By Carson Hu

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24 Oct,

Right now, there are over 3,000 facilities on the Outer Continental Shelf involved in the collection and treatment of oil and gas. These oils and gases are collected from wells -- a process that's performed using certain types of high pressure valves. Of course, different types of American ball valves offer different results and it's crucial that the right projects are executed with the right types of valves. Quite often, the types of valves being used are ball valves, sometimes referred to as pig ball valves or pig vales (as they are used in conjunction with pipeline pigging systems). Before sourcing and investing in valves, it is important to understand the degree to which these valves may differ from one another. Let's delve into some of the defining characteristics of ball valve types. Ball Valve Body Styles Before getting into the exact types of ball valves that are available at the moment, it's important to remember that there are actually four separate types of body styles. These include the single body, split body, top entry, and welded styles. The styles of ball valves available differ from the types of ball valves available. This means that there are number of potential variations that you can see in ball valves. The great thing about this variety is that it means that there is more potential applicability in ball valves than there would be otherwise. Full Port Ball Valves: Turning to the different body types of ball valves, we can first look at the full port ball valve. A full port ball valve is defined by the fact that it has an oversized ball. The oversized ball has a purpose -- it is the same size as the pipeline. This means that there will be less potential friction less than there would be if the ball wasn't the same size as the pipeline, and the flow involved is unrestricted. The valve is larger as well. Standard Port Valves: As their name suggests, standard port valve are quite usual. This means they're less expensive than some alternatives. This type of valve has a smaller ball, and therefore the valve itself is smaller as well. The flow going through the pipe will in turn be smaller and will typically be about one pipe size smaller than the valve's pipe size. This makes it more restricted. The V Port Ball Valve: The V port ball valve is named after its V-shaped seat. What this means is that the orifice through which the product flows can be more easily opened and closed to change its direction. While many like this idea, the construction of this type of valve means that it can't be used just anywhere. It typically needs to be utilized in a more secure site. When the valve is opened, it is usually opened at the "small end" first, which helps stabilize the flow control. Trunnion Ball Valve: Then there is the trunnion ball valve, which doesn't exactly give much away through its name. This type of valve will actually anchor the valve at the top and the bottom through a particular mechanism. This would be applied on larger and more high pressure valves. While this type of valve isn't going to fit everyone's needs, it can definitely be used for particularly high pressure projects. Manually Operated Valves: Finally, these types of valves can be closed more quickly than their counterparts. Though this is an advantage in some cases, it also means that there can be a risk of a water hammer. These can include an actuator, which can be pneumatically or motor operated, which will in turn be used for on/off flow control. The valve will also have a positioner, which transforms the control signal into an actuator position. The flexibility of this type of valve is certainly an advantage to most projects. Now that you're more familiar with the styles and types of ball valves, you'll be in a better position to make decisions that will support your needs. For more information, please contact us today.

Selection guidelines for wellhead equipment

This article describe the design and selection criteria necessary in the construction of safe and cost effective Wellheads and Christmas trees.

 

Standardized wellhead design

The objective of standardizing wellhead design is to obtain a cost effective completion of the well and ease of well maintenance.

Wellheads have traditionally been of the individual spool type. The spool type wellhead offered flexibility because it was relatively easy to add or omit casing strings. However to further enhance safety and rig time saving, wellhead design evolved from the spool type wellhead to the compact wellhead.

The compact wellhead is a technically superior design which offers enhanced safety and rig time savings without incurring a direct cost penalty. The design of compact wellheads is constantly evolving and there are now several variations available on the market.

Note that BOP protection is an essential factor of wellhead design which should never be underestimated particularly in the workover situation .

Need for uninterrupted BOP protection

Cementing reliability

As a result of potential safety hazards the wellhead configurations should be such that it is not necessary to remove the BOP after cementing. The wellhead most traditionally used in the drilling industry has been of the individual spool type. With these types of wellhead the BOP has to be removed each time a casing is cemented thereby relying on the cement to seal the annulus and on the float equipment to seal the inside of the casing.

Experience has shown that the cement does not always reach the hydrocarbon-bearing formations resulting in either "roping" of the cement or micro annuli; as indicated by annular pressures. Similarly, the float equipment, which is seldom designed to act as a hydrocarbon barrier, can be eroded or pumped through.

Nipple-up time

To improve the safety and cost effectiveness of wellhead operations the BOP should be designed so that it has to be run only once and all casings, hangers, seal assemblies and tubings can be run through it (unitised wellheads). This design results in rig time saving and enhanced safety not only of the well but also of personnel as it requires less heavy-lifts and work under the BOP.

Definition of a wellhead

A wellhead is the crossover between a BOP or Christmas tree and the various casings of the well. For design purposes the wellhead, tree and casings should be considered as pressure vessels, which have to be hydrocarbon tight. This is complicated by the many penetrations, outlets, inspection ports and large through bore connections.

Types of wellhead

There are several variations of the compact type of wellhead and the final choice will depend on the category of well and its unique characteristics such as pressure, flow, etc. Also if it is an onshore or offshore well.

Wells can be divided into the following six categories:

·Oil Producers

·Gas Producers

·Gas Injectors

·Water Injectors

·Water Producers

·Gas Lifted Wells

The following types of well are defined as "specialist":

·Steam Injection

·Beam Pumped

·ESP Lifted

·Plunger Lifted

·Jet Pump Lifted

·Sub-sea

One of the main advantages of the compact wellhead, also know as the unitised wellhead, is its reduced height; which is one of the requirements of the selection criteria.

To make wellheads fire resistant by "add ons" is not recommended. The preferred approach is to design fit for purpose fire resistant wellheads.

Wellhead selection

Prior to selection the following aspects should be considered:

·It is possible that weakness of the wellhead systems can be concealed. This situation can occur when the formation evaluation is carried out using Drill Stem Tests which bypass the casing and head. This practice is unlikely to reveal any weaknesses as most exploration wells do not become 'production' wells.

·The casing scheme finally selected will impose a number of restrictions on the wellhead design, such as pressure rating, tie-in points, etc.

·The selected BOP system will have an impact on the upper connection style.

·It is important that both drilling and production requirements are reconciled in the design phase to maximise operating performance.

Selection of wellhead equipment usually involves the following departments/personnel:

·Exploration and Production who provide data for the objectives.

·Production department (Technology and Well Services) who define the production, testing, and completion requirements.

·Driller or Production Operator who finally selects the wellhead.

Normally the wellhead is selected by Drilling Personnel, based on the interpretation of the forecast by the Exploration team.

Exploration and production wellhead

In the past the standard practice was to develop a field with the back-up exploration wellhead. This practice was based upon the availability of equipment and a propensity towards standardisation.

The completion, normally designed by a Production Technologist, was then added to the Exploration Wellhead. Unfortunately the exploration wellhead was selected on the basis of information yet to be validated, and, very often, with short term seal design. As a result the exploration wellhead was only guaranteed hydrocarbon tight for a short period of time and therefore became the weakest part of the construction. The tubing, tubing hanger and Christmas tree were then relied upon for the integrity of hydrocarbon containment.

It is recommended to select the production casing of a well on the same engineering criteria as the testing/production tubing and in accordance with casing design standards. The completed well is then subjected to either a Production Test or a Drill Stem Test.

The same practice that has been adopted for testing/production tubing has been applied to the design of wellheads. The benefits of this practice are that in the event of a discovery the wellhead used for exploration is also suitable for permanent completion with less functional limitations and reduced chances of future interventions.

Design standards

The design should be in accordance with the following standards:

·BOP: API specification 16A

·Wellhead: API specification 6A

·Casing: API specification 5CT

Selection criteria

The selection of a wellhead depends on the objectives of the well and its completion requirements, such as pressure rating, tie-in points, wellhead bore, etc.

The selection criteria must include the following:

·Technical specifications; Reliability and Completability.

·Maintenance requirements; Repeatability, Retrievability, Side-track ability, and Tie-back ability.

·Rig time saving.

·Low profile.

·Weight reduction.

·Purchasing cost.

·Delivery.

Ranking of the different available alternatives in order of priority varies with each application. Standardisation is further hampered by the different casing schemes, bore size and pressure rating as well as modern tighter casing schemes and slimhole drilling.

In the past the importance of completability and maintainability have often been overlooked by designers. It is therefore recommended to adopt a standardised approach to design. This does not mean all future wellheads should be identical. It does mean that such an approach to design will determine the objectives and allow the incorporation of any new engineering developments that will achieve those objectives by the most cost effective methods.

Offshore wellheads

The wellhead used during offshore appraisal drilling with a floating rig cannot be used during the platform development phase. Therefore the wellhead must be selected to suit the field under development.

The main designs are compact type wellheads which are available under the following trade names:

·Compact Wellheads

·Unihead

·Multibowl

·Speedhead

·Unitised Wellheads.

Compact wellheads reduce the height of the assembly significantly and allow the use of smaller valves and lighter assemblies which reduce the costs. However, smaller valves are a disadvantage when a well has to be killed by pumping.

Onshore wellheads

When considering wellhead selection for onshore, the exploration and development situations are different to those offshore. For onshore, there is a tendency to extend the use of the wellhead used in exploration and appraisal, into development as it is usual for the exploration and development of onshore drilling to be performed in a back to back sequence with the same rig. Hence the popularity of the flexible spool type heads in spite of their shortcomings.

However, the experience indicates that in using uniheads, it is not necessary to make any distinction in design - provided that the unihead is maintainable - they offer enough flexibility with enhanced safety and rig time savings. Therefore it is recommended to design the wellhead for both exploration/appraisal and development. Although the operational flexibility is reduced this is considered a minor disadvantage when measured against the overall benefits.

Quality assurance

ISO- is the international standard for quality assurance.

During the design and fabrication stages it is advisable that Quality Control Surveyors, End Users, and Vendors Service Engineers are systematically and regularly consulted.

Wellhead seals

Acceptance criteria

Selecting seals is an important aspect of wellhead design as a wellhead relies heavily on seals for its pressure integrity. The leakage rate acceptable should always be clearly stated to vendors to ensure they comply with the required standards. Failure to do this may result in vendors using their own acceptable leakage rates which may vary to suit their needs. For example 700 kPa (100 psi)/3 minutes is a common standard.

In the nuclear industry zero leakage is any leak rate below 0. cm3/second of helium at atmospheric pressure. NASA and the aerospace industry define their upper limits as 0. cm3/seconds of Nitrogen at kPa (300 psi) and ambient temperature.

For tubular premium connections to be acceptable, a limit of 0.001 cm3/second is normally set. This aims at avoiding significant annular pressures in a ten year completion. (The accuracy of the Helium detector normally used is 0. cm3/second).

Types of seals

When considering the seals to be selected for the wellhead(s) there are three main types of seals on the market. These are the:

·Metal to metal seals.

·Polymeric or resilient seals. Which are either elastomeric (natural or synthetic rubbers) or plastomeric e.g. Teflon.

·Metal encapsulated polymeric seals. Which are a combination of the first two types.

Static Metal to Metal seals require greater precision and attention to detail during installation but once satisfactorily tested they have a longer lifespan.

Polymeric seals are less predictable than metal seals as they often seal on installation but can fail soon afterwards.

The metal encapsulated polymeric seals are in certain cases an acceptable compromise. They are almost as forgiving as the elastomer seals and last longer, as the endless anti-extrusion devices minimise the contact with well bore fluids.

The recommendation is to use metal to metal seals; metal encapsulated polymer seals should only be used for pressures below 28,000 kPa ( psi). Pure elastomeric and/or plastomeric seals should be confined to running tools and testing tools.

Requirements for good sealing

To ensure the maximum performance from wellhead seals, metal or polymeric, static or dynamic, they will require:

·axial concentricity for gap uniformity

·endless and axisymmetric configuration for uniform stress distribution

·constant preload for longevity, within the elastic limits.

Lack of axisymmetry is a problem with "D" shaped seals and eccentric bolt holes through elastomers.

Other important seal characteristics to be considered are:

·material selection with regard to fluid compatibility

·surface finish of the seal interfaces, hence the need for protectors (wear bushings, seat protectors, etc.)

·extrusion resistance

·friction, which is particularly critical on dynamic seals

·explosive decompression, which cannot be overlooked on elastomers.

The USA military code MIL-R- can be used in the absence of an equivalent in the oil industry.

Seal behaviour

Workovers, steam injection and fire resistance technology have provided considerable experience of seal behaviour. As a result of this experience a preference for straight bore metal seals, also known as parallel bore seals, has developed. Straight bore metal seals are not affected by loss of preload as a result of thermal elongation of fasteners, loss of friction, or permanent setting due to vibration.

Plastomeric seals or metal encapsulated polymeric seals act on plastic deformation and can also deform the confining interface (usually the grooves). When this occurs the space to be sealed is enlarged thereby decreasing the pressure rating of the assembly and also the bolt fatigue life. For example flat washer-like seals are severely affected by the conditions described above.

Shallow tapered seals are being used successfully in the subsea environment: AX new style, CX, DX, FX, Grayloc, KX, NX, VX and VGX. In these seals, the separation forces are reduced as the seal circle is a minimum; closer to the parallel bore. The exception is CX, where to prevent key seating, the seal circle is larger.

To prevent buckling and cocking of the seal a centralising belt is necessary. This belt functions as the load flank (inner flank) of the API ring groove.

The open seal interface design has the advantage that it is easier to machine, inspect and weld inlay, thereby making it more cost effective.

Seal selection criteria

In the selection of seals the following aspects should be considered:

·The most important function of a seal is that it should only seal.

·The seal should only be exposed to fluids, pressures and temperatures and not to load transfer, separation forces, bending moments and shear forces; such forces should be taken by the geometry of the connection.

The following API gaskets are examples of bad seal design:

 ·R. Which causes clear flange stand-off

·RX and BX. Experience has revealed that these seals seldom achieve flange face to face contact.

These API gaskets transfer loads, align the mating members, provide shear resistance, are plastically deformed, and are often harder than the non-repairable confining groove; which will consequently be deformed. A typical example is groove deformation of the dual tree tops.

Zero flange stand-off has been proven impossible. Statements in vendor catalogues that they can achieve this should be examined closely and not automatically accepted.

Also with API seals the separation forces are higher as the seal circle is larger than the corresponding AX seal. A ratio of 5 to 3 is common, thus helping in overloading the bolting system. This is particularly critical in sour service applications where API fasteners, if they are not properly ventilated, have to be replaced by Inconel or B7 material. This reduces the rating of the connection as the yield strength of these materials is limited. See API Specification 6A, relevant ASTM Specification paragraph 903 and NACE MR-01-75, Edition 1 984.

The stacking of seals has been considered as a solution to overcome the weaknesses of existing seals. Unfortunately the disadvantage with stacks of seals is that the further they are from the landing level the more difficult it becomes to get a reliable seal.

It is recommended that to have the best axial alignment, the seal should be on the landing line level. CIW's polymeric seals on BRX casing hangers, and Gray's tubing hanger metal seals are typical examples.

Seal energisation

It must be possible for seals to be tested, and, as a consequence of this, they must also be re-energisable and/or retrievable. This is, however, not a feature that can be expected of integral hanger seals. The casing hangers can only be retrieved by splitting the casing, and the tubing hanger retrieved only after removing the entire tubing. Therefore it is recommended for all pack-offs to be retrievable without having to pull the confining strings. The present BRX seal and Gray's tubing hanger seal are, therefore, sub-optimal on practical grounds.

Re-energisation can be achieved through reload. Torque, weight, and radial energisation are the most common energising methods. Of these, radial energisation is the most precise method, but also the method in which machining tolerances are more critical. All other methods rely on excessive force and unpredictable friction.

A good seal removes the necessity for re-energisation. However, some seals need re-energisation, either through plastic injection or through tie-down screws, which results in undesirable penetrations in the pressure vessel.

The use of elastomer in seals has its limitations:

 ·Maximum pressure of to psi depending on containment

·Maximum temperature of 200°C (400°F) for fluor elastomers with the right carbon black and particle size, and 150°C (300°F) for nitriles

·Incompatibility with H2S, C02 and amines

·Explosive decompression

·Fatigue life

·Wear

·Friction

·Erratic energising behaviour. For example nitrile rubber behaves like a fluid under heavy pressure and as a solid under low temperatures. This has created many deformed casings which precluded access to the well bore.

Seal testing

Sound engineering practice dictate that it should be possible to test all seals from the correct direction. External testing of the upper seals checks these seals the wrong way around, as the test pressure in this case comes from below, while the actual well bore pressure comes from above. The reverse situation applies to the lower seal.

Also the auxiliary seals, which are used to facilitate the pressure testing of the assembly, should have the same integrity as the main metal to metal seals. This means that metal to metal seals should not have elastomers to test against.

Some pressure energised purpose-designed seals, such as elastomeric or metallic cup testers, suffer as they are undirectional. Although they are good at sealing pressures from the wellbore they do not seal from the well test port side. Therefore they are sometimes not considered for selection for the wrong reasons.

For spool type wellheads the situation is even more complex. There are:

. Primary Seals. A misnomer for the first/low pressure seal to be installed.

·Secondary Seals. A misnomer for Second, Critical or Crossover seals.

These have two pressure ratings: low pressure when tested from below and high pressure when tested from above. In this context it is not recommended to use Cooper Industries' X bushing, which floats and thereby transmits high pressure to the low pressure side of the assembly, either through leakage or hydraulically by floating. The concept behind this design was to have a spool which would accept a variety of casing sizes. This is seldom required in the international arena and it is irrelevant in Unitised Wellheads.

It is recommended to use fixed crossover seals; two for redundancy and test. These seals should be used on the smallest dimension possible (casing OD) to reduce casing forces and minimise seal interfaces. Therefore endless and axisymmetric seals are recommended.

The mechanical part of the assembly must be designed with tight tolerances in accordance with the practical rule of thumb:

 ·Gap (mm) x Pressure rating (kPa) = 13,000; or

·Gap (0.001") x Pressure rating (thousands psi) = 75

For example, for 100,000 kPa (15,000 psi) systems, 0.13 mm tolerances (0.005") should not be exceeded.

As a corollary each pressure rating requires a different geometry and/or different machining tolerances.

BOP connections

The main consideration is the selection of a matched strength connection, e.g. the properties of the connector should meet the capability of the casing assembly to which the BOP is to be attached. Most of the subsea connectors and modern multi-segmented clamps are good examples of this design philosophy.

Surface wellheads

BOP connections can be either clamped with two-piece clamps and hubs or flanged with raised faced flanges. Both of these design features have their advantages and disadvantages, however a major objective is to have a low profile wellhead.

Raised face flanges were used in older BOP connections and over the years these have evolved into R type connections with ring gasket and grooves. The grooves are shallow for R seals and deep for RX seals. The seal flank of the RX seal is identical to that of the R seal but the load flank is sometimes omitted. Some valve bonnet seals employ a similar design feature. See API Specification 16A. Lateral installation of API gaskets highlights the inconvenience of having no means for retaining them. The major suppliers have manufactured various types of connectors for surface wellheads.

Examples of these are:

 ·Cooper segmented clamps, Fast lock

·DrillQuip QuickLok

·FMC speedlock

·National Oilwell

·Vetco-Gray

·Ingram Cactus

Conventional two piece clamps have the following advantages:

For more Casing Spool Assemblyinformation, please contact us. We will provide professional answers.

Further reading:
How to Select the Perfect F5 Resilient Seated Gate Valve?
Understanding Conduit Gate Valves: Key Benefits Explained
10 Questions You Should Know about Stainless Steel Butterfly Valves

 ·The reduction in the time consuming and high risk operation of nippling up and down, during which time the protection offered by the tight pressure vessel is not provided.

 The nippling is best done by means of torque wrenches, as accidents can occur while using flogging spanners.

·They can act as better heat sinks. With API seal technology clamps without expandable washers have better fire resistance; acting as a better heat sink.

Conventional two piece clamps have the following disadvantages:

 ·A higher profile and therefore extra head room is needed.

·They are heavy and very difficult to energise. In particular for medium to high pressures (more than 5,000 psi) and medium to large sizes (more than 346 mm/135/8")

·Faulty castings and forgings can and have contributed to low and unacceptable performance.

·Stresses in clamps and hubs exceed those in flanges and bolts.

·The lack of proper alignment. This is a problem with AX style gaskets. For example while machining new heads two features are often faulty; the API ring groove and the API bolt holes, despite the generous tolerances. When bolt holes require repairing, threaded bushings are recommended over welding.

·Aligning bolts is difficult. Firefighters prefer flanges instead of clamps because they can align flanges easier by using bolts of different lengths. For the same reason conventional spools are also better than unitised wellheads, if not splittable. Similarly studded connections are preferred over flanges. This apparent conflict highlights the vulnerability of sealing within the plastic limits of the steel. Therefore in these applications it is recommended the use of elastic seals, such as AX, Grayloc, and similar.

·Heavy clamps are difficult to handle.

Subsea wellheads

In subsea wellhead BOPs multi-segment clamps and riser connections are used. BX style seals are excluded because either they are not vented or, if they are, venting of the ring gaskets is not reliable as the vent becomes plugged. Both situations create hydraulic lock on the groove.

The major suppliers have manufactured various types of connectors for wet applications.

Among these are:

 ·The Vetco H4. The H4 Multiple Load Shoulder features a slimmer profile which can withstand bending moments better due to a deeper swallow and is also easier to stab-in.

·Cameron's modified Collet connectors. Cameron uses the standard Hub with Single Load shoulder for its collet connector thereby providing a larger OD.

Male/female profiles are inconvenient as they prevent bi-directional installation. API double box profiles are a good alternative provided that the ring gasket belt acts as the matching double pin. The modified/recessed Grayloc has been used in such profiles.

In the design of marine hubs, male/female profiles must be incorporated, to allow the easy alignment of the mating members, thereby freeing the gasket from such a duty.

Selection criteria

The ideal connection should maintain the maximum equivalent pressure rating of the assembly, require little stud tensioning (to avoid over-torque), resist external loads (bending, shear, vibration, temperature expansion), allow easier seat rework and reusable seals.

For new orders state of the art connections should be considered because pure unmodified API connections do not satisfy all requirements. On existing connections API fasteners should be upgraded.

OTC/86 state that only 206,850 kPa (30,000 psi) flanges are correctly dimensioned. As face contact of the flanges is seldom achieved with normal preload the result is a reduction in the fatigue life. As flanges cannot be easily replaced they can be retrofitted with load monitored fasteners, stress mikes, and spherical seatings (OTC 85 ). Expandable washers can be used when temperature variations are a problem.

Face to face contact is vital for fatigue resistance, bending, shear and axial alignment. Ideally the bolt circle should be inside the contact area to have all fasteners working together. This also helps while the BOP is in the following state:

 ·Tension: during testing.

·In compression: by hanging off.

·In shear: during Slant drilling.

Housing bottom preparation

The options available for housing bottom preparation are threading, wedging, and swaging. The recommended option is threading in combination with matched strength connections; as the modern mills of today allow better outside diameter casing tolerances. ASME in recommended matched strength connections to maximise fatigue life of the connection between the wellhead and the casing. In this respect ASME also emphasises that a buttweld preparation can be 100% efficient and fully inspectable. Therefore the housing bottom preparation should be 100% efficient similar to that of a casing coupling.

Coupling-like connections and Buttweld/HotHed (pre heating and post weld heat treatment) are a viable alternative to slip-on welds or swaging and are very cost effective. However swaging should be seen as an emergency option as it requires considerable energy.

Slip-on welds, however popular, are not as good as butt-welding, because of the difficulty of structural inspection and welding; particularly with higher grade steels. The introduction of landing plates stimulated the transition to alternatives; no longer is the surface string in compression but in tension.

The slips on the slip lock heads are unique, because the bowl moves upwards, rather than the slips moving downwards.

In situations where the most cost effective solutions cannot be applied the alternatives, in order of preference, are: shaft/hub locking devices, cold swaging and radially energised slips (slip lock heads). The reasoning for selecting these alternatives is based upon maximum resistance to hoop stresses and minimal casing deformation.

Casing preparation

The casing must be prepared prior to installing a Casing head housing. The casing cutting required for this can be performed in a variety of ways, ranging from internal cutting, where accurate space out is difficult, to external cutting. This can be accomplished by:

 ·Cold cutting: sawing or jetting with abrasive fluids.

·On site machining.

·Flame cutting.

Cold cutting is preferred to prevent case hardening and iron carbide streaks. SPE 86 .

In some selected applications hydraulic or explosive cutting may be considered.

Casing suspension

Design requirements

Some of the principles and requirements for housing bottom preparations apply to casing connections, mandrel hangers/boll weevil, and slip and seal assemblies.

For safety reasons every related operation must be carried out through the BOP.

Mandrel type hanger

The preferred connection is a matched strength thread, normally box down, since this design is shorter, stiffer and offers better handling protection. Pin down, while not the first choice is also acceptable.

·The landing area is to take steel loads without yield.

·The seat angle is to provide a self cleaning profile without causing excessive hoop stresses on both housing and hanger.

·An anti-rotation device should be fitted to enable the release of the running tool, energising/retrieving the pack-off assembly, and eventual tie-back connections and wear bushing anchor points. This is particularly important on light strings.

·The hanger through bore should be in line with the casing drift for optimal strength.

·The seal interface must be fitted as close as practical to the landing level, in order to minimise axial eccentricity, essential for radial energisation of parallel bore seals.

·A circulation path with returns through the outlets bypassing the BOP is regarded as unsafe. The flow-by area should be in line with the clearance between the open hole and casing coupling in use, and should cater for large debris (25mm/1" minimum diameter).

·Casing movements such as reciprocation, off seat rotation, and/or vibration should be considered.

·The design must offer washing capabilities so that sealing profiles can be cleaned and, eventually, debris too large to pump out can be squeezed off.

·A lock down is mandatory to prevent thermal growth of the static seals and to make allowance for the use of Marine style casing patches. The lock down should be done, preferably, after testing of the seal assembly.

·A casing like upper neck is recommended to ensure the same top geometry, even with a stuck casing, to allow for the safest crossover seals. This is vital with spool type heads.

·The running preparation should be an external, normally left hand thread to facilitate release and tie-back. A simple crossover to the casing thread in use will complete the tool; provided the tensile strength is equivalent to the coupling in use. An elastomer ensures the seal between the crossover and hanger.

It should be possible to carry out all of operations described above with a minimum number of trips thereby saving expensive rig time.

Emergency Suspension Requirements

The emergency system should also be designed to the rules listed above; stressing the installation through BOP aspects as the cement is the only downhole annular seal. When a casing is not free to go to the intended depth the circulation is hindered and cement roping is likely.

For this reason the suspension and seal mechanism must be run through the rotary table and BOP. This can be difficult if a casing coupling or centraliser happens to be in the way. This is a typical platform problem as sometimes a double stand of casing is required to bridge the gap between the housing and the drilling floor. There are two solutions to this problem:

 ·The emergency suspension rides the coupling.

·The removal of the offending coupling. Either a "Pull 'n' Cut" tool (combining a spear on the bottom, a swivel in the middle, and a mechanical cutter on top) or a selective back-off tool.

Both mandrel hangers and emergency slips must be run through and tested under BOP protection.

Some operators split the BOP above the casing rams and below the casing coupling thereby creating a working window for a split slip and seal. This acts as a temporary seal to allow removal of the entire BOP and the installation of a proper seal sometimes assisted with on-site machining of the casing stub.

Slip segments can decentralise the casing as there is always one lazy segment which tilts the entire assembly. See the rotary slips where a hammer is often required to level them. Segmented slips are outdated and therefore not recommended. Similarly, experience with liner hangers and packers show that concentricity of the confining tubular members is seldom achieved.

Developments

The following endless slips are listed in order of preference:

 ·Cooper's Canh seal, which is based on Ring Fedder (shaft/hub locking devices), have been successfully used as an endless casing slip and seal assembly on casing patches.

·Helical slips.

·Single piece split slips and pocket slips.

·Lindsey pocket slips and Baker Service Tools (Brown/Edeco. Flexlock).

·Segmented slips.

Bottle necking of casing tubulars is the main drawback of segmented slips as they do not contribute in resisting hoop stresses. Also the casing is too flimsy to resist the energising load plus pressure load; often point load occurs due to the relative motion of each of the segments on its own.

New developments worth considering for emergency suspension metal to metal seal casing patch are:

 ·Metal to metal casing patch (MTMCP) are already available for downhole application but have not yet been applied to surface use.

·Cold forging or hydraulic swaging tools (camforge or hydraloc).

·Emergency back-off joints. A joint development of Shell Oil and DrillQuip.

·Selective casing back-off tools. A modern version of the field proven reversing tool, e.g. TRISTATE.

Internal geometry

Selection criteria

The preferred housing configuration should have:

 ·An access bore of nominal size in line with the BOP bore with the tolerance only one way. That is, the bore may be a larger diameter, but to ensure the drill bit fits, the bore may not be of smaller diameter.

·A sealing bore, a little smaller than the access bore, well protected throughout all operations by a bore protector, e.g. 473 mm (185/8")

·A through bore, even smaller, in line with the maximum required bit size; often in line with the drift of the attached casing. For example 447.675 mm (175/8") which is too small for a 508 mm (20") casing but ideal for a 473 mm (185/8") casing.

Seat angle and bearing area

The recommended design is a tapered profile with a 45° seat angle.

This is a good compromise that is supported by experience as the seat angle of 45° is also the shear angle of steel. This is the maximum angle allowed to avoid shear behaviour and also the minimum slope required to minimise the centralising effort. Almost all designs are like this. Only Cameron, Vetco and Regan, and their clones, occasionally deviate from this design.

The advantages of a tapered profile are:

·Reduced chances of shear

·Easier guidance

·Self cleaning

·It is ideal for mandrel type hangers

·Load carrying capacity.

 The disadvantages are:

 ·Induces hoop stresses

·More difficult to centralise

·Increases cost due to prolonged machining of the raw material

·Ballooning of the housing is possible

·Collapsing of the hanger is possible

·It is inconvenient for emergency suspension, which relies on wedging and friction. In this situation an endless bowl with an external 45° matching taper and a shallow internal taper is mandatory.

The bearing area or shoulder offered by the housing is defined as the minimum sealing bore minus the maximum through bore. The load capacity depends not only on the bearing area but also upon the following factors:

 ·The mechanical properties of the steel used and on the seat angle. This is a minimum of 60,000 psi and the most common is 75,000 psi; above this, sour service can impose limitations. With a square shoulder the shear strength is only 50 to 60% of the tensile yield strength.

·The friction coefficient. The desired friction coefficient cancels out the unfavourable machining imperfections therefore the friction factor should not be relied upon to upgrade design ratings.

The seat areas should be in line with the cross sectional area of the supporting system.

Shallow tapers vary between 15° (Varco DP slips) and 4° for self locking. The most common taper is around 8° e.g. CIW slips and spools which do not require a bowl, but make the items very long. Therefore the 45° seat angles are technically superior and cost effective.

In compact heads the subsequent hangers land:

 ·On top of the first hanger neck. An almost square shoulder is required to prevent hoop stresses of the neck interfering with the seal assembly.

·Inside the hanger. Nested construction preferred.

·On a dedicated profile for the tubing hanger which, if it is positive, can limit the pressure and load rating of the unitised head.

Hanger centralisation

The hanger matching landing profile must maximise the overlap with the housing bearing area. A 100% overlap is impossible but a minimum gap of 0.127 mm (0.005"), to prevent cold welding (galling), is acceptable. In addition, machining tolerances must be added to the gap because the housing OD tolerances are minus nil and plus something, while the hanger OD is plus nil and minus something. Therefore the gap can vary between a minimum of 0.127 mm (0.005") and a maximum of 0.38 mm (0.015"); assuming standard machining tolerances. The seal must be very adaptable to accept the above variation without being excessively derated.

Without proper centralisation the gap can be zero on one side and 0.762 mm (0.03") on the other side. Such a situation will make sealing extremely difficult and reduce the pressure rating.

Centralisation is essential. Centralising tools (centralisers, seal assemblies run together or long running tools) can help in minimising the inconvenience.

In addition to radial centralisation, axial alignment is also required. Length is therefore the most practical axial centralising criteria. It is for this reason that Vendors of some designs such as Vetco SG insist on running the seal assembly together with the hanger. The result is an improved design that increases rig time saving because fewer trips are required.

Outlets

Most Surface Wellheads are designed with too many outlets. There are sixty-six outlets on a standard design and each one is a potential leak path.

The preferred construction for cost effectiveness, fire resistance, and minimal bending moments on the wellhead, is the studded outlet. An acceptable connection but only for non-sour service is a buttweld preparation full penetration welded and X-rayed with the Valve Removal (VR) preparation in the main housing body.

Socket welded connections, which rely on a fillet weld, are structurally uninspectable and have been the cause of some stretched outlets. Therefore they are not recommended. Full penetration welding, without spigot removal, nor radiographic inspection and pipeline threaded outlets is also not recommended.

The types of outlets on the standard wellhead design are listed below:

 ·Tie down screws

·Access entries to the various annuli

·A, B, and C inspection ports

·Test ports

·Monitoring ports

·Plastic injection and return ports

·Control line passages

·Stud holes. Difficult to seal if they are too deep.

The requirement is to design a wellhead with the minimum number of outlets and to achieve this the following options should be considered:

 ·Annular outlets can be used as secondary kill/choke connections and as monitoring points. Therefore a spool type wellhead will require a pair of outlets per spool; nominally 50.8 mm (2"). The valve removal preparation (VR) will reduce the nominal size to the actual size of 31.75 mm (11/4").

·B, and C outlets, etc., can be utilised as monitoring ports and theoretically could be designed as small as 6.35 mm (1/4"). However, in practice, the minimum diameter of these ports is 25.4 mm (1") in order to avoid plugging. For well killing purposes 2" nominal is often specified. This configuration is possible because compact wellheads do not require a pair of outlets per spool, as the A annulus outlets are already permanently hooked-up, thereby saving rig time on nippling and testing.

In all of the options mentioned the valve removal preparation should have a metal to metal seal because the NPT threads are not hydrocarbon tight. However NPT-F, Autoclave, etc., are acceptable profiles. Threads should not be cut but forged or rolled. This has the advantage that the threading load is transferred through the tensile strength of the steel instead of through the weaker shear strength. Suppliers of this type are the Japanese company C. Itoh and LTV in the USA.

  The valve removal plugs should not be left permanently installed because then the valve gaskets are not tested. After removal of the valve removal plugs hollow thread protectors could be inserted.

The design should include room for both the valve removal lubricator and the installation tool. There are some very short modular lubricators in existence which have the rod divided in sections, like drilling stands made of three drill pipes, which do fit in tight corners. Diverter blocks, fitted inside the inner gate valve, can also be used.

·The A annulus is the annulus between the tubing and the production casing

·B annulus is the annulus between the production casing and intermediate casing

·C annulus is the annulus between the intermediate casing and the surface casing.

Hanger lock down

It is not recommended to use tie down screws on the housing to minimise pressure vessel penetrations. If tie down screws are used, the preferred design is where the seal separates the driving thread from the well bore fluids, which corrode the threads. Failure of the tie down screws will result in- undesired repairs with the tree and BOP removal.

Seizing of tie down screws can be avoided by transferring the female driving thread from the bulky housing to the gland. An additional advantage is that this method of construction reduces the machining costs for the housing and the system can be repaired/maintained externally.

The energising nose should be non-rotating in order to enhance the system through reduced friction. Each penetration should be treated like a valve bonnet which requires a metal seal on the interface between the housing and the gland (the bonnet seal) and also between the gland and the driving screw (stem back seat). This arrangement, although more expensive on a dated screw than an updated screw, can still be attractive because usually only one third of the updated screws are required. CIW, : 20 conventional tie down screws were replaced by only 6. On dated screws a 30° nose versus a conventional 45° nose can halve the requirement i.e. 10 instead of 20.

Running tools

A running tool requires a running preparation. Therefore consideration should be given to its retrieval, such as side track or eventual tie-back. To achieve this, some tolerance for misalignment is imperative. Which is why there is a preference for either external profiles or internal recesses in the housing instead of exposed threads that are prone to wear and damage.

For internal preparations the running tool can be:

 ·Cam actuated. Where the central body rotates and drives a cam ring which expands a split lock ring into the housing groove.

·Hydrodynamically actuated. This is not recommended as these tools make circulation impossible and a wet trip is not acceptable.

·Threaded/screwed. This is not recommended unless the retrieving/tie-back option has an alternative.

Therefore for the reasons stated above it is recommended that for internal preparations the preferred running tool should be cam actuated.

For external profiles riser connectors (dogs or segments) can be used. Usually the external profile is easier to machine and offers more support area due to a larger perimeter.

Running tools should have top and bottom connections to allow the addition of not only the running string but also of a stabbing stinger. This acts as a close fit centraliser to prevent damage to the mating profiles, as they may collide if not axially aligned. Non-stretched endless resilient seals are acceptable in running tools.

The recommended rotary connections are, in order of preference:

 ·van der Wissel (Wirth, Erkelenz) and/or EVl/Grant SST. Both of these are preferred for practical reasons as they are interchangeable with API connections.

·Hydril H90 and/or EVl/Grant High Torque as fatigue resistance is incorporated in the design.

·API NC. If none of the above are available. These can be improved by modifying the last engaged thread - LET, as suggested by SPE DE December .

It is not recommended that the older 65/8" Reg., 41/2" IF and 3 1/2" IF, etc., connections are used (listed here in order of preference) as their fatigue life is too short. Only one or two of these threads will work effectively if utilised and their radii of curvature is too small.

Orientation of dual completion tubing

The challenge in dual completions is the orientation of the tubing hangers to match the flowlines, control lines and the tree. The preference is for indirect orientation via the running tool, indexing by a 'poking' finger in the lowermost outlet of the BOP.

Direct orientation of the head may be achieved using round pins, parallel keys or triangular profiles. Round pins location holes are often drilled all the way through. Thus the pins may be removed but at the expense of having an extra leak path or penetration. To avoid these extra leak paths some pins, keys and triangular profiles are inserted from the inside.

There are two types of dual tubing hanger:

Split or 'D' shaped

Two 'D' shaped tubing hangers are used: one for each string. Special care should be taken to prevent cocking of the first hanger to be installed, as this will complicate the running and sealing of the second. Any alignment fixture must be positioned high enough over the landing shoulder to have sufficient leverage to counteract the eccentric load of the installed tubing.

In this case machining tolerances must be to an absolute minimum to minimise difficulties. In this context self aligning hanger slots, funnel like ending in a parallel slot or groove, fitting snugly around a parallel key is a preferred option. This will reduce contact stresses.

The idea of a 'D' shaped hanger is not only to run one string at a time but also facilitate the work over of the secondary (short) string. This type of hanger also calls for 'D' shaped seals which are difficult to set and are only effective if both hangers are in place. They are also called 5 minute seals, the primary is effectively a large disc with two holes, the secondary being the interface with the dual tree.

Solid hangers

The recommended hanger is the solid type dual hanger. In this case there is no particular preference for the orientation system. However, a solid hanger implies running the tubing in tandem with dual slips, elevators, tubing rams (slip type) and telescopic/swivel joints or hanger.

The main advantage is not only to allow the use of hydraulically set packers but also to minimise the risks of a leaking connection between the secondary (short) string first and the dual packer.

There are also round, asymmetric hangers that allow the running of the primary (long) string and also offer a bowl type hanger preparation for the secondary (short) string. This secondary hanger preparation can be round or oval (egg) shaped to allow the passage of side packet mandrels.

The preferred option is the round solid hanger run on the primary (long) string with the secondary (short) tubing hung off in a bowl type preparation.

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