown system should accommodate any specific requirements of the gas compression packages, such as for startup, design considerations, motor starts, explosive decompression, etc.

In addition, the back pressure at equipment required to be depressurized via a BDV is limited to 50% of the design pressure of the equipment. The 50% limit ensures critical flow across the BDV at initial conditions such that the back pressure should not reduce the expected depressuring capacity.

The depressurization rate should not exceed 50 bar / min in order to avoid explosive decompression issues with casing seals associated with certain compressors and/or valve trim.

The following equipment items do not have to be capable of being automatically blown down for fire considerations:

  • Liquid filled pressure vessels
  • Equipment items with an operating pressure already below the final blowdown pressure at the end of 15 minutes

Blowdown of the production flowlines, gas lift riser, injection, or export gas pipeline should not be considered as part of the offshore emergency shutdown and blowdown system. These should be independently activated and manually initiated. The blowdown lines should be designed such that depressurization of these items should not govern the sizing of the flare system. Appropriate materials should be selected for the blowdown lines and headers for the low temperatures that are anticipated.

3.3 Relief Device Inlet Piping

The inlet piping of the relief valves should be sized to limit the pressure drop to 3% of the set pressure. Inlet pressure drop should be based on the non-recoverable losses (friction) only; however, the inlet line size should be at least equal to the PSV inlet size. Where applicable, the PSV set pressure should be adjusted to account for the static head difference between the PSV and the protected equipment.

The inlet piping of restriction orifice (for blowdown valve) should be sized to limit the Mach number to 0.3. The minimum line size should be 2 inches. The pressure drop should be limited to allow the critical flow to occur across the orifice and not the inlet line.

3.4 Relief Device Outlet Piping / Flare Sub-Headers / Headers

In accordance with API RP 521, the rated capacity of the PSV is used for sizing individual discharge lines. The flare headers are sized using the maximum combined relieving rates of all devices that may reasonably be expected to discharge simultaneously in a single overpressure event.

When calculating the relief load from multiple relieving devices, it should be assumed that all PSVs within a “fire circle” can relieve simultaneously. Only the fire load should be considered for each PSV. For an offshore facility, one entire module should be considered as the fire circle.

For simultaneous depressurization calculations (after the BDV / restriction orifice has been sized for fire), a set of equipment items with a common fire circle should be assumed to be at 100% MAWP while the remaining equipment items to be depressurized should be assumed to be at their normal operating pressure.

The outlet piping of the relief valves should be sized to limit the total built-up back pressure at the relief valves to 10% of the set pressure (in case of conventional valves) and 50% of the set pressure (in case of balanced bellows valves). In case of a pilot operated relief valve, the back pressure should be limited to 75% of the set pressure. In all cases, the back pressure should not exceed the outlet pressure limits as defined in API 526.

In addition, the back pressure at equipment required to be depressurized via a blowdown valve is limited to 50% of the design pressure of the equipment. The 50% limit ensures critical flow across the blowdown valve at initial conditions such that the back pressure should not reduce the expected depressuring capacity.

For emergency vapor relief, the Mach number in the relief device outlet piping / flare subheader / flare header should not exceed 0.5 Mach.

For continuous vapor relief, the Mach number in the relief device outlet piping / flare subheader / flare header should not exceed 0.2 Mach.

For emergency case multi-phase relief, the rho v2 (Mixed Density * velocity2) should not exceed 62,500 lb/ft/s2. This is based on an erosional velocity C-factor of 250 per API 14E.

The flare system should be sloped approximately 1 degree to cater for the maximum stern trim to prevent liquid hold up. Routing of flare and vent lines should take account of vessel static trim and heel as well as wave induced vessel motions.

All lines should be sloped from the source of discharge into their respective flare KO drums to allow for free drainage. If low points cannot be avoided, drains should be installed to keep pockets free of liquids.

The flare headers should be continuously purged with fuel gas. The purge rate should be at least the minimum required to guarantee that air ingress into the tip is prevented. Purge flow rates should be measured at each purge point by a flowmeter. A “no flow” alarm should be provided on each flowmeter. Nitrogen back up should be provided for purging.

Special care should be taken with respect to the occurrence of slug flow during a two phase flow discharge. The possible flow effects of all streams that can enter the flare system should be considered to identify the maximum forces on the supports. For this, a total inventory of all relief streams (e.g. operational, emergency) should be made and the simultaneous occurrence of liquid and gas releases should be evaluated. In this connection, it should be noted that liquid would stay in the relief header for a certain time period due to the limited slope of the relief header. A vapor relief occurring shortly after a liquid relief should pick up this liquid and a slug should possibly be formed, generating high excitation forces. These situations should be designed out by proper instrumentation or the installation of drainpots or knockout drums or separate gas and liquid relief headers.

The hydraulics of the flare piping systems should be analyzed based on estimated line routings or piping isometrics. The hydraulics should ensure that the built-up back pressures have been appropriately considered in the derating of the relief valves, as appropriate. Low temperatures can occur as a result of the expansion of gas during depressurization. The minimum temperature that can occur during relief or blowdown should be determined by considering fluids at design or PSHH set pressure and normal operating temperature upstream of the relieving device.

The flare system pipework should be designed and / or fabricated from materials suitable for the minimum temperature that can be achieved.

3.5 Flare Scrubbers

It is desired that flare scrubbers be able to separate all liquid droplets in excess of 450 micrometers (ABS Guideline, 300-600 micrometers API Guideline) and provide a liquid retention time between LAH and LAHH1 that should allow reasonable Operator response time to take corrective action. The closure time on any SDV that may be relied upon to mitigate the relieving situation should be included between LAHH1 and LAHH2. The 450 micrometer design criteria should be met in the vapor space above LAHH2.

A provision should be made to allow for a heating medium coil built into the flare scrubbers to prevent congealing of oil.

The scrubbers should not have any continuous source of liquids discharging into it.

A shutdown valve should not be provided on the liquid outlet line of flare scrubbers fitted with liquid level control valves in lieu of flare pumps.

3.6 Flare Pumps

No credit should be taken in the flare scrubbers sizing for the pump-out of the collected liquids.

Where installed, the pump operation philosophy is that the first pump should start on LAH1 and the second (stand-by) pump should start on LAH2. Both pumps should stop on LAL. Also, for pump protection, LALL (through PSD function) is also provided on the flare scrubbers.

The HP and LP flare pumps should be connected to the emergency power supply. The liquids leaving each flare scrubber should be directed to closed drain. If either flare scrubber can be arranged in relative elevation to closed drain such that the liquids may exit on gravity flow, then no pumps should be required for the service.

The high liquid level LAHH1 on the flare scrubbers, voting 2 out of 3, actuates a complete process shutdown across the topsides.

3.7 Flare Stack

The flare design should take account of helicopter approach, cargo and supply vessel approach, as well as the potential for smoke, noise, and heat impacting the offshore facilities.

Radiation Levels

The flare stack height and diameter are designed to minimize the maximum radiation level during maximum flaring to within acceptable levels during normal operation.

The permissible design levels for flame radiation per API 521 are given in the Table below:

Flame Radiation Levels.jpg

Table: Permitted Flame Radiation Levels

For continuous flaring and emergency flaring, the maximum allowable radiation level at various points should be 1.58 kW/m2 (500 Btu/h/ft2) and 4.73 kW/m2 (1500 Btu/h/ft2) respectively. The above radiation limits include solar radiation.

Dispersion Levels

The H2S content in the gas phase should not result in local H2S or SO2 ground level concentrations that should be a threat to personnel.

For continuous and emergency flaring, the flammable gas concentration should be below 20% LEL at the various points, assuming the most conservative wind speed (of all the locales).

The basis associated with conducting a dispersion analysis for the offshore facilities is to quantify the risks related to various gas emissions that have some possibility of occurrence during the life of the facility. Some release scenarios are expected and controlled such as venting scenarios off of equipment, and other releases are as a result of an incident requiring safe actions.

The purpose of conducting the analysis is to evaluate the extent of a combustible vapor cloud resulting from a particular release at predefined environmental conditions, i.e. wind speeds. The resulting gas dispersion concentrations should be overlaid on any adjacent equipment to determine their impact on operations.

The analysis should be conducted using an industry accepted software package such as PHAST. Within the program, studies are conducted illustrating the extent of the cloud within the UFL and the LEL as dictated by each project requirements.

The results should indicate the concentration levels that could reach process areas, accommodations, and other areas of concern, and recommend courses of action to mitigate any hazardous emission levels in these areas.

HP / LP Flare Tip

The flare tip should be designed such that in the high velocity range, liquid droplets carried through from the HP flare scrubber are broken down and atomized to avoid burnout of the tip. The flare system should be designed such that the flare is smokeless, as defined by Level 1 of the Ringlemann Scale, for continuous flaring of design throughput capacities. The maximum liquid droplet diameter that can be tolerated with efficient burning is subject to confirmation by the tip Supplier. The design should comply with the requirements of the Local Governing Authority, if determined to be more stringent.

The design of the flare tip should be such that thermally induced stresses are avoided by preventing flame impingement.

Procedures and capability should be provided for flare tip replacement.

For flare gas metering, a non-intrusive type flow meter should be used. Typically, an externally mounted ultrasonic meter covering a significant range of flow rates should be employed. Depending on accuracy requirements dictated by the Local Governing Authority, more than one meter may be required for the large turndown ratio dictated by this service.

Ignition Panel and Pilot Burners

Pilot burners should be provided at the flare tip, capable of igniting the flare gas and sustaining stable combustion under all flaring conditions. Blowout-proof pilots should be provided. A flame detector (Thermocouple type) should be provided common for all pilots with a quick response time to monitor the flame presence.

The ignition system should be an electronic ignition (spark) type, capable of igniting the pilot burners for local wind conditions. Separate ignition lines should be provided for each pilot, each being sloped with a low point drain.

4. Vent Design Philosophy

Atmospheric venting to a safe location is permissible from equipment items operating at or below 1 barg.

An annulus vent tank of 5 barrels should be provided to allow for venting of the wellhead annuli through the umbilical tubing to the topsides.