Christmas tree design


This article describes the preferred approach to various aspects of Christmas tree design, with regard to pressures, types of well, equipment, experience, operability and safety. All wellhead valves and components should comply with the current edition of API Specification 6A.

Definition of a christmas tree

A Christmas tree is the cross-over between the wellhead casing and the flowline to the production process. It is defined as all the equipment from and including the wellhead connection through to and including the downstream flange of the choke.

A Christmas tree controls the wellhead pressure and the flow of hydrocarbon fluids and enables the well to be shut off in an emergency. It also provides access into the well for wirelining, coiled tubing and logging operations.

The tree must be designed to withstand all pressure levels such as gas lifting, gas injection, and the pressures arising due to a fracture or kill operation.

Types of trees

There are two 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. Experience in using solid trees has concluded that the side arm orientation should be reverse "Y". This configuration provides fluid cushioning and limits wall erosion, although it does make the hook up of flow lines difficult. A compromise is to use right angle outlets, which also makes internal inspection easier and is the preferred option. To further ease maintenance and replacement, the flow wing and kill wing outlets should be studded. The solid type tree is also used for dual completions.

Solid type fire resistant tree

Ultimately a so called fire resistant tree is not fire proof. In combination with its large size and difficult configuration this type has not been shown to be cost-effective.

Composite trees

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.

Operating philosophy

Before starting the design process it is recommended that an operating philosophy and a reference plan be produced.

Operating philosophy

The operating philosophy shouldconsider the needs of production operators, well services personnel and personnel involved in the asset management of the well.

The designer should be familiar with the current statutory requirements for the installation and before commencing any design work should ascertain the following information:

·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.

Reference plan

A reference plan is required to measure the true performance, availability, and OPEX of the well. This plan should indicate the major events over the lifespan of the well. This will ensure that the customer's requirements are followed and maintenance has minimum negative impact on the well(s) production capability.

Operating envelope

The Operating Envelope is a list containing information describing the well, and giving the parameters of various properties. This information should be gathered before design on the Christmas tree commences. The information in the envelope should cover the total lifespan of the well and include fluid properties, surface pressures, temperatures, flow rates, solid and gas content, etc.


An important consideration in designing surface equipment is repressurisation after a shutdown, a SCSSSV leak-off test, and tree maintenance. It is essential that the repressurisation facilities of the well are adequate and the method for achieving this must be documented at the beginning of the design phase. The proposed method should also be communicated to the facilities designers for consideration. There are various methods and each is dependent on the circumstances and the design of the well.

Chemical injection

For environmental, OPEX and logistical reasons chemical injection should be avoided. Therefore passive corrosion protection is preferred over active corrosion protection.

To achieve this, materials can be selected that can eliminate the need for corrosion inhibitor injection, although this is likely to increase CAPEX.

However there are situations, such as hydrate prevention that demand the injection of a chemical such as methanol and/or glycol. In this situation the general guide for all chemical injection should be followed.

Injection lines should be designed in compliance with the general safety principles. 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.


For well monitoring purposes it is necessary to take samples regularly at the wellhead. The design of sampling points should follow good oilfield practice. The point at which the sample is taken should be at the lowest pressure possible. It is not policy to provide sampling points 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.


To maximise production it is essential to monitor the wellhead pressure and temperature. The preferred approach is to install an instrument flange, with ports for the sensors, between the 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.

It is not recommended to take pressure readings from the tree cap. To do this would mean that the Swab valve would have to be open. Failure of the tree cap seal would result in a safety hazard and possible environmental pollution. The Swab valve should normally only be open during wireline operations. Should a hot CITHP be required after a regular well test, this is considered to be a planned event, and therefore the pressure can be taken from the tree cap with the Swab valve open as part of the well test procedure. After the HCITHP is taken the Swab valve should be closed.

Kill philosophy

In production systems the policy is to regard well killing operations as a planned event. Although kill facilities should be available, for logistical and economic factors, it is not policy to have permanent hooked up kill systems to producing wells.

Before the design of a well is started the routine (planned) kill philosophy during all stages of the well(s) lifespan must be determined. This philosophy will determine if a kill valve or even a kill connection is needed. For example the kill philosophy will dictate a tubing or casing kill and appropriate connections should be made for this.

Safety criteria

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.

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.

Valve sequencing

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 SCSSSV, SSV and choke must be defined as it will have an influence on the control systems of the tree. References should be made to the Production Operations Philosophy, which contains the departmental standard on valve sequencing.

Typical examples of the sequential valve operations in an integrated production system are:

 ·Emergency Shutdown [ESD]

 1.Choke closes under automatic actuation

2.Flow wing (or injection wing) valve closes

3.Upper master gate valve closes

4.SCSSSV closes.

·Operational Shutdown (Unit Shutdown) [OSD/USD]

 1.Choke closes under automatic actuation

2.Flow wing (or injection wing) valve closes

 ·Planned Shutdown

 1.Choke is closed under automatic actuation, by the operator

2.Flow wing (or injection wing) valve closes

3.Upper master gate valve closes

4.SCSSSV closes (depending on the work to be done).

Closing the choke first has the advantage of stopping the flow across the other valves before they are closed. In remote locations or non-critical low pressure/producing wells this sequence may be different due to the reduced number of valves. However the principle of closing an actuated choke before any other valve should be followed.

In wells with a positive (fixed bean) choke the SSV has to close against the flow, thereby taking the place of the choke in the sequence. In this situation the SSV should have the capacity to survive repeated closures with the well flowing.

It should be noted that where the choke is remote from the wellhead, the section of flowline between it and the Christmas tree should be pressure rated.

Christmas tree selection

Design Parameters

When selecting a wellhead system, the first action should be to produce a description of the parameters of the envisaged process, or the operating envelope. This description will be the basis for the design and selection of equipment for a potential or existing application.

When considering corrosion, attention should be given to the properties of the well fluids, drilling fluids, brine, etc. that come into contact with the equipment.

The data from exploration testing and sampling should be considered as a range of values. Each of these will vary over time between a given minimum and maximum. Depending on the effect that a particular property can have on well equipment, its maximum value, during the lifespan of the well, should be taken as a design parameter.

All aspects of the process in developing a specification of a Christmas tree should be documented: its basic functions, operational requirements, etc.

The type of well should then be classified. For example the design of a tree that will be used for a well producing low pressure water will be different from that of a tree used for a high pressure gas well. To assist in the selection process, wells have been categorised in terms of production rate, pressure rating and gas oil ratio (GOR). These categories are:


Over 1000 bbls/d.

Over 2000 GOR (scuft/bbl)

Over 600 lb rating. (max. working pressure 1440 psi).


500 to 1000 bbls/d.

Under 2000 GOR (scuft/bbl)

Under 600 lb rating (m.w.p. 1440 psi).


Under 500 bbls/d.

Very low GOR (scuft/bbl)

Very low pressures.

Consideration should also be given to the potential changes in a well during its productive life to ensure these do not have an impact on the classification of the well. For example changes in GOR, BS&W, gas lift requirement, reservoir pressure, etc., as well as the material specification, type of service C0 2, H 2S, etc.

Wellhead/christmas tree interface

Christmas tree bottom connection

The preferred approach is to use the compact wellhead design. This provides greater safety during drilling and completion phases as well as providing adequate access to the annulus. It also reduces the overall height of the surface equipment.

The bottom 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 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.

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. Experience has demonstrated that these threads may become corroded or eroded by well fluids. Damage has also been caused by wireline wire passing across the apex of the threads. The same criteria apply for dual completions.

Control lines

The tubing hanger also houses the termination or passage of the control line for the SCSSSV and any other devices fitted downhole. The control line should be a continuous path from the valve nipple to the surface. The wellhead body, however, should not incorporate a fluid path for the SCSSSV control line or other downhole devices. Older designs have had a chamber or path for the hydraulic fluid as part of the wellhead, which provided an easier way of terminating the control line, but increased the number of seals to be installed and tested. When, with the older design, problems were encountered with the downhole device it was possible to exceed the overall pressure rating of the wellhead assembly. For example: it was possible to have a SCSSSV hydraulic pressure of 6000 psi in a 5000 psi rated wellhead. With the pressure path of the control line independent and continuous from the valve nipple to the Christmas tree/Wellhead exit point, this potential problem is avoided.

Casing outlets

The interconnection between wellhead and casing outlet must provide two barriers between fluid flow and environment, and each intermediate annulus should have two outlets on the surface. During the venture life of the well the annuli provide access to each of the casings for:

 ·Pressure monitoring

·Bleed off

·Passage of gas lift gas. ("A" Annulus usually)

·Well kill, via the "A" Annulus.

The outlets for each of the annuli are normally oriented at 180° to each other. The orientation for each of the casing outlets should be the same. This means that the outlets for the ""A", "B"" and "C" annuli should be in line with each other. The "A annulus, production tubing to casing annulus, should be uppermost, the "B" next lowest with subsequent casing outlets below that.

If there is a height constraint, the casing access points may be staggered around the casing head. If possible this should be avoided as it leads to a more complicated casing tie in arrangement, thereby creating access problems and potential safety hazards.

All annuli should have pressure monitoring facilities and sample/bleed off points. Sample/bleed points should be designed in accordance with good sampling practise, with earthing points, drains, etc. Configuration of the tree should be as follows:

 ·"A" Annulus: In the event of a tubing or packer leak the "A" annulus is likely to come under full reservoir pressure. As such it is the most important annulus and should be treated separately from the "B" and "C" annuli. The "A" Annulus should have two flanged gate valves, with the same pressure rating as the tree on each outlet. 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.

Gate valves

All tree valves are normally gate valves of identical design. The actuated valves on a tree differ in their mode of operation from the non-actuated valves in that they are reverse acting. This means that the valve is closed when the gate is in the fully "out" position. All the valves fitted to the tree and "A" annulus should be capable of withstanding the same pressure as the tree.

Specification guidelines for tree valves

The valve configuration of a Christmas tree should conform to the wellhead safety principle of always providing an ultimate safety barrier. Group policy gives preference to complying with international standards such as ISO, and API, etc., over the national standards such as B.S, DIN, etc. In some operating environments it is even necessary to exceed existing standards.

Recommended features of tree valves

Due to safety considerations it is not recommended to have valves or pipe connections with screwed fittings. Therefore all tree valves should preferably have forged bodies and flanges with a minimum number of penetrations. The recommended design is the true floating single slab, double seat arrangement and non-rising stems, with a (preferably selective) backseating capability. Ideally the stem packing should be metal to metal. However, in some cases elastomeric seals could be allowed.

Wire cutting valve

Sometimes, in an emergency during wireline operations, it may become necessary to cut the wire. In such a situation it is essential that this can be done quickly and efficiently and may be achieved by installing a wire cutting valve in the tree. If installed, this valve should be fitted in the upper master gate position.

The difference between wire cutting valves and non-wire cutting valves is in the design of the slab, and the power of the actuator. With a wire cutting valve it should be possible to cut the largest size of braided wire used (7/32" repeatedly without causing damage to the gates or seats. In some applications a booster, or add-on actuator is used to transform a nominal actuator into a wire cutting one.

Coiled tubing cutting valve

Occasionally during coiled tubing operations it will be necessary to shear the coiled tubing. A coiled tubing BOP has this capability, therefore the installation of a separate coiled tubing cutting valve in the tree is not necessary.

Tree valve actuation

Valves are opened or closed either by hand or actuators. Actuated valves can be triggered automatically or manually. However whether the tree has two actuated valves (UMG and FWV) or a single SSV, they must close immediately when triggered.

Automatic hydraulic actuation is the most common system used. An alternative to hydraulic actuation may be used if it does not compromise the other design parameters.

Automatic actuator design

There are several factors which affect the design of actuators. These are as follows and generally conform to API specification 6A:

·Actuator fluid volume and overall dimensions should be minimised to reduce size and response times.

·For maintenance and replacement, size and weight should be minimised but should not compromise the pressure integrity of the tree.

·All actuators must have a fail-safe action.

·Actuators should not interfere with the back seating capability of the valve.

·In an emergency the tree valves should close in the quickest possible time. The normally accepted time is 10-20 seconds; including the cutting of wire. Factors to consider are the effects of other wells closing simultaneously, system capacities, hydraulic line lengths and diameters. In multi-well systems the hydraulic fluid is bled back to the fluid storage tank, which may create a "bottle neck" in the unit and increase well closure times.

·During wireline operations normal control of the well is transferred to the wireline operator. In an emergency it must be possible for the operator to shut in the well.

·Wireline control of the well is traditionally done by disconnecting the fixed hydraulic line to the actuator and connecting a flexible hydraulic hose. The hydraulic flexible line may be approximately 200 feet long and 1/2" in diameter. When this is done it must be demonstrated by calculation or otherwise, that the actuator closure time is not affected.

·In a wire cutting application the actuator should have enough force to cut the largest size of braided wire (7/32") in use, independent of well pressure.

Although manual tree valves should not have rising stems, some designs of actuator have a central shaft which protrudes from the actuator body when the valve is closed. Care should be taken to ensure "pinch" points are not created between these shafts and any other equipment structure. If this is unavoidable, then stem protectors/shrouds should be used.

Manual actuation of tree valves

Manual valves should not be hydraulically or pneumatically triggered, or have a gearbox. These devices isolate the operator from the "feel" of the valve during its travel and therefore do not provide direct control. If an unnoticed fault develops they may give a false indication of the position of the valve. An operator should be in physical contact with the valve; counting turns to ensure the valve is fully open or fully closed. Experience has also shown manual gearboxes on valves to be maintenance intensive.

Production chokes

Adjustable chokes

As stated earlier, a tree has several important functions, one of which is flow control of the produced fluids. On integrated platforms and modern processing plants flow control from the well is provided using adjustable chokes. These devices have been in operation for many years and are used by numerous cpmpanies.

Adjustable chokes are designed to withstand very high pressure drops and vary the fluid/gas flow at the same time. Control of the chokes may be by simple on/off local manual panels, or sophisticated distributed control systems.

For many years these devices have been used to apportion well flow. The well should be tested frequently and the choke opening (number of steps taken by the actuator, or percentage of choke opening) calibrated against measured well flow. Provided the calibration is carried out frequently and is repeatable this approach is supported. However, it should not be used for fiscal or custody transfer measurement.

The high pressure drops which are normally associated with chokes often cause severe turbulence and eventual erosion in the downstream pipework. This problem should be considered in the design phase. An acceptable solution is to install hardened pup pieces directly downstream of the choke, or target tees instead of flowline bends.

Chokes must always be fitted in accordance with the manufacturers instructions and never be inverted. Flow reversal may cause premature catastrophic failure of the choke internals.

There are several types of chokes available, the main types being:

 ·Control valve types, with trims and plugs similar to process control valves, but designed for high pressure drops

·Variable orifice chokes, normally a needle valve configuration

·Multiple orifice chokes, normally two rotating discs with one or more holes in each disc.

When considering the selection of chokes, the following factors should be considered:

 ·Very high pressure drops

·Erosion of downstream pipework

·The effect of high pressure differentials on start up

·The degree of required choke control

·Valve sequencing and shutdown philosophy

·Maintainability, access for the removal of internals, etc.

·Vibration levels to be expected as a result of the pressure drop

·Acoustic levels during the high pressure drop production phases.

There should be a device to ensure pressure is bled off from the choke internals prior to any maintenance operation.

For more information on the selection of tree chokes see Section 8 to this document.

Positive chokes

Positive chokes are mainly used in remote, non-critical areas, in low pressure applications and where the choke may be some considerable distance from the tree. Once the fixed bean or orifice is fitted, the flow rate from the well cannot be changed. To vary the flow rate a different sized bean must be fitted. This normally entails breaking open the pressure envelope, which should only be done by trained personnel who are aware of the consequences of mis-aligned seals or badly fitted chokes.

As replacing a large bean in a vertically installed choke is a difficult operation, this should be considered during the design phase if this is not to become a serious operating problem. Fixed bean devices should always be installed in accordance with the manufacturer's instructions. They must never be reversed.

Lubricator connection

Single completions

With a flanged tree-to-cap connection (composite trees) and studded connection (solid block trees), due regard should be taken of advice given in the previous article. 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.

Dual completions

With this configuration the tree connections (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


#3 Andy Whitehead 2017-06-13 08:23
Not sure who wrote this, it's good but has a few inaccuracies.
#2 Sajit Viswan 2016-08-09 19:15
Useful info. Thank you.
#1 ali sarmiento 2015-12-08 18:38
thank you this is very helpful