The purpose of the Safety valves is to protect people, environment and property from uncontrolled production.
- SSV: Surface Safety Valves: an automatic fail-safe closed valve fitted at the wellhead.
- SSSV: Subsurface Safety Valve: a valve installed in the tubing down the well to prevent uncontrolled flow in case of an emergency through the tubing when actuated. These valves can be installed by wireline or as an integral part of the tubing. Subsurface Valves are usually divided into the following categories.
- SCSSV: Surface-Controlled Subsurface Safety Valves: SSSV which is controlled from the surface and installed by wireline or as an integral part of the tubing.
- SSCSV (storm choke): Subsurface-Controlled Subsurface Safety Valve: SSSV which is actuated by the flow characteristics of the well, and is wireline retrievable.
- ASV: Annulus Safety Valve: a valve installed in the well to prevent uncontrolled flow in the casing-tubing annulus when actuated. It consists of an annular safety valve packer with a by-pass. The opening in the by-pass is controlled by a safety valve, which can be an integral part of the packer on a wireline retrievable valve.
Subsurface safety valve classification
- tubing versus annulus safety valve;
- tubing versus wireline, through flowline, or coiled tubing retrievable valve;
- subsurface versus surface controlled valve;
- excess flow controlled versus ambient well pressure controlled valve;
- hydraulically controlled versus electrically, or mechanically controlled valve;
- non-hydraulically balanced versus hydraulically balanced valve;
- electric cable controlled versus wireless controlled valve;
- non-equalising versus equalising valve;
- ball valve versus flapper, or poppet valve.
1. Safety Valves Categories
Safety valves are divided in two distinct categories: the tubing and the annulus safety valves
1.1 Tubing safety valves
The tubing safety valve is installed to provide a flow barrier in the production tubing string, between the tail pipe and the surface or mudline. Such a valve consists of 3 main items:
- the valve housing
- the closure element
- the control mechanism
Safety valve should not be considered as an extra barrier in the tubing when the well is closed-in for a long period of time. Sealing is not optimal because of design space limitations. They should not be used to regularly shut-in the well.
Tubing valve types are referred to as:
- Tubing retrievable subsurface safety valves (TR SCSSV);
- Wireline retrievable subsurface safety valves (WR SCSSV);
- Excess flow valve (SSCSV).
SSV functions and requirements:
- flow barrier in the tubing;
- fail safe closing;
- hold the maximum reservoir pressure in closed position;
- compatible with all well fluids (completion and well-treatment);
- minimum pressure drop;
- with the valve closed, downwards pump-through of kill fluid must be possible.
1.2 Annulus safety valves
The annulus safety valve (ASV) provides a flow barrier in the casing-tubing annulus. It consists of an annular safety valve packer with a by-pass. The opening of the by-pass is controlled by a safety valve, which can be an integral part of the packer or a wireline retrievable valve. It is a surface controlled, fail-safe closed device for annular flow.
In general, the ASV is installed in gas lifted wells where the annulus is filled with compressed gas and serves as a barrier. Because of gas lift valves, the tubing cannot be considered as a barrier between the reservoir and the surface. Although the gas lift valves are commonly equipped with check valves, they are not a valid barrier. The ASV is normally located at a shallow depth to reduce the volume of the gas stored in the annulus between the ASV and the wellhead.
Installing a tubing SSSV below the bottom gas lift valve, rather than an ASV and shallow SSSV, has two major disadvantages:
- the tubing SSSV has to be set deep;
- a large volume of compressed gas from the annulus will escape in case of a leaking wellhead.
ASV functions and requirements:
- provides a flow barrier in the annuluswith fail safe closing
- controlled from surface
- preferably operated separately from the tubing SSSV;
- hold the maximum reservoir and/or the maximum gas injection pressure in closed position;
- allow downwards pump-through of kill fluid when closed-in;
- minimum pressure drop across the gas injection path.
2. Installation and retrieval methods
The tubing safety valves can be divided into two main groups:
- valves threaded into the tubing string;
- temporary installed valves that can be retrieved by wireline, through flowline or coiled tubing.
2.1. Tubing retrievable valve
The valve body and connections should be at least as strong as the tubing. It should provide leak resistance to internal and external pressures and be compatible with the fluids.
A workover rig is required to retrieve the production string. Reliability and the longevity of components is vital.
During the installation of the tubing string, it is necessary to keep the valve open. This can be done by inserting a retrievable lock-open tool in the valve, without or in combination with the control signal from surface.
Completion fluids should not enter the TR SCSSV internals, in particular the spring chamber, as this can adversely affect its operation (some manufacturers recommend to use a temporary isolation sleeve).
Tubing retrievable SSSVs are well suited for:
- Subsea completions, where wireline operations are costly and where valve reliability and longevity are of utmost importance.
- Wells that have high volume oil production, because a TR-SSSV has a larger bore then a WR-SSSV (Compressibility of gas allows high rates through relative small bores without appreciable pressure drop).
- Multiple zone completions, where wireline jobs are frequent on equipment installed beneath the safety valve. The larger bore of a TR-SSSV facilitates the operations, where a WR-SSSV normally has to be retrieved.
- Retrieval and installation of a WR-SSSV are difficult, because of wax or scale deposition in the landing nipple.
2.2. Wireline retrievable valve
The wireline retrievable safety valve (WR SCSSV) is run on wireline. A lock mandrel is screwed on top of the WR SCSSV that enables using a landing nipple. This nipple must hold the valve/mandrel assembly against pressure differentials loads. The nipple has a polished bores to seal the path between WR SCSSV and landing nipple by seals fitted to the outside of the valve/mandrel assembly.
With hydraulically operated WR SCSSVs, the external seals have also the function of containing the control fluid that is to be transmitted to the valve actuator.
The landing nipple for an electrically operated valve has a connection for an electric control line and an inductive coupler to transmit the signal to the WR SCSSV.
The locking mandrels are available in two main types: the selective and the no-go mandrel. The selective mandrel is designed to set and lock in any of a number of identical profiles in a landing nipple. The no-go mandrel has a no-go ring (largest OD on the mandrel) situated above the external seal stack section on the mandrel which allow the mandrel to locate the landing nipple.
Wireline retrievable SSSVs are well suited for:
- Extreme hostile environment, where high temperature, aggressive well fluid or abrasive production tends to shorten the life of valve components.
- Extremely high pressure service, particularly when large size valves are required. TR-SSSVs body strength may be a concern at these high pressures.
2.3 Trough Flowline (TFL) retrievable valve
Trough Flowline retrievable safety valves use specially constructed mandrels and landing nipples. They must have a stronger hold-open force than SCSSVs, because the Trough Flowline tools are circulated upwards in the tubing string, which tends to drag the valve's flow tube up, causing the valve to close. To overcome this problem the actuator hold-open force should be higher than the sum of the normal hold open force and the drag forces that can be experienced. Trough Flowline retrievable SSSVs can be used for subsea completions where wireline operations are difficult.
2.4 Coiled tubing retrievable valve
This technique allow to set and retrieve SSSV in wells not accessible by wireline.
Another application is to install a SSSV in tubing without a landing nipple. Such a system consists of a production packer with an integral safety valve. The assembly is positioned by the coiled tubing and the packer is set by pressure from the coiled tubing.
The SSSV may also be run as an integral part of a spooled coiled tubing completion.
Coiled tubing retrievable SSSVs are well suited for:
- Highly deviated or horizontal wells.
- Retrofitting in tubing that is not prepared for installing safety valves.
- Coiled tubing completions.
3. Means of control
3.1 Subsurface controlled valves
Subsurface controlled valves are normally open and are designed to close with an abnormal change in well condition. They detect the flow or well pressure and close when the set limit is reached. Basically there are three different concepts:
- velocity type valve;
- ambient pressure type valve;
- rate of pressure loss valve.
3.2 Surface controlled; hydraulically operated valves
Surface controlled valves utilise valve elements that are normally closed. This fail-safe mode requires that the valve is to be opened by a hydraulic control-line pressure. Loss of this pressure will result in the closing of the valve by a spring. The hydraulic pressure is supplied from a surface control panel to the valve and acts on the actuator. Typical for hydraulic operated SCSSVs is the hydrostatic head pressure, generated by the vertical column of control fluid, which additionally acts on the valve actuator.
Hydraulically controlled valves have the following advantages:
- can be activated remotely and valve operation is predictable;
- no fail to close risk if control pressure is lost due to well-completion damage;
- the surface control line pressure and the time for valve operation will give an indication whether the valve opening and closing performance is satisfactory;
- TR-SCSSVs of which the hydraulic actuator is damaged can be put back into function by inserting a back-up valve (insert valve), which can be operated with the existing hydraulic control system;
- hydraulic control system for SCSSV can easily be integrated into the surface safety system;
- the technology is field proven.
There are two methods for transmitting the hydraulic control pressure to the SCSSV, namely via:
- the tubing/casing annulus;
- one or two small diameter control lines.
3.3 Surface controlled; electrically operated valves
Electrically operated SCSSVs have in common with hydraulic SCSSVs that the differential pressure over the closed valve must be equalised before the valve can be opened and a means to keep the valve open must be permanently available from surface for fail safe operation.
note: as E-valves are primarily designed for deep setting, self-equalising is not recommended, because of the extremely long time to equalise.
With electric valves that means is an electrical signal, either dc or ac. Loss of this signal will result in closing of the valve. The force to close is always provided by expanding steel springs, which are precompressed by either electric power or by the well pressure.
In addition electrically controlled valves have the following advantages:
- much faster response time (only a few seconds);
- almost no setting depth limitation for the electric control signal (no static head pressure of the control signal);
- well pressure does not effect the electric control signal;
- less potential leak paths;
- no fail-to-close risk if control cable is damaged;
- can be combined with downhole monitoring system.
There are presently two different electrical communication systems available for controlling electric valves:
- via steel encapsulated downhole electrical cable, clamped to the tubing string;
- via electro-magnetic waves along the casing and through the formation (wireless).
- via the tubing and the casing strings, which are electrically insulated by insulating centralisers.
3.4 Surface controlled; mechanically operated valve
One type of mechanically operated SSSV is the Go-Devil valve from Otis. This safety valve is a normally open valve. It is designed to close by an impact force on the head of the valve, provided by a heavy ball that is dropped from a ball-dropper assembly at surface. The impact force will activate the spring based mechanical linkage, that moves the valve to the closed position.
The ball-dropper assembly is flange mounted on top of the Christmas tree. The pocket of the ball dropper retains the ball, sized to activate the Go-Devil SSSV by falling against flow and impacting the head of the valve. The ball dropper assembly retains the ball until the loss of the control signal activates the release mechanism.
3.5 Closure elements
Three types of valve closure elements are commonly used for SSSV: the ball, the flapper and the poppet type. The flapper valve can further be divided in flat, contoured and curved flappers, while the poppet valve can be divided into closed body and sleeve type poppet valves. All types of closure elements pinch off the fluid stream by a pair of opposing surfaces rather than sliding surfaces. This principal method has the advantage that it can provide a good tight shut-off when the sealing surfaces are sound.
As noted the flapper valves may be flat, curved or contoured. The latter two were introduced to obtain a better OD/ID ratio, as they are shaped to fit when in the open position, more efficiently in the annular space of the valve housing.
The seat angle is the shape of the flapper sealing surfaces, which is an important parameter of the valve sealing performance. Traditional flapper valves have a seat angle of 45°, as the angled seat has the advantage that:
- it alignes the closure element as it seats;
- it reduces the possibility of trapping debris between the closure element and seat;
- it provides a contact pressure multiplication.
Due to the characteristics of the curved flapper design the seat angle may vary from 0° to 60° along the flapper circumference, thus requiring stringent alignment of the sealing faces. The contoured flapper design has an angled sealing surface over the full circumference of the flapper and thus has potential to provide good sealing. Field experience indicate that the flapper valve type is more reliable than the ball valve type.
3.6 Equalising systems
When a SSSV is closed, a high differential pressure may be present across the valve closure element. Opening the valve under this condition will be difficult, if not impossible, because of the incapability of the relatively small valve mechanism to cope with the load working on the large diameter closure element. Insufficient equalising will introduce high loads that could deform critical valve parts. Also, erosive wash-out on the closure element by the sudden rush of well fluid through the partly opened valve can occur. Therefore, prior to opening a SSSV it is necessary to equalise the differential pressure.
Two methods are used for tubing-pressure equalisation:
- by repressurisation of the tubing string above the SSSV from an external source, for instance a nearby well or a pump unit;
- by by-passing well fluid from below the SSSV through its integrated equalising valve into the tubing string above the SSSV.
4. SSSV setting depth requirements
The depth at which to set the subsurface safety valve depends upon a number of variables, such as hydrate and wax formation tendencies, deviation kick-off depth, scale precipitation, earthquake probabilities, etc. The OD of the safety valve may influence the casing/tubing string configuration and should be addressed at the conceptual design stage.
The following definitions of valve setting are proposed:
- Shallow set: SSSV between surface and 300 m (1000 ft) below surface
- Medium depth: SSSV between 300 m and 600 m (1000-2000 ft) below surface
- Deep set: SSSV more than 600 m (2000 ft) below surface
- Packer set: SSSV set at production packer
- Below packer: SSSV set below production packer or below secondary recovery equipment.
The recommended minimum setting depth is below the cratering depth (or 50 ft below the deepest pile penetration depth on offshore structures or 100 ft below ground level on land locations, if deeper).
Factors to be considered in determining the setting depth of SSSVs are:
- to give maximum depth protection against leakage from tubing to annulus;
- to give protection for abnormal conditions, e.g. earthquake areas, where both tubing and casing could become seriously damaged;
- to set the valve below cratering depth;
- to place the valve below the mudline when producing a well in deep water;
- to provide for well control in the event that one wellbore is intersected by another during drilling on an offshore platform where numerous highly deviated wells are drilled in a relative small area;
- to have an additional barrier below the lowest gas-lift valve in a gas-lifted well where no annulus safety valve is installed;
- to have a SSSV below secondary recovery equipment such as beam pump, ESP, etc. to afford well control during running and pulling operations;
- ·to have a SSSV below the tubing extension joint of a downhole packer to shut-off any leaks occurring at its dynamic seals;
- ·to place the valve as close to the reservoir as possible to provide downhole shut-in and safety means if there is a catastrophe during well testing;
- to reduce tubing pressure reduction losses;
- to minimise the accumulation of hydrate and wax inside the valves
- to enable downhole wireline jobs without the necessity to remove the SSSV;
- parallel use of an electrically operated SSSV with downhole pressure and temperature monitoring;
- government legislation.
- Temperature limitations (cold weather)
For tubing safety valves it is obvious that the deeper the valve is set (closer to the hydrocarbon source) the more protection it will give to the completion. However, the application of a deep-set tubing SSSV generates some unfavourable conditions, namely:
- installation and maintenance of the valve will become more difficult and more time consuming;
- in the event of a wellhead damage, a larger volume of hydrocarbons is able to dissipate from the tubing bore above the safety valve;
- the higher temperature further downhole effects the reliability and the longevity of non-metal valve parts, for instance polymeric seals in hydraulic valves and electric/electronic parts in electric valves;
- the response time of hydraulically operated valves will increase significantly and could become unacceptably long for the closing cycle;
- the hydrostatic head pressure generated by the hydraulic control-line column will generate excessive forces on the valve operating mechanism. Hence, designing and manufacturing of these valves becomes more complicated.
- Furthermore, the required control pressure to operate a single control line valve (the majority of SSSVs) could become too high and more than the pressure rating of standard well completion equipment.
4.1 Hydraulic SCSSV setting depth calculations
Required control pressure
The approach for determining the required hydraulic control pressure at surface to hold a valve open depends on the type of valve, viz. the single control line valve, the dual control line valve and the valve with a pressure chamber.
The single control line valve
The single control line valve is tubing pressure sensitive. The forces acting to operate this type of valve are as follows:
Valve forced open by:
- Surface control pressure acting on top of piston: Pc
- Hydrostatic head pressure acting on top of piston Ph
Valve forced close by:
- Spring force (valve in closed position): Pvc(valve in open position): Pvo
- Tubing pressure acting on bottom of piston: Pt
Due to friction in the valve mechanism and the spring characteristic, there is a certain spread between the valve opening pressure (Pvo) and closing pressure (Pvc).
Pspread = Pvo - Pvc
When the valve is in the fully open position, the following force equilibrium exists:
Pc + Ph = Pvo + Pt
or
Pc = Pvo + Pt - Ph
To ensure that the valve is completely open, a safety factor or pressure margin (Pm) is added to the surface control pressure. Hence, the available control pressure at surface to open the valve must be at least:
Pc = Pvo + Pt + Pm - Ph
Example:
Valve setting depth: 2000 ft
Control line fluid gradient: 0.437 psi/ft (sea water)
Tubing fluid gradient: 0.354 psi/ft
CITHP: 2900 psi
Pressure to open valve: 2800 psi
Safety margin: 500 psi (0.17 * CITHP)
Pc = Pvo + Pt + Pm - Ph
Pc = 2800 + (2900 + 2000 * 0.354) + 500 - (2000 * 0.437) = 6071 psi
Dual control line valve
The dual control line valve or the pressure balanced valve uses a second control line from surface to balance the generated hydrostatic head pressure in the control line. The forces acting to operate this type of valve are as follows:
·Valve forced open by:
- -Surface control pressure acting on top of piston: Pc
- -Hydrostatic head pressure acting on top of piston: Ph
- ·Valve forced close by:
- -Spring force (valve in closed position): Pvc(valve in open position): Pvo
- -Hydrostatic head pressure acting on bottom of piston: Ph
Due to friction in the valve mechanism and the spring characteristic, there is a certain spread between the valve opening pressure (Pvo) and closing pressure (Pvc).
Pspread = Pvo - Pvc
When the valve is in the fully open position and the control and the balance line are both filled with fluid of the same fluid gradient, the following force equilibrium exists:
Pc + Ph = Pvo + Ph
or
Pc = Pvo
To insure that the valve is completely open, a safety factor or pressure margin (Pm) is added to the surface control pressure. Hence, the available control pressure at surface to open the valve must be at least:
Pc = Pvo + Pm
Example:
Valve setting depth: 2000 ft
Control line fluid gradient: 0 437 psi/ft
Balance line fluid gradient: 0.437 psi/ft
CITHP: 2900 psi
Pressure to open valve: 3000 psi
Safety margin: 500 psi (0.17 * CITHP)
Pc = Pvo + Pm
Pc = 3000 + 500 = 3500 psi
Dome charged valve
The dome charged valve uses a pressure in an integral dome to (partly) balance the generated hydrostatic head pressure in the control line. The forces acting to operate this type of valve are as follows:
- Valve forced open by:
- Surface control pressure acting on top of piston: Pc
- Hydrostatic head pressure acting on top of piston: Ph
- Valve forced close by:
- Spring force (valve in closed position): Pvc(valve in open position): Pvo
- Dome pressure acting on bottom of piston: Pd
Due to friction in the valve mechanism and the spring characteristic, there is a certain spread between the valve opening pressure (Pvo) and closing pressure (Pvc).
Pspread = Pvo - Pvc
When the valve is in the fully open position, the following force equilibrium exists:
Pc + Ph = Pvo + Pd
or
Pc = Pvo + Pd - Ph
To ensure that the valve is completely open, a safety factor or pressure margin (Pm) is added to the surface control pressure. Hence, the available control pressure at surface to open the valve must be at least:
Pc = Pvo + Pd + Pm - Ph
Example:
Valve setting depth: 2000 ft
Control line fluid gradient: 0.437 psi/ft
Tubing fluid gradient: 0.354 psi/ft
CITHP: 2900 psi
Pressure to open valve: 2800 psi
Safety margin: 500 psi (0.17 * CITHP)
Gas chamber pressure: 800 psi (arbitrarily selected)
Pc = Pvo + Pd + Pm - Ph
Pc = 2800 + 800 + 500 - (2000 * 0.437) = 3226 psi
Fail-safe setting depth
The single control line valve
The theoretical maximum setting depth of a single control line SSSV depends on the capacity of the valve closing spring to overcome the generated hydrostatic head pressure in the control line. For fail safety it is essential that the tubing pressure is not taken into account for the assistance of valve closing, even though single control line valves are assisted by this pressure. Hence, the governing factors for the maximum valve setting depth are:
- Control fluid gradient (G);
- Valve closing pressure (Pvc);
- Safety margin (Pm).
The maximum setting depth (Dm) can be determined with the formulae:
Dm = Pvc - Pm/G
Example:
Control line fluid gradient: 0.437 psi/ft (sea water)
Tubing fluid gradient: 0.354 psi/ft
CITHP: 2900 psi
Pressure to open valve: 1600 psi
Safety margin: 500 psi (0.17 x CITHP)
Dm = Pvc - Pm/G
Dm = 1600 - 500/0.437 = 2517 ft
* For fail safety, the worst case must be assumed, one in which the control line ruptures near the valve and annulus fluid will enter the control line. Therefore, for any completion the heaviest fluid gradient, either from the control fluid or from the annulus fluid, is used as the minimum control line fluid gradient.
Dual control-line and dome-charged valves
Because the hydrostatic head pressure in the control line is counteracted, the setting depths of the dual control-line and the dome-charged valves are theoretically not limited.