The Christmas tree is the cross-over between the wellhead casing and the flowline. The wellhead is the cross-over between the Christmas tree and the various casings.
- controls the wellhead pressure and the flow of hydrocarbon
- enables the well to be shut off in an emergency
- provides access into the well for well intervention activities.
Wellhead/christmas tree interface
The selection of the wellhead is normally by the Drilling Engineer in conjunction with the well structure design.
Both drilling and production requirements need to be addressed in the wellhead design, as it provides the crossover between the BOP and the various casings during the drilling phase of the well life cycle and as mentioned above controls the wellhead pressure and hydrocarbon flow during the production phase. The design should be in accordance with API specification 6A.
There are basically two types of wellhead, the individual spool type and 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.
Christmas tree bottom connection
The Christmas tree connection to the wellhead or the tubing head spool should be rated to the maximum closed-in wellhead pressure. The connection should be designed to accept the shear loads, the loads imposed during wireline, coiled tubing and snubbing operations, such as bending moments of the lubricator, vibration, etc. It must be demonstrated by calculation that the tree/wellhead connection is adequate to meet these demands during its working life.
A suitable connection between Christmas tree and wellhead is the multi-segmented clamp. This device is quicker and safer to install than the more traditional flange and allows the drilling function to line up the Christmas tree accurately with the flowline. In principle it is recommended that dual seals are used, generally this is accomplished by way of extended neck tubing hangers.
During wellhead maintenance and other operations a back pressure valve is normally installed in the tubing hanger. To accommodate this, a profile should be machined into the tubing hanger to receive the valve and/or running tool. This should preferably be a wireline profile, which allows setting and retrieving the back pressure valve to be performed under lubricator control.
It is recommended not to use threaded profiles. They may become corroded or eroded by well fluids and wireline passing across.
The tubing hanger must withstand the forces exerted during well completion, such as setting the well conduit in tension or compression, and subsequent forces during well production, well stimulation etc.
The tubing hanger also houses the termination or passage of the control line for the SCSSV and any other devices fitted downhole. The line should be a continuous path from the valve nipple to the surface. The wellhead body should not incorporate a fluid path for any control line (SCSSV or other downhole devices).
The wellhead design will incorporate a minimum number of outlets, including testing ports, tie down screws etc. Each annulus should have two outlets oriented at 180° to each other. The orientation of each annulus outlet should be the same, with the "A" annulus (production tubing to casing annulus) uppermost. The "B" should be the next lowest with subsequent casing outlets in line below each other.
During the producing phase of the well life cycle the annuli ports provide access to each casing for: pressure monitoring; pressure bleed off; fluid levels and samples; passage of fluids for artificial lift gas lift/hydraulic lift) usually only A annulus; passage of fluids for well killing/circulation; injection of corrosion inhibitors; access for pressuring the annulus to operate downhole tools such as SCSSVs.
- "A" annulus should have two flanged gate valves, with the same pressure rating as the tree on each outlet (in some instances, a single gate valve and a comparison flange is installed). The outlet used for sampling or gas lift should have a profile to insert a back pressure valve. The other side may be terminated with a flange, needle valve, and pressure gauge.
- "B" annulus: One outlet should have a single gate valve with a sampling/bleed down arrangement. The other side may be terminated with a flange, needle valve and pressure gauge.
- "C" annulus: One outlet should have a single gate valve with a sampling/bleed down arrangement. The other side may be terminated with a flange, needle valve and pressure gauge.
When there are more than three annuli on the wellhead these should be treated in the same way as the "C" annulus.
In general the "A" annulus ports are specified 2" nominal for well killing and gas injection purposes. The minimum diameter ports for the "B" and "C" annulus should be 1" nominal to avoid plugging. The specification of port sizes should take into consideration the life cycle requirements such as artificial lift requirements but also corrosion monitoring and remedial work requirements.
Christmas tree types
Subsea trees need to be designed to allow ease of tie-in to the tubing spool/wellhead, umbilical connections (hydraulic/electric), etc. and connection of tie-backs, flowlines, etc. in underwater conditions. The control and safety valves need to be operated via the umbilical lines.
Surface trees on the other hand are "simpler" in design since there is no need for running/guide bases, tie-in of umbilicals, etc.
There are two basic types of tree: solid, and composite. Solid trees are machined from single blocks of material. Composite trees consist of standard valves bolted together about a central body.
Solid type tree
The advantages of using trees constructed from a single block of material is the reduction in potential leak paths, and their higher pressure rating. It is also used for dual completions.
This type of tree should only be used for low pressure and low risk applications. Selection should ensure that the valves used have been designed for this type of application, and that gaskets do not project into the core of the tree and thereby obstruct the flow and wireline tool strings. All other features should apply equally to both types of tree.
Dual completions are widely used, although problems in optimised gas lifting of both strings tend to favour single completions where gas lifting will be employed.
This allows two wells to be drilled, cased and completed from a single wellbore. Each well is independent, permitting concurrent operations
- ·regulations governing the provision of one or two master valves;
- ·statutory requirements on the maintenance of the tree and other related pressure equipment;
- ·required maintenance frequency: what, where, when, and how.
The limits of the available space for the wellhead equipment should be defined at the initial stages of a project, not before detailed design commences.
An important consideration in designing surface equipment is repressurisation after a shutdown, a SCSSV leak-off test, and tree maintenance. For example, in the case of the well being shut in and depressurised with full pressure below the closed SCSSV, there has to be some means of equalising the pressure across the sub-surface valve before it can be opened.
There are several scenarios possible for the repressurisation of a Christmas tree:
- Using the equalisation feature of the sub-surface valve (if fitted).
- Repressurisation of the string above the SCSSV from another well via the Production Manifold (or the Kill Manifold, bearing in mind the directions on kill systems and the kill philosophy, as discussed in Section 3.1.3).
- Pumping into the string above the SCSSV a fluid which is compatible with the produced hydrocarbons (e.g. diesel) and pressurising this fluid until the flapper opens.
- Using a supply of inert gas at sufficient pressure for same.
- Using a combination of the methods described under b. and d.; if the other well cannot supply sufficient pressure this deficiency can be made up by an additional supply of inert gas.
Inter-well connection features
- ·Minimum line diameter of 2" (50 mm).
- ·For low pressure, normal temperature (non-gas) applications, any quick connecting rigid piped system or flexible hoses are acceptable.
- ·For high pressure, high/low temperature gas and H2S applications any suitable metal-to-metal seal system may be used.
- ·In all cases where jointed or flexible hoses are used there should be a documented and auditable means of determining whether the system is certified for use, i.e. pressure test certificates or insuring authority approval for use.
- ·In all cases where either jointed rigid line or flexible hoses are used suitable anchoring devices should be used to restrain the line in the event of a failure. This is a mandatory safety requirement.
Injection lines should be designed in compliance with the general safety principles where required. Chemicals should be injected into the main body of the tree where the fluid flow is most turbulent and injection points should be large enough to withstand shear forces. The diameter of the injection line should be as large as possible and the connection to the tree flanged. For example 21/16" (50 mm) diameter is adequate to withstand most shear loads and vibration. Ring joint flanges can be used but cognisance should be taken of the comments on BX joints.
No sampling points should be provided on the body of the tree. When a sample has to be taken close to the Christmas tree the sample point should be downstream of the choke, at the lowest pressure and at a point of high turbulence, to ensure that a representative sample is obtained.
The preferred approach for obtaining wellhead pressures is to install an instrument flange, with ports for the sensors, between the Flowline Wing Valve (FWV) and the choke. The flange can also be used for chemical injection. The flow measurement is normally taken on a straight section of the flowline.
Christmas trees and ancillaries must be designed to meet the minimum safety criteria and the installation should be suitable for its intended purpose. The design should comply with internationally recognised standards such as API 6A, ISO 9000, ISO 10423.
Well control intervention operations need to be a consideration during the well and facility design.
The safety logic of the process or platform installation should be taken into account during the design. For example, does the plant have emergency shut-down (ESD) and operational shut-down (OSD) systems? If so, what is the operating philosophy during these types of shut-downs? What effect will this have on the design of the tree?
All trees should have a (lower) master gate valve (LMG). This is the ultimate safety barrier and is one of the most important safety devices on the tree. In all wells the principle of operating a valve "one away" from the LMG must be incorporated in the design. The LMG should only be closed in an emergency situation.
When positioning casing outlets, valves, instruments, etc. consideration should be given to the space restrictions for normal operation and maintenance of the equipment. See ASTMS F-1166-88 (Recommended Installation of Valves) or similar.
Closure of the actuated valves on a Christmas tree is normally automatically sequenced through a dedicated well shutdown system. Before the design of a well is undertaken, the sequencing of the SCSSV, SSV and choke must be defined as it will have an influence on the control systems of the tree.
Typical examples of the sequential valve operations in an integrated production system are:
·Emergency Shutdown [ESD]
- Choke closes under automatic actuation
- Flow wing (or injection wing) valve closes (SSV)
- Upper master gate valve closes (SSV)
- SCSSV closes.
·Operational Shutdown (Unit Shutdown) [OSD/USD]
- Choke closes under automatic actuation
- Flow wing (or injection wing) valve closes (SSV)
- Choke is closed under automatic actuation, by the operator
- Flow wing (or injection wing) valve closes
- Upper master gate valve closes
- SCSSV closes (depending on the work to be done).
Lubricators are tubulars temporary fitted into the Xmas tree to enable well intervention activities on a well under pressure.
a. Single completions
With a flanged tree-to-cap connection (composite trees) and studded connection (solid block trees), due regard should be taken to seal selection. For similar reasons to the Christmas tree bottom connection, this uppermost connection or joint should be strong enough to withstand all the forces that will be imposed on it.
b. Dual completions
With this configuration the tree connection (each flange for each string) can be 'D' shaped. These are acceptable for low pressure, sweet applications. Their disadvantage is the uneven loading on the bolts of the 'D' shaped flanges. This type of connection should not be used in sour service.
An acceptable alternative for sour service is the figure of eight or oval shaped one piece connection that covers both top outlets. The bolts are more evenly tensioned and the flange less susceptible to differential movement.
The seal most predominantly used for lubricators is an 'O' seal, with the load being taken by an ACME thread. Provided the 'O' seal is regularly replaced, and pressure tested prior to well entry, this type of joint is wholly adequate.
In very high pressure applications, metal-to-metal seals have been used and are becoming more widespread. However, a change from 'O' seals to metal-to-metal seals will mean a change of lubricators and this should be carefully considered against the advantages of this state-of-the-art seal.
Wellhead/Christmas tree seals
Selecting seals is an important aspect of wellhead design as a wellhead relies heavily on seals for its pressure integrity. 700 kPa (100 psi)/3 minutes is a common standard for leakage rate.
For tubular premium connections a limit of 0.001 cm3/second is normally accepted
Types of seals
Tt is recommended to use metal-to-metal seals; metal encapsulated polymer seals should only be used for pressures below 28,000 kPa (4000 psi). Pure elastomeric and/or plastomeric seals should be confined to wellhead/Xmas tree running tools and testing tools.
Xmas tree parameters
BOP/Christmas tree 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 connection is to be made. Most of the subsea connectors and modern multi-segmented clamps are good examples of this design philosophy.
BOP/Christmas tree connections can be either clamped with two-piece clamps and hubs or flanged with raised face 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 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. The major suppliers have manufactured various types of connectors for surface wellheads.
Conventional two piece clamps have the following advantages:
- ·The reduction in time of the high risk operation of nippling up and down, during which time the protection offered by the pressure tight 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 34,474 kPa/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. See DEN 65189.
- 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 unitized 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 to use of elastic seals, such as AX, Grayloc, and similar.
- Heavy clamps are difficult to handle.
In subsea applications 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.
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 have reusable seals
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.
Subsea "spool" tree
The "spool" tree system does not currently fulfil the necessary two barrier reservoir isolation criteria under all conditions. This stems primarily from the barriers available during operations necessary to install or remove the wireline plugs in the tubing hanger/tree. With the current design there is heavy reliance on the shear rams of the Drilling BOP to provide not only the disconnect facility, but in some instances, the only barrier between the reservoir and the environment.
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.
The mechanical part of the assembly must be designed with tight tolerances in accordance with the practical rule of thumb:
- Gap (mm) ´ Pressure rating (kPa) = 13,000; or
- Gap (0.001") ´ 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.