Substantial gains can be made by deferring or avoiding the installation of downhole sand control. Implicit in this, is the acceptance that sand will arrive at surface and that the processing facilities can remove this effectively, without placing undue constraints on production capacity and uptime.

It is a simple statement, but the bare facts are that until now, little effort has been made to design bespoke sand separation equipment which will remove sand on a continuous basis without the need for regular shutdowns. The majority of equipment which does exist has been converted from its original duty-normally in the mining industry-without any modification or else it has been designed "in the mind" without any development testing. The majority of testing has taken place in situ with an appropriate level of failure and lost or deferred revenue.

As economic margins tighten, all operating companies are looking at ways of excluding sand without impacting PI or means of improving sand handling at surface. This review has prompted service companies to invest in the design, development and testing of new items of equipment often in conjunction with an oil company as sponsor and tester. This process is only just beginning and the benefits will not be available for a few years at best.

Role of process engineers in designing sand tolerant facilities

If the decision is made to defer or avoid sub-surface sand control, then the production facilities must be capable of handling any produced sand on a continuous basis. This requires the Process and Facilities Engineers to consider sand at the very early stages of a design and study its impact on the process route, line and vessel sizing, and materials of construction.

Early discussions with Petroleum Engineers and specifically Production Technologists are necessary to assess the probability of sand arriving at surface. If this is high, then the quantities of sand likely to be produced need to be defined. The phrases 'little sand' or 'no more sand than normal' are of little use to a Process Engineer despite an understanding of the degree of uncertainty which surrounds such predictions.

Probably the most important item of process data required is the produced sand particle size distribution as this allows settling rate calculations to be made. In the case of frac sand or proppant, this is easy as is its density and other physical properties are well known. However, it is important to note that there will be a larger proportion of fines back produced due to the crushing action of the frac. For produced sand, samples need to be taken. For an existing reservoir, the best method is to sample the sand collected in the primary production separator during internal cleaning. Taking samples from the sand wash line or produced water outlet is risky as an unknown quantity of fine material will leave with the hydrocarbon phase. Sampling of the inlet stream is not yet possible but the application of sand separation cyclones may yield good results.

Samples from a new reservoir or production area are even harder to take. The current methods are to core the reservoir and sample from the well test separator but there are many problems associated with this. Well tests by their very nature tend to be of short duration so the sample size may well be small and unrepresentative and they are at relatively low flowrates so sand may drop out in the tubing. The reservoir may be split into zones and it will not possible to determine from where the sand is being produced. Finally, the separator may contain some sand already.

Other tests which should be carried out on samples taken for sand evaluation are:

·Calculation of specific gravity. To determine settling rates.

·Average particle mass if centrifugal methods are being persued.

·Component analysis. To determine erosive characteristics.

·Oil phase viscosity and produced water salinity.

A good understanding of the possible operational problems is required to assess the impact that the new sand handling facilities will have on manning levels, production deferment, and operating costs. It is possible that the use of surface sand handling facilities will make a project uneconomic or give a low rate of return.

In addition, an engineer must understand how sand can affect routine operations and problems identified should be designed out during detailed design. For example, erosion damage can be minimised by the use of control valves with hardened plugs and seats (e.g. stellite and tungsten carbide) and by using sacrificial sleeves on vessel nozzles. Instrument failures and blockages can be prevented by designing vessels which will not trap sand in level bridles.

1 Sand production monitoring

The impact of downhole sand control on project economics has led an increasing number of Opcos to consider delaying its installation until proven necessary. Such a strategy however requires a reliable on line sand detection and monitoring.

Various methods can be used to detect or monitor sand production. Selection of the appropriate method is a function of the level of sand production that needs to be detected, the production conditions, the location and the potential risks associated with sand production.

Group experience with on line systems has generally been disappointing. Poor system reliability and high sensitivity to changing production conditions (rate, GOR etc) have led to major calibration and operational problems. However, indications are that some of these difficulties are now partially resolved.

Sand production monitoring programmes should be defined jointly by the Production Operations, Process Engineering and Production Technology departments.

1.1 Units

It is important to note that sand production in gas wells is measured in kg/MMscm. Sand production levels in oil wells are measured in grams per cubic meter oil (stock tank) or Pounds of sand Per Thousand Barrels (pptb) (1 pptb = 3 g/m3). A sand concentration of 5 pptb is equivalent to 0.001 percent volume. An important remark is that sand production levels lower than say 50 pptb are difficult to measure accurately because of the very low sand concentrations in the wellstream.

1.2 Sand production characteristics

Sandstone reservoirs which do not require sand control may produce hydrocarbons with various sand concentrations depending on the degree of rock consolidation. In these reservoirs, some sand may be produced from time to time and may depend on a large number of variables e.g. drawdown, production rate, watercut, GOR, etc. A small level of irreducible sand production is likely to exist.

Field experience shows that sand production is generally rate dependent. However sand concentration cannot be simply related to flow rate as sand production may increase as soon as the well is beaned up but subsequently declines again to background. This is probably due to the enlargement of pseudo-stable cavities behind the casing which is discussed below.

Accurate measurement of sand concentration in the wellstream is generally difficult because of the erratic nature of sand production, the difficulty of obtaining representative samples and the low absolute sand concentrations.

1.3 Why is sand production monitoring required?

Sand production monitoring may be required for the following reasons:

·To provide an early warning of a sudden increase in sand production which, if permitted to continue, might cause an unacceptable degree of metal erosion in the subsurface or surface production system. Timely detection of high sand production rates is a genuine requirement for high velocity gas streams and high velocity, high GOR oil streams, especially in locations where the potential consequences of equipment failure are intolerable e.g. offshore platforms, subsea wells. Guidelines for acceptable sand production rates in high velocity gas wells are discussed elsewhere in the manual.

·To prevent sanding-up of wells or surface facilities.

·Manage sand production - minimise the risk of erosional failure. Extend velocity limits thereby optimise production offtake.

·For trouble shooting i.e. to identify which well from a cluster or flowstation is producing sand or which interval in a well is producing sand. Remedial sand control measures can be implemented once the well or interval is identified.

·To monitor cavity growth behind the casing.

·To help in validating rock mechanical models in conjunction with sand influx tests.

1.4 Sand production monitoring methods

 1.4.1 Passive monitoring

The simplest way of monitoring sand production is to measure sand volumes recovered in sand traps, separators or storage tanks during periodic maintenance or by routine hold up depth tagging in the wellbore. This must be combined with periodic inspection of items susceptible to high erosion rates e.g choke internals or Non Destructive Test (NDT) inspection of critical components.

This method maybe adequate when expected sand production levels can be handled by the production facilities on a long term basis. Sand may be carried over before an increase in sand production is detected. When a significant increase in sand production is detected other methods need to be used to identify the well(s) which are producing sand and at what rate.

1.4.2 Flowline sampling

A sample of the wellstream is periodically taken and the sand content is measured. Sampling for sand is an operation which is labour intensive, costly and not entirely free of safety hazards. Sand concentrations determined from flowline samples can be very inaccurate for the following reasons:

·The sample is not representative of the wellstream

·The well may be slugging

·The random nature of sand production

·The sample volume is not adequate to measure the very small sand concentrations encountered in practice

·Poor handling of the fluid samples.

Furthermore because of the sampling frequency and the turnover time, it is unlikely that a sudden massive increase in sand production of a particular well can be detected before a significant amount of sand is produced and/or the well sands-up.

The sampling point should be positioned in a location where sufficient turbulence exists to homogenise the wellstream i.e. downstream of a choke or a tee, preferably in a vertical section. The sample point is generally a small valve tapped in the flowline.

1.4.3 Erosion probes

Erosion probes were first developed by Exxon as a safeguard against the erosional effects of sand. The probes are thin walled steel cylinders with a closed end and are installed at one or more locations in the flow line. When the probe wall is eroded, the flowline pressure is transmitted to a pressure signalling unit or to a pilot valve to actuate shut down controls. Erosion probes only give a qualitative indication of erosive conditions as the "sensitivity" (i.e. the amount of sand that has to be produced to erode the probe wall) of these devices is presently unknown.

Erosion can also be caused by other factors than sand production. Further laboratory work may allow a more quantitative estimate. However it can be ensured by careful selection of the probe that it would fail long before the integrity of a critical component is at ris 

1.4.4 Acoustic sand detection probes

Acoustic sand detection devices use a sensor rod inserted in the flowline or are simply clamped on the pipe. A piezo-electric crystal is used to detect the impact of sand grains on the sensor rod or pipe wall. This transducer converts vibrations caused by impact into electrical energy. The signal is preamplified prior to transmission through a coaxial cable. It is then processed to give the sand impact rate i.e. the sand production rate.

So far, the experience with acoustic sand detection systems is disappointing because of the lack of reliable calibration equipment, poor system reliability and cumbersome data presentation systems. Sand detection systems are also costly and expensive to maintain and operate as continuous intervention by skilled and trained personnel is required in order to maintain a reliable output.

Sand detection systems have proven helpful when used in a qualitative mode i.e. to detect threshold levels and trends in sand production. Derivation of quantitative sand production data requires in-situ calibration because the probes are highly sensitive to local production conditions i.e. flowline velocities, flow characteristics, grain size distribution, probe location. Presently the only acceptable way to provide calibration points for acoustic sand detection systems is by injection of known quantities of sand in the flowline. Currently industry efforts are under way to couple acoustic sand detection equipment, in particular clamp-on probes, to data processing systems, which (potentially) are capable of correcting detector output real time to changing flow line conditions, such as flow rate, gas liquid ratio etc. The corrections are based on knowledge of how detector output depends on these parameters. In principle this would eliminate a number of the problems, mentioned above, associated with the use of the equipment. Experience with such advanced systems will have to indicate to which extent the, sometimes erratic, relation between sand production and detector output, can be translated into useful correction algorithms.

In view of the above, acoustic sand detection equipment, at present, should be considered only when other forms of surveillance do not give the required level of protection against sand production. 

1.5 Guidelines for a sand production monitoring philosophy

Sand monitoring methods can be very expensive in terms of equipment and manpower costs. They can also result in unacceptable loss of revenue if for instance a well is beaned back on the basis of an inaccurate sand cut measurement. It is therefore important to correctly formulate the sand production monitoring requirements and select the appropriate method.

Passive sand production monitoring should be relied upon when the production system can cope with the expected sand production levels on a long term basis and the usually low risk of a sudden undetected increase in sand production which could ultimately lead to well or separator sand-up can be tolerated. Preventive maintenance may need to be enhanced to adequately monitor erosion of critical components or sand fill of production facilities.

It is recommended to move away from routinely taking large numbers of generally unreliable and unrepresentative samples. When zones are initially opened up or operational experience indicates, flowline sampling can be carried out as required to establish sand production trends of selected wells. Better supervision and more representative results can be expected because of the non-routine character of such tests. Operators which are currently involved in large scale sand sampling operations should critically review their programmes with a view to identify the problem wells.

Detection of sand under production conditions which could give rise to high erosion rates is feasible as the acoustic sand detection technology is based on the same physical principle that causes erosion i.e. kinetic energy. However in order to maintain a reliable output acoustic sand detection systems require continuous attention from a skilled operator which makes this method impractical for many cases.

Derivation of quantitative sand production data also requires on site calibration. The usefulness of quantitative data is questionable because it is difficult to translate these into expected erosion rates as reliable "erosion models" are not currently available.

Permanently installed probes could however be used for regular surveys by specialist contractors using portable electronic equipment to provide quantitative sand production trends of individual wells. Portable instrumentation has also proved useful for gathering sand production data during dedicated sand production tests.

Accurate measurement of low sand production levels, which can be handled by the production system on a long term basis and which do not pose a serious erosional threat, is not required and currently not feasible in practice. Consequently it is also unrealistic to base the decision for remedial sand control on threshold sand production levels measured under these conditions.

In summary, any sand production monitoring programme should be adapted to the local production environment, i.e. the production conditions, the level of support available and the potential consequences of sand production.

2 Sand separation from produced fluids

Sand separation direct from a wellstream is generally not an acute problem in the case of intermittent sand production because of the small volumes involved. It may become an issue if continuous and significant quantities are produced because of its impact on production. Dedicated sand removal facilities may then be required, the type of equipment used depending on the stream carrying the sand.

2.1 Sand from oil

Continuous removal of sand from oil streams is currently not possible due in part to the high pressures involved, the multiphase character of well streams and the difficulties associated with removing the sand product. Continuous desanding from liquid hydrocarbon streams is being investigated by several manufacturers but no product is yet available for testing.

The traditional method is to let the sand settle out in the production separators and storage tanks and periodically shut down and flush out with water using dedicated sand wash bars. Blockage of separators is not usually a problem as the residence times are sufficiently low such that the majority of sand particles leave with the produced water. Some sand will obviously be deposited until the water residence time is smaller than the time taken for a particle to settle under gravity (Stokes law). Hence, for vessels which are over-sized with respect to water, as nearly all are in their early years, more sand will settle out than in a vessel designed for the appropriate flowrate.

If this theory of self regulation is true, which is disputed by some, then any sand which leaves the production separators is bound to deposit in degassers,TPI's or floatation units where the residence times are generally an order of magnitude greater. The logical extension of this argument is that sand wash facilities in separators are not necessary and sand should be removed upstream of floatation units, hydrocyclones etc.

2.1.1 Separator sand wash facilities

In the past, separator sand wash systems were a hastily assembled collection of pipes and nozzles placed in the base of a separator. Rather than designed in response to observed behaviour, they were designed subjectively to fluidise sand simply by using a large number of water jets and then draining off the fluidised mix. The nozzles used were just 10-12 mm pipe with their ends crimped to give a jet. The principle problem with this system was that the high velocities and the direct impingement of the water on the vessel caused rapid erosion and left areas of sand unfluidised which subsequently compacted and grew. A typical system such as this would only remove 5% of the deposited wet sand.

Sand wash can be accomplished on or off line but there are problems associated with each. Offline washing allows the use of low pressure water and removes the risk of oil entering the sand disposal system but it interrupts production. Online jetting however, imposes greater risks which need to be designed out or minimised. For sand wash to be truly effective, research has shown that regular washing for short durations is preferable to longer washing at longer durations as this prevents the sand accumulating and compacting.

The source of the jetting water is also important. Online jetting requires a high pressure water source either from the water injection system or from a dedicated pump. Offline washing can be accomplished using utility water at 7 bar. Use of seawater on a regular basis may encourage the formation of scales, but this could be limited by using recycled produced water from the oily water treatment system. However, recycle of small oil droplets and sand fines is a possibility the latter of which may block the spray nozzles. Fine sand can be removed by using 50 micron cartridge filters. 

2.2 Separating sand from gas

This can be further sub-divided into separating reservoir sand and frac sand. For the former, its production is continuous and at a relatively constant rate so permanent facilities are required. Frac sand is only produced for a finite time after stimulation and can be handled by temporary facilities with a higher degree of manual involvement. In addition, proppant is generally coarser grained so making separation easier but it is also very hard so increasing the risk of erosion damage.

Therefore, it is the design of permanent facilities which provide the greatest challenge to engineers but the experience gained in the separation of frac sand will yield valuable information.

2.2.1 Separation of frac sand

A fractured well must be flowed clean of completion fluid and excess proppant before it is connected up to the permanent production system. Proppant must be removed, continuously, by purpose built, temporary facilities capable of handling large quantities of sand. The amount of sand to be back flowed depends on the success of the frac and whether the well has screened out. Although ideally no proppant should be back produced in practise many fracced wells produce significant amounts of proppant. A typical stimulation may back produce some 200 kg/hr sand for 21 days with typical peak rates of 450-900 kg/hr.

2.2.2 Separation of reservoir sand

A series of manufacturers provide sand separators for high (above 100 bar) pressure gas systems, the most well known being Paladon and Burgess-Manning.

These proprietary designs are based on bundles of small cyclones housed inside the separator shell. The use of small cyclones makes separation efficiency insensitive to flow rate changes and they can be easily adapted for continuous low flow operation by removal or blinding of a number of cyclones.

The principle of separation is centrifugal force and so the smaller the cyclone the greater the efficiency. Upon entry, the gas stream is split into a multiple of small cyclones each having, normally, two tangential, diametrically opposed inlets. The high forces generated push the sand out of the base of the cyclone into a storage chamber ready for removal. The cleaned gas reverses direction and leaves via the top of the cyclone.

Cyclone separators will remove small quantities of sand very efficiently but as they are centrifugal devices, efficiency is dependent of particle mass and not size. Typical removal specifications are 100 % of all particles above 10 micron with sand loadings of up to

3 kg/MMscm. Normal loadings are typically below this. Their pressure drop is high, with figures of between 0.25 to 0.5% of the inlet pressure being normal.

Vessel height is dictated by the sand storage volume required and typical specifications from the Southern North Sea show values of six months at maximum sand burden. This essentially means that the vessels can run for a full year without being emptied. If they do require cleaning, the incorporation of sand wash facilities is recommended to help fluidise the sand but also to keep it wet during storage. Jetting water can be supplied by the utility water system but obviously cannot be permanently hooked up. Some operators have a connection from the kill pumps (or similar high pressure units) to allow fluidisation under pressure.

Pre-conditioning gas wells by flowing them at a THP below the minimum set for the worst case has also been successfully carried out on Sean. This conditions the wellbore and clears the tubing of any sand prior to a prolonged production period and allows the accurate prediction of a sand burst from a reservoir. Following preconditioning, the base line for any sand detection device can be set with confidence.

2.3 Separation of sand from water

In typical production systems there are two water streams which will contain appreciable levels of sand. A continuous produced water stream from the production separators and an intermittent water stream as a result of sand wash operations. This sand will cause erosion of hydrocyclones if allowed to enter and will separate out in degassers and floatation units due to their calm flow regimes. The current accepted method is to hold the sand in the separators and periodically flush it out  but methods are being developed for the continuous removal of sand from water. The most promising being 'sand cyclones'.

These were developed by the mining and water purification industries to remove solids from water both to recover valuable ores and to meet produced water specifications. Extensive use of this technology is also seen in the drilling industry to remove solids from drilling fluids

2.3.1 Sand cyclones

The water and solids enter the unit tangentially which sets up a circular flow inside the head space. The solids and liquid are drawn through the tangential slots and are accelerated into the separation chamber where centrifugal force throws the heavier particles to the vessel perimeter. The solids fall under gravity down the wall and enter the quiescent collection chamber. These solids are either periodically purged or continuously bled from the chamber through an appropriate valve into a collection and/or washing system. The desanded liquid is now drawn into the low pressure vortex and rises up through the vessel and leaves through the cyclone outlet.

The water flows into the sand cyclone at separator pressure and temperature. The sand is separated and purged, on a timed basis, through a actuated valve to disposal. The vessel pressure provides a driving force to ensure that the slurry moves and a special conical orifice ensures that some back pressure is maintained on the vessel. High levels of sand are detected by a nucleonic level detector or some similar non intrusive instrument. Some form of flushing system may required to clean out the vessels on shutdown. The desanded water flows to a series of hydrocyclones and the deoiled water passes through a level control valve to a degassing vessel prior to disposal.

2.3.2 Potential risks

As this is relatively unproven technology, there are significant associated risks. These can be summarised as follows:

The amount of oil which will adhere to the sand is not quantifiable and therefore the disposal route needs to be considered carefully (see Section .3). If the sand is water wet, then the quantity of oil will be small especially after experiencing the high forces inside the cyclone. If the sand is oil wet then direct disposal into the sea or water course will not be possible and some cleaning facility may be required.

The effect of sand cyclones on downstream oil/water separators is unknown at present. It is claimed by the manufactures that the cyclones will cause the oil particles to agglomerate and not shear but neither process is supportable by research or testing. If excessive shear is found in practice then a chemical coagulant could be injected upstream of the oil separation facility. 

2.3.3 Specification

The following are typical specifications for a sand cyclone. It is important to note that the separation efficiency of a centrifugal device is not dependent on particle size but its weight. Therefore it is not possible to give a standard specification as you would for a filter, i.e. removes 100% of all particles greater than 100 micron.

Pressure range: Standard units 16 bar. Specials up to 100 bar depending on size.

Temperature range:Full range of EP temperatures

Flow range:2 - 2000 m3/hr per unit

Turndown:2 to 1 (without loss of efficiency)

Sand burden:1% w/w maximum. Max particle size = 8 mm

Pressure drop:0.3 to 0.8 bar maximum

Design codes:BS5500 or ASME VIII and NACE MR-01-75

Materials of construction:Carbon steel, coated carbon steel or stainless 316; Duplex (1993)

Separation efficiency:Typically 98% above 75 micron for SG 2.5 to 2.7

Manufactures:Lakos, Krebs Engineering

3 Sand cleaning and disposal

One of the major problems associated with sand production relates to the disposal rather than equipment problems. Typical regulations permit the overboard disposal of sand providing that it is clean enough not to produce a visible sheen on the water surface and it is not contaminated with LSA (Low specific activity) scale. Plants which process heavy, viscous oils are more likely to require sand cleaning facilities than those producing light oils and condensates, though this may change as legislation becomes stricter. Many facilities can put sand direct into the sea as it remains water wet with no free oil.

3.1 Cleaning of wet sand

Sand cleaning equipment falls into two distinct categories: newly developed and modified drilling equipment. The latter technology was based on the analogous but more difficult problem of removing oil based mud from drill cuttings due to its tightly bound material in the pores and the break up of clay like materials which tend to form complexes with oil droplets. Removal of oil from sands should be somewhat easier due to its pore free nature and lower viscosity.

Utilising existing cuttings systems has been looked at before but a variety of problems arise. The mass flow rates are orders of magnitude apart (kg/hr not t/hr) and the particle size distributions are substantially different. Also intermittent operation on sand (mixtures are not possible to prevent contamination of the mud) is not considered practical due to operational conflicts and retaining large complex systems after drilling is complete is not thought to be economic.

3.1.1 Solvent washing

Washing the sand with a aqueous or solvent based liquid is probably the best method. Both methods have been used successfully to treat contaminated beach sands but these are onshore processes starting with high (80% w/w) oil concentrations and have associated solvent treatment systems.

The ideal washing medium must be water and experience has been gained by companies in washing oil contaminated produced sands in an agitated environment using hot water. Hydrocyclones mimic this effect with their high shear rates and produce oil free sand but with detrimental effects on cyclone life. In onshore plants a hot water supply is readily accessible, offshore the only water available in large quantities is sea water which at high temperatures (65° C) is highly corrosive.

3.1.2 Centrifuges

Centrifuges are used extensively by the drilling industry to remove cuttings from mud streams. The market leaders in this area are Thomas Broadbent and Alfa Laval. The former has developed a new process which mixes the sand/oil/water mixture with a wetting agent (BP superwetter) and separates the solids with a shale shaker and a centrifuge. The product sand is oil free but coated with the wetting agent. The agent is environmental friendly and can be disposed of directly to a watercourse. The liquid stream containing the oil and the agent are then separated and the wetting agent recycled. Its principle drawback is that the wetting agent will only function if the feed stream is 5-8% w/w water not the 20% typically seen after settling. In addition, the cost of the agent and the equipment is seen as a barrier to acceptance for this duty.

3.2 Sand disposal procedures

1.Disposal of radio-active material (LSA scale).

Produced sand may be coated or commingled with barium sulphate scale, which contains traces of radioactive elements in concentrations sufficient to cause "low specific activity (LSA)", and as such is covered by the radioactive substances act.

The H.M. Industrial Pollution Inspectorate do not permit the backloading of unconsolidated LSA material but insist on disposal at sea. Each North Sea installation has a cumulative yearly allowance for dumping LSA material which is allocated in Giga-Becquerels. LSA scale can be identified offshore and handled accordingly.

Samples are sent for analysis which establish the level of activity, and together with an estimation of the total amount of material involved a cumulative figure for each installation can be kept. The process is monitored and the Head of Mining Installation (HMIPI) informed accordingly. The current allowance far exceeds requirements.

2.Non LSA-contaminated sand.

Such material is backloaded to shore and handed over to a licenced disposal contractor. This includes non-LSA contaminated sand from the oilfields and most of the produced sand volume from the SNS gasfields, comprising back produced proppant from hydraulic fracturing (Leman F and G).

This will be disposed of under the auspices of the appropriate local authority, probably to a back-fill site.

Minor amounts of sand from other SNS gas platforms are disposed offshore.

3.Disposal of hydrocarbons.

Traces of hydrocarbons may be associated with produced sand. Disposal of these hydrocarbons at sea by dumping requires specific exemption from the department of energy, which is usually granted on the grounds of the small volumes involved.

4 Subsea sand separation

A number of small field discoveries can only be developed economically using subsea satellites tied back to existing platforms. These economic constraints dictate that the subsea facilities must be simple, operate with a minimum of intervention and have wells of high productivity. This latter demand means that reservoirs which could be sand producers are not developed due to increased cost of installing downhole sand exclusion or sand tolerant production facilities. The latter can lead to oversized flowlines and equipment damage and a increased risk of asset failure due to sand breakthrough. In addition, low velocities can lead to sand deposition and partial blockage. This in turn will increase pressure loss and may lead to accelerated corrosion beneath the sand layer.

These problems can be solved by two means:

1.Separate out the sand at the wellhead.

2.Ensure that the correct flow regime exists to transport sand to the platform.

4.1 Subsea wellhead separation

4.2 Flowline sand transport

5 Miscellaneous equipment

This section deals with other major items of equipment which are necessary to handle produced sand. This list is not exhaustive as specialist equipments exists for every device.

5.1 Sand filters

In line filters offer the possibility to separate out all particulate matter from a gas stream but if used on a continuous basis they are vulnerable to plugging and require significant operational and maintenance effort. Filters rely on a screen to separate out particulate matter and if sized to filter sand the holes are generally about 200 mesh (0.165 mm diameter) (see Fig. 776). If used on high velocity gas wells, filters, if they do not plug and burst due to high differential pressures, may be eroded by the abrasive material. As a result, these filters are of little use in continuous service and if fitted are soon either by-passed or operated with no screen.

In line filters can be considered for short duration well tests where produced sand volumes need to be accurately assessed and adequate operational support is available. A dual filter arrangement is preferred as it allows switching between vessels.

5.2 Non intrusive level detection

Measuring the levels of sand within a vessel is best achieved by non-intrusive devices which are unaffected by the vessel contents. The most reliable and the most commonly used are the radioactive devices such as the "Gammatrol" marketed by ICI and a similar instrument marketed by Foxboro. These systems use a low activity radioactive source located on one side of the vessel which emits a fan of radiation across the width of the vessel. This radiation is detected by a series of detectors located in the plane of the source but within the radiation beam. The unit is calibrated on an empty vessel to give 0% and then on a full vessel to give full scale.  The advantage of this system is that it is non intrusive, has no moving parts, and it is intrinsically safe. As it is a source of radiation, strict procedures and laws govern their use, maintenance and installation. However, the only part which cannot be handled by the local maintenance staff is the source itself which must be installed and removed by a registered worker.

6 Velocity limits in pipework

The current industry standard for setting velocity limits in pipework to minimise erosion/corrosion is set by API RP 14E. This formula correlates maximum allowable velocity to density using a dimensioned constant C (100 in imperial units, 125 in metric). This equation was developed based on experience from wells in the Gulf of Mexico and defines maximum velocity as that point at which velocity becomes the most significant factor in removing the protective corrosion layer or inhibitor film. As defined, it was based on carbon steel piping and does not reflect the range of materials in use today. Applying this limit to duplex stainless steel which has a superior hardness will lead to oversized lines but how much to increase the velocity to compensate is a matter of intense debate.