The Design and Operation of Offshore Relief - Venting Systems

I. CHEM. E. SYMPOSIUM SERIES NO. 85

THE DESIGN AND OPERATION OF OFFSHORE RELIEF SYSTEMS

F.K. Crawley* and D.S. Scott*

The design of pressure relief systems for offshore operation provides a demanding challenge to the process designer, which if poorly handled will cause numerous operating difficulties.

This paper therefore consists of two parts. The first, which deals with the design of relief systems, will discuss the sizing and routing of relief piping and includes two phase flow, estimation of relief rates and alternatives to venting. Items of particular importance to the offshore industry (such as total system weight and flare location) will be examined briefly and contrasted with onshore practice. The second part of the paper will examine problems encountered in the operation of relief systems and includes flare radiation levels, segregation of flare systems and, of particular importance, drainage and cross communication in vent systems. The paper aims to provide a practical basis for the design of relief systems (equally valid for offshore, and onshore equipment) and suggests a number of improvements to existing design practice.

INTRODUCTION Pressure relief systems are one of the most important and difficult to design piping systems on any process plant - onshore or offshore. The design of relief and blowdown facilities usually takes place toward the end of the process design phase when any flexibility within the design has been limited. This is unfortunate, but probably inevitable, as process flow sheets, control valve sizes, vessel dimensions and many other factors must be agreed before detailed design of the vent system can proceed. Few other systems require the same detailed attention and whenever possible the routing of the vent pipework should be considered at an early stage, even if pipe sizes are unknown. This can ease, or possibly prevent, layout problems at a later stage. By considering a number of points as early in the design process as possible, later problems can be minimised. The most important points are: - The relief rates from each source. Composition, temperature and pressure of the relieved material. Routing of the relieved material to flare (or other means of

disposal). Radiation levels from the flare. These factors, and others, will be examined later, first however, it is worth comparing some aspects of onshore process plant with offshore practice. * Britoil plc, 150 St. Vincent St., Glasgow. G2 5LJ

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COMPARISON OF ONSHORE AND OFFSHORE PRACTICE At the present time the only process commonly found offshore is oil and gas production from fixed, as opposed to floating, installations. A typical flowsheet for oil production is found in figure 1. Oil production from floating facilities and chemical production from barge mounted plant are being considered, but are not yet widespread. In addition to the challenges inherent in the design of any major industrial plant a number of particular problems exist offshore and are highlighted in table 1. DESIGN OF RELIEF SYSTEMS

Estimation of Relief Rates There are a relatively small number of overpressure causes present in offshore facilities: these are generally covered, sometimes in a superficial manner, in API-521 (1) which is usually taken as the standard reference for pressure relief systems, even outside the oil and petrochemical industry. The major areas of concern are:-

'Blowby' or 'Blowthrough' Fire Thermal expansion Heat exchanger tube failure Pump or compressor deadhead Mal-operation These are examined below. It should be noted that runaway chemical reaction, which is a difficult relief case to analyse in chemical plant, does not occur offshore. Additional relief cases may be identified during hazard and operability studies, safety reviews or other procedures. A typical example would be failure of control valves on service systems. For example failure in the open position of a heating medium control valve may allow a high flow of hot fluid into heat exchanger causing thermal expansion or boiling of the process fluid.

'Blowby' or 'Blowthrough' As all but the last separator in a production train operate at elevated pressure, loss of the liquid level will allow gas at high pressure to enter downstream vessels which are designed to operate at low pressure. This is termed 'blowby' or 'blowthrough'. Low level trips in each vessel should operate to stop production and close emergency isolation valves, if the trip system fails relief valves will provide the last line of defence. The relief rate required can be calculated from the control valve size and the pressures upstream and downstream of the relief valve. The downstream pressure will be either atmospheric, if the downstream equipment vents directly to atmosphere, or the set pressure of the relief device in question.

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Wellhead fluid is usually at high pressure and is letdown, or choked, to a relatively low pressure before processing. Elaborate instrument systems are generally used to close off the wellheads upstream of the choke valves in the event of a serious process upset. It is not normal practice to design the flare system to cope with a simultaneous failure of a number of choke valves which, due to the use of high integrity protective systems, is a very remote possibility. A more credible event is the failure of a level control valve in a gas/water/oil separator. There is an initial temptation to take the relief valve set pressure,

plus accumulation of the separator relief valves as the upstream pressure. However, this may result in extremely large relief valves and header sizes. As separators usually have a high pressure alarm and trip plus one and usually two high level trips, it is unlikely that level will be lost at the same time as the pressure trips do not operate. Therefore it is usually permissible to use the pressure trip setting for the upstream pressure in the calculation. If necessary, a fault tree can be constructed and quantified to justify the choice of upstream pressure.

Fire One of three distinct situations will exist when fire impinges on a vessel heating the contents and causing an increase in internal pressure. Each situation described below requires a different approach to relief valve sizing.

. Gas filled Vessels There are a number of vessels on any platform where a liquid phase is unlikely to be present, for example instrument air receivers and fuel gas heaters. In a fire, overpressure will be caused entirely by thermal expansion of gas. A relief valve for this duty can be sized from (2):

= 3 31

F' AA 1.824 10

P...(1) A = effective discharge

area of the relief valve (M2)

F = factor related to gas temperature (which can be determined from fig. 2).

A3 = exposed surface area (M2).

P1 = upstream relieving pressure in Bar(a), (e.g. atmospheric pressure plus relief valve set pressure, plus overpressure).

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The use of this equation ignores the fact that as the metal wall of the vessel heats up the yield stress of the wall reduces ultimately reaching a point where the wall will rupture below the relief valve set pressure (2,3). It is therefore unwise to rely on relief valves as a protection against fire in a gas filled system, depressuring the vessel via a control valve is generally preferable and is discussed further below. Vessels containing liquid with a vapour space Calculation of relief rate in this situation is straight forward using the method outlined in API-520 and API-2000. In general there is little difference between the methods which relate heat input to wetted surface area, however API-2000 is more conservative for lower wetted surface areas. A comparison of the two is shown in figure 3. There is growing evidence to suggest that heat input rates in large fires may be more than 100% in excess of the figures given by either API 520 and API 2000 (4,5).

It should be noted that crude oil is not a single component substance and the vessel contents will fractionate during a fire, resulting in a variable boil off rate. The highest boil-off rate usually occurs at low temperatures when low molecular weight materials are present, however it is prudent to calculate boil off rates at higher temperatures particularly near the critical point where the enthalpy of liquid and vapour phases may be similar. Again the dangers of overheating the metal walls of pressure vessels should be examined and the alternative of depressuring considered.

Liquid filled vessels Behaviour of the contents of a liquid filled vessel under fire conditions is difficult to predict and the commonly applied (6) method of sizing the relief valve to pass a volume of liquid equivalent to the vapour generated is probably conservative.

A more realistic approach where relief valves are installed on the top of vessels is to consider three distinct stages:-

1. thermal expansion of the fluid up to the boiling point or bubble point.

2. boil-off of vapour with entrained liquid until a vapour cap is formed, which allows liquid droplet disengagement.

3. continuous vapour relief.

The required relief rate for stage 1 can be calculated from the thermal expansion of the liquid and vapour relief rates for stages 2 and 3 can be calculated in the same manner as above. The major problem is the estimation of the liquid entrainment in stage 2, in trial calculations this has been assumed to be the same as the vapour flowrate in mass terms. The relief valve is then sized on the largest of the three orifice areas calculated. Usually the only liquid filled vessel on the platform is the crude pig launcher which is isolated and depressured when not in use.

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Estimation of orifice areas for relief valves on two phase flow duties presents difficulties. Most relief valve manufacturers suggest that separate calculations be done for the vapour and liquid components of the flow and the separate orifice areas added together.

This is commonly felt to under-estimate the required orifice area as it does not allow for flashing through the valve or differences in sonic velocity between a vapour and a two-phase mixture (7,8).

Thermal Expansion Protection of liquid filled vessels and piping against thermal expansion of the contents from high ambient temperature or heat tracing is often necessary. Frequently small thermal relief valves which do not comply with API-526 (9) are installed without estimates

of the required capacity being made. This is unfortunate as relief valve capacity is easily calculated from (10):

Where V = flow rate at the flowing temperature M3/S.

B = cubic expansion coefficient for the liquid at the temperature under consideration.

H = total heat transfer rate (kw).

G = specific gravity related to water at 15C.

C = specific heat of the trapped fluid in (KJ/kgK).

A particularly severe problem may occur in heat exchangers if the cold fluid is isolated, with the hot fluid flowing. Temperature rise may be very rapid and if the bubble point of the cold fluid is exceeded boiling will occur. Theoretical calculations can be performed to estimate the relief rate, which will occur in a similar fashion to fire relief of liquid full vessels, but usually at a much higher rate; in some cases, particularly with plate type exchangers, the pressure drop imposed by the exchanger may cause unstable operation of the relief valve. In this situation rigorously enforced operating procedures and valve interlocks are a better form of protection than relief valves.

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Burst Tubes Although plate heat exchangers are preferred offshore for reasons of space and weight savings, shell and tube type exchangers are still required for high pressure duties on gas compression and fuel gas systems. Almost invariably gas flow is on the tube side with cooling on the shell side.

In common with accepted practice (11) relief protection against a burst tube is only fitted if the hydrostatic test pressure of the lower pressure side of the exchanger can be exceeded. Unfortunately this logic only applies to the first stage or first two stages of a compression train and overpressure protection is required for the high pressure stages. Here bursting discs rather than relief valves are used due to the high venting rate required. Reverse buckling discs are favoured for this duty as they are thicker and hence less likely to pinhole or rupture spuriously than conventional or composite slotted discs. Bursting disc sizing methods are less standardised than relief valves and disc manufacturers should be approached for advice. Note that obstructions in the pipework such as knife blades or catcher bars will be present and the line size may have to be increased to ensure that sufficient flow area is available (12). If thermal expansion of the cooling medium occurs it may be relieved by a partial buckling of the bursting disc, which will either cause spurious rupture or, more probably, an increase in the pressure which may be attained before the disc ruptures. For this reason a separate thermal relief valve should be installed on the shell side with a set pressure plus overpressure below the lower burst tolerance of the disc. Note that the pressure rating of the bursting disc must allow for back pressure on the downstream side of the disc.

Pump and Compressor Deadhead Mal-operation may result in isolation valves on pump and compressor discharge lines being inadvertantly closed, allowing equipment to 'run-up' its curve. Downstream piping or equipment with a design pressure below the deadhead pressure must therefore be protected. The relief rate can be estimated, as shown in figure 3, by finding the pump capacity at the relief valve set pressure. It should be noted that relief valves on liquid duties may have to be set below the vessel (or piping) design pressure if the valve overpressure exceeds 10% of relief valve set pressure. When estimating relief rates for compressors it should be noted that variations in molecular weight of the compressed gas will affect the discharge pressure.

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Mai-operation Operator error may cause any of the situations discussed above, with the possible exception of fire. Probably the most common examples of operator error are the unauthorised opening and closing of isolation valves or incorrect adjustment of control valve set points. For this reason essential valves are often locked or interlocked and their operation governed by a permit to work system (12). Where valves are accidently opened or closed problems may result from the overpressure of a lower pressure vessel from higher pressure source. The relief rate required is estimated by locating the flow limiting component of the piping system (usually a globe valve, control valve or an orifice plate) and then calculating the flow coincident with the highest postulated upstream pressure and lowest downstream pressure. ALTERNATIVES TO PRESSURE RELIEF VALVES In some situations, both onshore and offshore, the installation of relief valves and their associated pipework may prove unrealistic either for economic reasons or due to the difficulty of disposing of large quantities of relieved material. Here alternative solutions must be found with a reliability equal to, or greater than, a relief valve.

Instrumented Trip Systems Trip systems to close emergency isolation valves or to shut down pressure producing equipment are commonly found on any offshore facility as part of the Emergency Shutdown System (ESD). Instrumented systems of this type require careful design, components liable to failure have to be duplicated or perhaps triplicated; voting systems may be necessary to prevent frequent spurious operation of the trip (13). Proof test procedures and test intervals must also be defined at the design stage, and the proof test must cover as much of the trip system as possible. Frequently, great attention is paid to testing and self checking of the trip controller and comparatively little to the less reliable sensor element and actuator mechanism. Another popular misconception is that reliability of a trip can be increased to any desirable level by increasing the frequency of testing. As the frequency of testing increases the proportion of time the trip is unavailable increases and hence, during this period, a demand on the trip will not initiate the remedial action required (14, 15).

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Depressuring Systems The advantages of depressuring systems for the protection of vessels exposed to fire have been discussed above; similar systems are frequently installed on the platform compression train and equipment is depressurised as a precautionary measure under certain upset conditions. Operating pressures in the compression train will normally range from atmospheric up to perhaps 150 bar g and frequently several vessels with different design pressures will discharge to the same header. It is therefore essential to size the depressuring valves to prevent excessive flow and hence excessive backpressure in the header. High uncontrolled

flows can cause a number of problems (16, 17):- Excessive cooling, causing materials of construction and pipe

stressing problems. Large flaring rates with attendant thermal radiation problems. Noise caused by sonic velocity through the depressuring valve. Reverse flow from high pressure sources into low pressure vessels.

Design of depressuring facilities is a complex task, based on an initial specification to reduce pressure to a given level within a set time. The criteria proposed by API (18, 19) may be inadequate for large hydrocarbon fires where metal in contact with the vapour space may yield after 5 - 1 0 minutes exposure (4).

PIPING DESIGN On oil platforms all vented material, except that from low pressure small volume vents, is fed to a flare system. On gas platforms, gas is not released during normal process operations and flammable material is 'cold' vented rather than flared during process upsets. The discussion of flare systems below therefore relates to oil production platforms. Most platforms have separate high and low pressure headers to prevent vessels with a low design pressure being subject to excessive backpressure. As most present generation platforms use low emissivity type flares, which require significant pressure at the flare tip, it is essential to ensure that vessels are connected to the correct header. Another important segregation, in high pressure headers, is between (water) wet and cold streams. Wet streams usually originate in the gas/oil separators or the cooling medium side of gas compression coolers. Pressure control valves in the separation train will also contaminate the flare header with wet gas in normal operation. Due to the thermodynamic properties of hydrocarbon gases, very low temperatures may result when they are relieved or blow down from high pressures. The mixing of cold and wet streams in pipework may therefore cause problems of blockage by ice or hydrate formation. Ideally, segregation should occur with cold and wet streams being run in separate headers.

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Sizing of Relief Headers The correct sizing of relief piping particularly downstream of the relief valve or other relief device requires more care than almost any other section of piping on an offshore facility. A number of apparently conflicting requirements have to be reconciled until an acceptable compromise is reached. This process is best achieved by following a rigorous stepwise procedure as show below. Step 1 Decide which combinations of relief valves will operate simultaneously; realistic estimates, not worst assumptions are required. For example, it is reasonable to expect all the fire relief valves from one module to operate together, it is not reasonable to expect every fire relief valve on the platform to operate at once.

Step 2 Make an approximate estimate of the relief line sizes. Step 3 Calculate the back pressure that will exist at the discharge of

each relief valve for the combination in question. Step 4 Check that the backpressure imposed on the relief valves does

not exceed 10% of relief valve set pressure (RVSP) for conventional valves or 50% RVSP for balanced bellows valves (20). (Note that some relief valve vendors are unhappy with back pressures as high as 50% RVSP on balance bellows relief valves and may recommend lower figures). It is generally advisable to specify a maximum velocity of approximately Mach 0.3 to limit noise.

Step 5 Repeat steps 2 to 4 until all line sizes are satisfactory. Calculation of back pressure in relief valves is most conveniently performed by flashing all the relief streams involved to a known downstream pressure at the discharge of the header. This will be atmospheric pressure in the case of a 'cold' vent or the pressure required for efficient operation of the flare tip. Where low emissivity flare tips are installed the pressure is a function of relief rate. At this downstream pressure physical properties can be estimated and used to calculate the pressure drop and hence the upstream pressure for the section of pipe in question. The upstream pressure then forms the basis of another flash calculation and the whole process is repeated until the entire header has been examined. More sophisticated line sizing formulae are required for relief systems than are normally used for pressure drop calculations. In particular use of the Fanning equation with average vapour properties is not applicable as this only calculates the frictional pressure drop. The other components of the total pressure drop (gravitational and accelerational) must also be considered, in many relief situations the accelerational pressure loss predominates (21). The complexities of relief line sizing requires the use of computer software, preferably with a physical properties generator, for complete solution.

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Manual calculations may be performed if required and in simple cases may be adequate. They should always err on the side of caution; for example, isothermal and not adiabatic pressure drop calculations should be performed. Lapple's method for calculating pressure drop (which is recommended in API-521) is not an accurate method for sizing relief headers, particularly where changes in pipe diameter occur, and it should be avoided if possible (22). Special problems arise where two, or in some cases three, phase flow (vapour, hydrocarbon liquid and water) is present. Here vaporisation of the liquid stream or retrograde condensation of the vapour may occur. A number of short cut methods are available (23, 24), but rigorous solution is only practical with a computer. Equilibrium conditions should be used to predict vapour fractions. This will produce a conservative result as there is evidence to suggest that under conditions of rapid

depressuring a metastable condition exists which inhibits complete formation of the equilibrium vapour fraction.

Sizing of Relief Valve Inlet Lines The pressure drop between the relief valve and the item being protected must be limited to a maximum of 3% of the relief valve set pressure, and preferably less. Higher pressure drops will effect the lift and blowdown characterisitics causing 'chatter' which will damage the valve (20, 25).

Sizing of Depressuring Lines In many cases depressuring valves are piped into the relief header: this may be termed 'uncontrolled depressuring'. It requires some additional calculation to ensure that backpressures at the start of depressuring do not affect operation of relief valves which may be simultaneously discharging. Similarly when the pressure in the depressured vessels is low, relief valve operation should not interfere with the satisfactory completion of the depressuring operation. Where weight limitations pose a problem there are advantages in running a completely separate depressuring header feeding directly into the flare drum or other disposal unit, with a pressure control valve at the downstream end. By maintaining the gas flow at high pressure upstream of the flare knockout drum the volumetric flow rate can be controlled, resulting in a more constant flow of gas; with careful sizing the time to depressure equipment will not be increased. The concept is shown graphically in figure 4 (26). By keeping pressure in the discharge header relatively high, the depressured gas density will also be high and volumetric flow rates will be low, compared to those at atmospheric conditions. This can lead to significant savings in piping cost and weight.

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Obviously the control system must be designed with care to ensure its reliability, and it is usually desirable to provide additional equipment for online testing as an integral part of the design. This system is probably best suited to depressuring groups of vessels of similar design pressure where one vessel cannot overpressure another if the control valve fails closed. Layout of Piping All relief piping should be designed to minimize pressure drop by the use of long radius bends, swept tees and gradual changes in diameter. Although it is undesirable to install isolation valves in relief lines it may be necessary in certain situations (see below). A frequent mistake here is the use of standard pattern ball valves: these have a reduced flow area through the ball which may have a significant effect on pressure drop. Full bore ball valves must always be specified in vent lines. Mach numbers should be limited to 0.3 or below to avoid noise problems and limit the possibility of sonic velocity at elbows and other fittings where the flow area may be reduced. Relief valves are often fitted with ASA 150 flanges on the discharge nozzle and if significant backpressure can be generated the pipe flange rating and wall thickness must be checked to ensure suitability. All tail pipes should feed into the top of the header to ensure that liquid relief from upstream valves do not flood the tail pipes of downstream relief valves.

Discharge piping should be self draining and have a fall in the direction of flow (27). On production platforms, where equipment is installed on several levels, this usually results in the flare knockout drum being located at the cellar deck level. Occasionally low points are required in the header and, as a last resort, if they are unavoidable, must be provided complete with drainage and heat tracing facilities. A vertical leg or 'boot' should be provided to store liquid without reducing the flow area. Drainage from the boot should be controlled by an instrumented level control system, float valves are unreliable and should be avoided.

Location of the Flare Flare location is a major problem for platform designers. The flare must be located in such a position that heat radiation will not pose a hazard to equipment, personnel or helicopters. Older platforms have used pipe flares either free standing above the production modules or supported off the side of the platform. In some cases more than one flare stack is provided, the stack in use at any time being dictated by wind speed and direction.

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More recent platforms use low emissivity type flares with high gas velocities at the flare tip, resulting in improved gas-air mixing, combustion and improved heat radiation levels (29). The heat envelope from the flare can affect radio communications to the platform and this produces an extra constraint on flare location (28). OPERATION OF RELIEF SYSTEMS The operation of offshore relief systems differs in many respects from those onshore. Differences occur for economic and strategic reasons in addition to these cited in table 1.

Isolation of Relief Valves In onshore installations duplicated relief valves or bursting discs are commonly installed; there is little cost implication and weight limitations do not exist. Offshore, the situation is very different; duplicated relief systems are a weight penalty and are not installed unless operating advantages can be demonstrated. In practice duplicated relief devices are installed in locations where isolation and removal of relief devices would cause a process shutdown. In other locations single relief devices are provided with locked - not carsealed - open isolation valves. Where duplicated systems are installed a system of lock and key assemblies are used in preference to interference discs, three way valves or ganged valves. Their main advantage, apart from simplicity, is that they present no obstruction to flow; with ganged valves for instance, there is the possibility that the mechanism will jam at some midpoint, obstructing both relief routes. On oil production platforms crude oil is the major revenue earning product, the associated gas represents the icing on the cake and can if necessary be sacrificed. In any event it is standard operating practice to flare part of the produced gas, as a means of pressure control. Passing relief valves are of relatively minor concern. Fluids leaking past relief and depressuring valves will collect in the flare knock out drum and will be recycled to the crude production train. Ignition and pilot gas supplies Offshore platforms rarely have the luxury of a guaranteed gas supply for the flare pilots. Gas is available from the oil production train and hence a shut down of oil production will remove the gas supply. This system however is of no use during commissioning or start up after a prolonged break in production. Bottled gas is required for these situations and careful assessment is required to ensure that sufficient but not excessive supplies of bottled gas are available. Problems with condensation in the fuel gas line are not uncommon; therefore, heat tracing and/or some form of pretreatment is not unusual.

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Snuffing

The worst conceivable event on a platform is a 'blowout' or uncontrolled release of hydrocarbons to atmosphere from a well. Fortunately these are rare events, the best known cases in the North Sea being on Ecofisk B and more recently Forties D. When a blowout does occur large quantities of flammable material are released to the atmosphere and a serious risk of fire and explosion exists. Blowouts generally give some warning of their occurrance and this 'breathing space' may be used to try and eliminate sources of ignition, among which the flare features prominently. Consideration is therefore often given to flare snuffing by an immediate trip of oil production and the injection of large quantities of halogenated hydrocarbons ('halons') into the flare. The usefulness of this is debatable, as experience suggests that many blowouts will ignite from sources of ignition other than the flare. Purging

During periods where there is no flow in the flare system, there is a possibility that air may enter the flare either by contraction or condensation of flare gas causing a volume shrinkage; or by diffusion of air down the flare from the flare tip. To prevent this a flow of purge gas is required, for short durations fuel gas may be used but during commissioning or after a prolonged shutdown an inert gas usually nitrogen should be used. Husa (30) has developed the following equation for estimating purge rates on pipe flares up to 48" diameter. This may over-estimate the requirement for low emissivity type flares where the cross-sectional area at the tip is less than the pipework flow area. However, Husa's work suggests that anti-diffusion devices, such as fluidic seals, are of very limited value and a conservative calculation of purge rate is advisable until more information is available.

Where q = Purge rate (M3/S)

D = stack dia (M).

Ci = volume fraction of gas Ki = constant (values for some common

gases are given in table 2). Whenever maintenance work is necessary purging with an inert gas is required before breaking into the flare header; purging should continue after the flare has been extinguished and the purge gas and pipework has cooled down, this will minimise buoyancy effects (31). Similarly purging with an inert gas is required before the system is recommissioned.

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Flare radiation

For many years flare radiation calculations have been based on API-521 which advocates a point source formula developed by Hajek and Ludwig (32):

Where D = minimum distance from mid point

of flare to object being considered (M)

F = fraction of heat radiated; (this is often mistakenly called the emissivity)

Q = Heat released (kw) k = allowable radiation (kw/M2)

The F factor is thought to be dependent on the gas moledular weight and/or the flow aerodynamics, quoted values range from 0.2 to 0.5. This relationship was developed for use with pipe flares and not the low emissivity flare types usually found offshore. Although this formula provides an accurate estimate of the radiation level at a distance from the flame, it is inaccurate close to the flare tip. The designer is therefore left with four choices:

1. Reduce flare rates. 2. Increase the distance from the flare to the receiver. 3. Reduce the fraction of heat transmitted from the flare. 4. Increase the allowable radiation level at the receiver.

1. This is not usually a practical proposition, the maximum flaring rate is a function of crude production and can only be altered by reducing the production rate and hence affecting project economics.

2. This can be done by increasing the length and hence cost of the flare boom or by installing a separate platform for the flare. This is not a desirable way to operate.

3. This has some attractions and is one reason for the adoption of low emissivity type flares. (Another is the greater degree of flame stability resulting in less flame distortion in high winds).

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4. This initially has some attractions but needs careful study, the frequently assumed figure of 1.39 kw/M2 still appears to be a reasonable figure. Particularly as an allowance must be made for solar radiation which may reach 0.95 kw/M2 during summer in the U.K. (34). The possibility of high radiation levels in situations where personnel may escape before serious injury occurs, is sometimes considered; however this principle is not valid offshore where space is limited and rapid escape from the flare is frequently highly impractical.

The prediction of flare radiation levels is a less than exact science and a better understanding of radiation mechanisms could result in significant savings in the structural steelwork required for flare booms (35).

Gas Dispersion

On gas platforms cold venting of gas is an accepted practice and on platforms with flare systems it is prudent to check how gas would disperse if the flame was for some reason extinguished. In particular it is important to ensure that the plume of flammable gas will not affect helicopter flight paths. The rate of gas dispersion and dilution below the lower flammable limit is dependent on the buoyancy and momentum of the vented gas and wind conditions. Calculation methods have been developed for this situation, generally on the assumption that gas is vented through a pipe to atmosphere (36). So far no work has been done on the likely dispersion patterns from low emissivity type flare tips; however it should be possible to calculate dispersion rates assuming dilution to the stoichiometric fuel/air mixture at the source.

CONCLUSIONS The design of the pressure relief and disposal system is one of the most complex parts of platform design. The designer has little control over the streams feeding the relief system and is constrained by environmental and operational factors in the design of the disposal system. It is therefore worthwhile to highlight very briefly some developments which would make the designer's task easier:

Sizing Method for Two Phase Flow through Relief Valves. A reliable method to estimate the capacity of relief valves in two phase flow, particularly flashing flow, situations would be extremely useful. A number of companies have developed individual methods but at present there is no commonly accepted method.

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Computer Program for rating Relief Valve Headers There are a number of commercially available computer programs for estimating pressure in pipe networks; however, for one reason or another they are not entirly suitable for venting applications, where pressure drops may be very high and the vapour acceleration pressure loss is significant. This situation becomes even more complex if two phase mixtures are present.

Improved Flare Radiation Calculation method. Although there is now a better understanding of the mechanism of flare radiation than ever before the calculation of the F factor still presents problems forcing designers to err on the side of caution. Perhaps it is now time to look at new methods of radiation based on the Stefan-Boltzmann equation and flame dynamics.

Implicit in these recommendations is the belief that API-520 and API-521 are dated and need revising. There is little doubt that further effort will be spent providing better design methods for pressure relief systems; on the other hand it is also likely that design criteria and legislative requirements will become increasingly strict. Acknowledgement We would like to thank Britoil plc for permission to publish this paper. Opinions expressed are the views of the authors and do not necessarily reflect the opinion of Britoil plc.

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References

1. API-521 Guide for Pressure Relief and Depressuring System

2. API-520 Recommended Practice for the Design and Installation of Pressure Relieving Systems in Refineries, Part 1 Design. Appendix C, Section 3. 3. Kletz T.A., 1977, Hydrocarbon Processing 56(8) p98.

4. Personal Communication.

5. Sallet D.W., 1979, Conference on Pressure Relief Devices, Paper C274/19, Institution of Mechanical Engineers, London.

6. API-520 Recommended Practice for the Design and Installation of Pressure Relieving Systems in Refineries, Part 1 Design, Section 5.4.2.

7. Wallis G.B. 1969, One - dimensional Two-phase flow pp144-6, McGraw-Hill, New York.

8. Bliss D.G.B., Quackenbush TR, Teske ME, 1982, Transactions of the ASME 104(4), pp272-7.

9. API-526 Flanged Steel Safety Relief Valves.

10. API-520 Recommended Practice for the Design and Installation of Pressure Relieving Systems in Refineries, Part 1 Design, Appendix C, Section 4.

11. API-521 Guide for Pressure Relief and Depressuring Systems section 3.16A.

12. Scott D.S., 1980, "Some Seldom Considered Aspects of Pressure Relief Systems" presented to the Institution of Chemical Engineers Symposium on Explosions, Fire Hazards and Relief Venting, Sheffield. (March 1980)

13. Lees F.P., 1977, Instruments and Control Systems, November 1977, pp17-22.

14. Rooney J.P., 1983, Hydrocarbon Processing, 62(1), pp89-92.


16. Pilz V., 1978, German Chemical Engineering (1), pp63-73.

17. Seebold J.G., 1982, Hydrocarbon Processing 61(10), pp75-79.

18. API-520 Recommended Practice for the Design and Installation of Pressure Relieving Systems in Refineries, Part 1 Design, Appendix A.

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19. API-2000 Venting Atmospheric and Low Pressure Storage Tanks.

20. API-520 Recommended Practice for the Design and Installation of Pressure Relieving Systems in Refineries, Part 1 Design, Section 7.

21. Crane Company, 1957 Crane Technical Paper, No.410.

22. Duxbury H.A., 1979, Chemical Engineer (350), pp783-787 and (351) pp851-858.

23. Richter S.H., 1978, Hydrocarbon Processing, 57(7) ppl45-152.

24. Landis R.L., 1982, Chemical Engineering 89(5) pp79-82.

25. Van Boskirk B.A., 1982, Chemical Engineering 89(17) pp77-82. 26. Paruit B and Kimmel W., 1979, Hydrocarbon Processing 58(10), pp117-121.

27. API-521 Guide for Pressure Relief and Depressuring Systems Sections 5.3 A4 and A5.


29. Wilkins J., 1977, Witheridge R.E., Mason J.T.M. and Newby N., Offshore Technology Conference paper 2822, Huston.

30. Husa H.W., 1977, "Purging Requirements of Large Diameter Stacks" presented at Fire/Safety Engineering Subcommittee American Petroleum Institute, September, 1977, San Francisco.

31. Reed R.D., 1972, Oil and Gas Journal 70(7), pp91-2.

32. Hajeck J.D., and Ludwig E.E., 1960, Petro/Chemical Engineering Part 1, 32(6) C31-8, Part 2 (7) C44-51.

33. McMurray R., 1982, Hydrocarbon Processing 61(11), pp175-181.



36. Lees F.P., 1980, Loss Prevention in the Process Industries, Butterworth, London.

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TABLE 1

ITEM ONSHORE OFFSHORE Layout Generally spacious, separation between process units is not usually a problem.

Cramped, equipment is usually stacked in several layers one above the other.

Transport Transport by road and sometimes rail.

All supplies must be tran-sported by supply boat, personnel transported by helicopter. These may be disrupted in bad weather.

Product Storage

Usually substantial storage available.

In many cases storage facilities do not exist or are very limited. Processed gas and crude is pumped directly into pipelines.

Services Connections to local utilities exist (electricity, water, gas). These may be supplemented by on site equipment.

All services are supplied on the platform, if necessary supplemented by bulk deliveries of drinking water from supply boats.

Accommodation Generally none, employees return to their own homes after work.

Accommodation and recreation facilities must be provided for all staff.

Vibration Sufficient damping can be provided by foundation design.

Heavy foundations for equip-ment pose a weight penalty. Design codes give specific advice on vibration.

Construction Traditional construction methods employed.

Modular construction employed with as much work as possible being carried out at onshore construction yards to minimise hook-up operations offshore.

Flare Radiation

Radiation does not present a major problem as the stack height can be increased or the stack located in a remote area.

Flare location presents a major problem, remote location requires an expensive support structure. In addition the flare radiation and turbulent air movements caused by hot gases must not effect helicopter operations.

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TABLE 2

K Values for use in Equation 5

GAS K

Hydrogen + 5.783

Helium + 5.078

Nitrogen + 1.067 (No wind) + 1.707 (wind)

Ethane 1.067 Propane 2.651 Carbon Dioxide 2.651 Butane 6.586 (after Husa, ref. 30)

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INTRODUCTIONCOMPARISON OF ONSHORE AND OFFSHORE PRACTICEDESIGN OF RELIEF SYSTEMSALTERNATIVES TO PRESSURE RELIEF VALVESPIPING DESIGNOPERATION OF RELIEF SYSTEMSCONCLUSIONSAcknowledgementReferencesTable 1Table 2Figure 1Figure 2Figure 3Figure 4

The Design and Operation of Offshore Relief - Venting Systems

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