NOTES PAGE
NOTES PAGE
Figure 8.24 -Example Composite Xmas Tree
Kill Wing Valve
The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure equalisation across tree valves e.g. during wireline operations or prior to the removal/opening of a sub-surface safety valve. This valve is usually manually operated.
Swab Valve
The Swab Valve permits vertical entry into the well for wireline (e.g. running BHP/BHT gauges, tubing conditioning) or for well interventions such as coiled tubing operations and logging. This valve is operated manually.
Xmas Tree Cap
The Xmas Tree Cap provides the appropriate connection for well control equipment when conducting well interventions and is installed directly above the swab valve.
The Xmas Tree cap normally includes a quick union type connection and should be strong enough to support the well control equipment. The bore of the cap flange should be compatible with the tree and permit the running of service tools. Sometimes the cap is removed and replaced by tertiary well control equipment. (e.g. Shear Seal)
Figure 8.23 - Typical Surface Xmas Tree
As already described, a Xmas Tree is an assembly of valves and fittings used to control the flow of tubing fluids at surface, provide access to the production tubing and on some subsea completions to provide access to the annulus string. In general, a Xmas Tree is essentially a manifold of valves, installed as a unit on top of a tubing head or subsea wellhead.
The range of trees available is wide, and are not all addressed in this manual. However the valve layout of surface Xmas trees is similar throughout and typically contains the following valves and features:
Lower Master Valve (LMV)
The Lower Master Valve is utilised on all Xmas trees to shut in a well. This valve is usually operated manually. As its name implies, the master is the most important valve on the Xmas tree. When closed, this valve should keep the well pressure under full control and therefore should be in optimum condition - it should never be used as a working valve.
In moderate to high-pressure wells, Xmas trees are often furnished with a valve actuator system for automatic or remote controlled operation (i.e. surface safety valve system). This is often a regulatory requirement in sour gas or high-pressure wells.
Upper Master Valve (UMV)
The Upper Master Valve is used on moderate to high pressure wells as a emergency shut-in system where the valve should be capable of cutting at least7/32“ braided wireline. This valve can be actuated pneumatically or hydraulically. The UMV valve is a surface safety valve and is normally connected to an emergency shut-down (ESD) system.
Flow Wing Valve (FWV)
The Flow Wing Valve permits the passage of well fluids to the choke valve. This valve can be operated manually or automatically (pneumatic or hydraulic) depending on whether a surface safety system is to be included in the production wing design.
Choke Valve
The Choke Valve is used to restrict, control or regulate the flow of hydrocarbons to the production facilities. This valve is operated manually or automatically and may be of the fixed (positive) or adjustable type. It is the only valve on the Xmas tree that is used to control flow. It is sometimes located downstream at the production manifold.
NOTE: All other valves used on Xmas trees are invariably of the gate valve type providing full bore access to the well. These valves must be operated in the fully open or closed position.
Figure 8.22 - Typical Compact Wellhead
8.11.1 Tubing Heads
At the drilling stage, casing is run and cemented in a well to line the well to protect against collapse of the borehole, to prevent unwanted leakage into or from rock formations and to provide a concentric bore for future operations. Various strings of casing are run, i.e. conductor, surface string (which provides a base for the wellhead) followed by one or more intermediate strings depending on the target depth and expected conditions in the well. At the completion stage, production tubing is run to act as a flowline between the formation and surface. Unlike casing, production tubing is not cemented in the hole so the entire tubing weight must be supported by a suspension system suitably installed in a tubing head. The tubing head is positioned on top of the uppermost casing head of a well and is used to suspend the production tubing and to produce an effective seal between tubing and casing.
Tubing heads are composed of a body, a hanger-sealing device (tubing hanger), and a mechanism that retains the hanger. Figure 8.22 shows a typical modern compact wellhead.
The wellhead equipment installed on top of the tubing head serves to control and directs the flow of well fluids from the production tubing string. Surface equipment may range from a simple flow cross with stuffing box to an elaborate Xmas tree. Choice of surface tree depends on well fluid production method (natural flow or artificial) and the wellhead pressure encountered. In general, most surface trees are comprised of at least one master valve, at least two wing or flow valves (one of which may be hydraulically operated), and one swab valve utilised in wireline operations.
(Refer to Figure 8.23).
Wellhead equipment (spools, valves, chokes) are either screwed, flanged or a combination of both. Wellheads with screwed connections are used for pressures not exceeding 1,000psi. (69 bar); those with screwed valves and chokes not exceeding 5,000psi. (345bar). However, most operators specify flanged connections, even for low pressure wellheads since they are less susceptible to leakage, easier orientated and, especially in the larger sizes, easier manipulated.
NOTE: API test pressures for all wellhead, including pressure control equipment and downhole equipment, is twice the rated working pressure for equipment up to 5,000psi and 11/2times working pressure for 5,000psi and above.
With regard to subsea wellheads, there is no API standard and manufacturers all have their own specific design that includes some means of orientation in order to align the subsea tree inlets and outlets to the flowlines or indeed in a subsea manifold system.
Multiple Tubing Heads/Hangers
The purpose of a multiple completion is to produce reservoirs simultaneously without any pressure or reservoir fluid combining during the transfer of fluid from the production zones to the production facilities.
For multiple string completions two or three segments, one for each production string, are used to form a hanger assembly which, when installed in the appropriate tubing head, resembles a mandrel type tubing hanger. Figure 8.21 shows a tubing hanger spool arrangement for use in a dual completion. An important characteristic of this tubing hanger is the support wedges (or in other heads support pins) used to guide and align the two segmented hangers in their proper positions in the upper bowl. The segmented hangers are locked in place with the tie-down screws.
A disadvantage of this type of hanger is that seals are often damaged while installing the second segment.
NOTE: Segmented hangers are available to accommodate a backpressure valve and are also manufactured with control line outlets to allow an SCSSV to be installed in the production tubing.
Figure 8.21 – Tubing Hanger Spool
After long service periods, it may be difficult to re-open the rams
The tubing pick-up weight must be overcome prior to opening the rams otherwise the rams will be difficult to open
They are bulky, heavy and expensive.
Figure 8.20 - Cameron Single Ram Tubing Head (‘SRT’)
Figure 8.19- Cameron ‘F’ Tubing Head and Hangers
Ram Type Tubing Heads find their application in completions where manipulation of the tubing is necessary to locate and latch into a packer and to maintain tension in the tubing when landed.
Figure 8.20 shows a ram type tubing head that comprises a housing with two side outlets in which are located retractable rams. These rams, when closed, support the hanger nipple, which is screwed on to the top of the tubing string. A seal assembly provides the seal between the annulus and the tubing, which is located around the hanger nipple above the rams.
With the ram type tubing hanger installed on the wellhead and the packer set, production tubing is run and spaced out so that the final position of the hanger nipple is that distance below the tubing head corresponding to the amount of stretch required to give the appropriate tension. The tubing is latched into the packer and tension applied to the tubing so that the hanger nipple is just above its final hang off position. The rams are closed, the tubing weight is set on the rams and the handling string removed. The seal assembly is then installed, bolted down, and the seal system energised by the injection of plastic packing. Finally, the BOPs are removed and the Xmas Tree installed.
NOTE: Like mandrel type hangers, landing nipple hangers are provided with a top thread for the landing joint, an internal left hand thread or wireline profile for the installation of a back pressure valve, and can be supplied with extended necks to facilitate secondary sealing. Also, ram type tubing heads are available with control line outlets to allow an SCSSV to be incorporated in the tubing string.
The important features of tubing hanger spools are:
Top and Bottom
Connections the size and pressure ratings of these connections (usually flanged) must be compatible with the size and pressure rating of the joining connections.
Upper Bowl provides the seal area for various tubing hangers and a load shoulder to support the production tubing.
Lower Bowl this is provided to house some type of isolation seal.
Set Screws or hold-down screws are found in most tubing heads and have two important functions.
Retain the tubing hanger and prevent any upward tubing movement due to pressure surges.
Activate (energise) the body seals on the tubing hanger.
Outlets these provide access to the annulus (e.g. for pressure monitoring or gas lift) during production.
Test Port permits the pressure testing of the hanger seal assembly, lockdown screw packing connection between flanges, and the secondary (isolation) seal.
The important features of tubing hangers are:
Landing Threads these are the uppermost threads on the hanger and they must support the entire weight of the tubing string during landing operations.
Bottom Threads these must support the entire weight of the tubing string and seal the producing conduit from the tubing/casing annulus.
Sealing Area these provide compression type sealing between the outside diameter of the hanger body and the inside diameter of the hanger bowl. Sealing is accomplished by energising elastomer seals or metal-to-metal seals by the action of tubing weight on various load-bearing surfaces.
Tubing hangers are sized according to the upper bowl of the tubing head and the tubing size the hanger will be supporting. Thus, a 7” x 27/8” tubing hanger means a 27/8” production string suspended from a tubing head 71/16” top bowl.
wells, casing size tubulars are often installed as the production conduit.
Tubing selection is governed by several factors. Anticipated well peak production rate, depth of well, casing sizes, well product, use of wireline tools and equipment, pressures, temperatures, and tubing/annulus differential pressures are among those which must be considered.
To meet various completion designs, there is a wide range of tubing sizes, wall thickness (weights) and materials to provide resistance to tubing forces and differing well environments. The best tubing selection is the cheapest tubing which will meet the external, internal and longitudinal forces it will be subjected to, and resist all corrosive fluids in the well product.
Tubing in the main is supplied in accordance to API specifications which has a range of materials to resist most of the potential corrosive well conditions but today where deeper high pressure sour reservoirs are being developed, the API range is not suitable. To fill this gap in the market steel suppliers provide propriety grades. These grades are usually high chrome steels designed for various high temperature and sour well conditions up to 24% chrome.
For ease of identification, tubing is colour coded to API specification. Some specialist supplier's steels are not covered by the code and provide their own specific codes. Refer to these codes to ensure the tubing is according to requirements.
8.10.9 Tubing Hangers
Bowl Type Tubing Head/Mandrel Type Tubing Hanger
A Tubing Head/Tubing Hanger combination unit is attached to the uppermost casing head on the wellhead. The main functions of this unit are to:
Suspend the tubing
Seal the annular space between the tubing and the casing
Lock the tubing hanger in place
Provide a base for the wellhead top assembly (Xmas Tree)
Provide access to the annular space (‘A’ annulus).
Suspension of the tubing is accomplished usually by threads, slips or any other suitable device, i.e.
rams.
The tubing head consists of a spool piece type housing where the internal profile of the top section is a straight or tapered cylindrical receptacle (bowl) into which the tubing hanger is landed, suspending the tubing and sealing off the volume between the tubing and the casing. A tapered mandrel type tubing hanger system is shown in Figure 8.19.
8.10.7 Control Lines
The conduit, which supplies the hydraulic fluid to the SCSSV, is termed the ‘control line’. The control line is normally 1/4“ OD tubing attached between the sub-surface valve (TRSV) or nipple (WRSV) and the tubing hanger. It is attached with compression fittings, and clamped to the outside of the tubing.
The method of porting through the hanger to the control manifold is dependent on the type of wellhead and hanger system being used. Some systems on land wellheads are simply fed out through a port with a packing element (often a tie-down bolt hole) that is tightened to seal around the outside of the tubing. Other systems have drilled ports through the hanger, into which the control line is fitted again by a compression fitting, and the spool sealed off from the annulus and the Xmas tree bore by concentric weight set or pressure energised seals.
Subsea wellheads have different methods of termination so the tree can be installed without diver assistance.
The control line material is selected to meet the environment in which it is to be installed and must be compatible with the safety valve and the hanger materials to avoid corrosion caused by electolosis (Dissimilar materials). There is a large choice of control lines materials from 316ss for sweet service to Inconel and Elgiloy alloys for more demanding service. They are also supplied in hard durable plastic coatings for added protection from corrosion and against crushing damage during installation, which at one time was one of the major problems during completing. Two lines can be encased for operation of dual-control line safety valves.
Control lines are held flat to the tubing by control line protectors usually placed across a coupling or connection and sometimes also in the middle of a joint. The protector has a slot into which the control line plastic outer coating fits. Simple banding can be used but it is not strong and is easily ripped off. Protectors are now metal clamp types as earlier rubber versions were easily detached and caused major problems while retrieving the completion string.
8.10.8 Tubing
The purpose of using tubing in a well is to convey the produced fluids from the producing zone to the surface, or in some cases to convey fluids from the surface to the producing zone. It should continue to do this effectively, safely and economically for the life of the well, so care must be taken in its selection, protection and installation.
The tubing must retain the well fluids and keep them out of the annulus to protect the casing from corrosion and well pressure which may be detrimental to future well operations such as workovers.
Tubing connections play a vital part in the function of the tubing. There are two types of connection available today; API and premium connections. API connections are tapered thread connections and rely on thread compound to affect a seal whereas the premium thread has at least one metal-to-metal seal. Premium connections are generally used in high pressure wells.
Surface control manifolds are designed to provide and control the hydraulic pressure required to hold an SCSSV open. The manifold has one or more air powered hydraulic pumps to maintain the hydraulic operating pressure for the safety valve.
The hydraulic pressure is through a three-way control valve, which is controlled by remote pressure pilots and fire sensors. Pilot, sensor or manual activation removes the hydraulic pressure, closing the safety valve.
NOTE: Activation can occur from the operation of remote-control pressure sensing pilots, fusible plugs, plastic line, sand probes, level controllers or emergency shutdown (ESD) systems.
Surface control manifolds are generally supplied as complete systems containing a reservoir, pressure control regulators, relief valves, gauges, and a pump with manual override.
Manifolds, in combination with the various pilot monitors, have many different applications, e.g.
controlling multiple Wells using individual control, multiple Wells using individual pressures and any combination of these.
Other additional features have been incorporated into surface control manifolds when the system is integrated with other pressure-operated devices. A control panel, designed to supply hydraulic pressure to a surface safety valve (SSV) and hydraulic pressure to an SCSSV, contains circuit logic for proper sequential opening and closing of the safety valves, i.e.
Sequential closing:
Sequential logic is incorporated to increase the service life of hydraulic master valves and SCSSVs to prevent SCSSVs becoming flow cut by high velocity wells.
Improvements have also been made in the monitoring systems, e.g.:
Sand erosion probes installed on a flowline to monitor sand flow production.
Quick exhaust valves, which allow rapid exhausting of control line pressure, to speed up valve closures.
Figure 8.18 - Typical Annular Safety Valve System
The sub-surface safety valves discussed so far, i.e. tubing retrievable and wireline retrievable, only provide control on the tubing. In these systems, no annular flow control exists.
Annulus safety valve systems are usually associated with completions where artificial lift or secondary recovery methods are employed e.g. gas venting in electric submersible pump (ESP), hydraulic pump, and gas lift installations. Their application is to remove the potential hazard of a large gas escape in the event there is an incident where the tubing hanger seal is breached.
There are a number of designs on the market and the variety of modes of operation is too wide to be covered in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off. This is generally a packer type installation, but may also be a casing polished bore nipple into which a packing mandrel will seal. In the sealing device there is a valve mechanism operated by hydraulic pressure similar to an SCSSV. The valve mechanism opens the communication path from the annulus below to the annulus above the valve and is fail-safe
There are a number of designs on the market and the variety of modes of operation is too wide to be covered in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off. This is generally a packer type installation, but may also be a casing polished bore nipple into which a packing mandrel will seal. In the sealing device there is a valve mechanism operated by hydraulic pressure similar to an SCSSV. The valve mechanism opens the communication path from the annulus below to the annulus above the valve and is fail-safe