electric downhole safety valve manufacturer

Halliburton provides proven, high-performance tubing-retrievable and wireline-retrievable subsurface safety valves (SSSV) designed to reliably shut-in (fail safe) if a catastrophic event occurs, allowing operators to maintain safe operations.

Our downhole safety valves provide your testing operations with fail-safe sustained control downhole in the event of an emergency or to facilitate test procedures.

Surface-controlled subsurface safety valves (SCSSVs) are critical components of well completions, preventing uncontrolled flow in the case of catastrophic damage to wellhead equipment. Fail-safe closure must be certain to ensure proper security of the well. However, this is not the only function in which it must be reliable—the valve must remain open to produce the well. Schlumberger surface controlled subsurface safety valves exceed all ISO 10432 and API Spec 14A requirements for pressure integrity, leakage acceptance criteria, and slam closure.

Through decades of innovation and experience, Schlumberger safety valve flapper systems are proven robust and reliable. The multizone dynamic seal technology for hydraulic actuation of subsurface safety valves is a further improvement in reliability performance when compared with traditional seal systems in the industry.

The multizone seal technology is currently available in the GeoGuard high-performance deepwater safety valves, which is validated to API Spec 14A V1 and V1-H.

Baker Hughes’s portfolio of subsurface safety valves deliver reliable performance when it matters the most, providing emergency closure in the event that well control is lost. We offer a full range of valves to suit applications ranging from shallow- to deep-set, and the valves are available in surface- and subsurface-controlled, tubing-retrievable, and wireline-retrievable options. All Baker Hughes valves undergo stringent prototype testing and conform to standards and specifications such as API and ISO, as well as requirements requested for your unique situation.

The tubing-retrievable subsurface safety valve (SSSV) provides well protection against pressure drop and system failure in wireline and thru-tubing operations. This retrievable safety valve is controlled from the surface with a hydraulic control line. The valve connects to the tubing string and remains open if adequate pressure is maintained. If pressure drops below the threshold (as occurs in the beginning stages of losing well control), the valve closes. This creates a barrier in the tubing to prevent fluids from rushing up the tubing.

The TSS series subsurface safety valves are tubing retrievable surface controlled subsurface safety valves. Compared with the TS series, the safety valve features super slim outer diameter design. The control line connects the valve to the surface, and the pressurization from surface on the control line controls the opening and closing of the flapper. This series of products includes self-equalizing and non-equalizing types.

Tejas has positioned itself as a Technology Partner to provide turnkey product solutions to OFSC’s and since 1999 developed exclusive products and complete product lines for OFSC’s. We are deeply rooted in Research & Development (R&D) with deep expertise in downhole completions products, especially subsurface safety valves and other flow control devices.

The subsurface safety valve (SSV) is an essential device of a subsea production system. The hydraulic SSV is widely used, but it has some drawbacks when used in deep water: It needs a long pipeline from platform to wellhead, and brings additional pressure loss. The system needs higher pressure and manufacturing costs, but the response is slower. To solve the problem, a new all-electric surface-controlled SSV (E-SCSSV) system consisting of an E-SCSSV body and a control system is developed. The innovative structural designs include electric-drive mechanisms and a magnetic coupler that can transfer linear motion. The mechanical property of E-SCSSV body is analyzed to determine the ability to resist well pressure. The coupling rule of the magnetic coupler is studied through experiment and finite-element analysis. The dynamics of the failure-safety mechanism is investigated to obtain the optimal performance and combination of structural parameters. Using sensors on the E-SCSSV body, the operation status of the E-SCSSV can be monitored. An E-SCSSV system prototype has been developed to validate the function of the E-SCSSV. Reliability requirements are discussed. Compared with existing SSVs, the biggest advantage of the E-SCSSV is its quick response.

The Flow Component Testing Facilities (FCTF) at SwRI are accredited through the American Petroleum Institute (API) to perform validation testing on both surface and subsurface safety valves. The facilities are also used to perform safety valve testing on other downhole safety valves, riser isolation valves, and wellhead valves. All testing is completed under an API Q1 and ISO 17025 quality management system.

SwRI performs SSSV testing on surface control safety valves (SCSSV) and subsurface control safety valves (SSCSV), subsurface injection safety valves (SSISV), and annular safety valves.Validation Testing – Annex B

SwRI performs testing on various types of valves used as underwater safety valves (USV), surface safety valves (SSV), and boarding shutdown valves (BDSV). This equipment is essential for emergency shutdown of offshore production.

The all-electric subsea Xmas tree, complete with electric downhole safety valve, has finally made its debut. Elaine Maslin spoke to Total’s Frederic Garnaud about the achievement.

The K5F-3 well has demonstrated the all-electric subsea concept, including a downhole safety valve (DHSV). Two earlier wells on K5F had all-electric trees – also firsts – but a hydraulic DHSV. Furthermore, the components involved have been qualified to 3000m water depth, making it a deepwater-ready technology.

The system uses Schlumberger-owned OneSubsea’s latest generation CameronDC subsea Xmas tree and controls technology and a Halliburton electric downhole safety valve (eDHSV).

It’s an achievement, towards reducing cost, simplifying the subsea system and enabling ultra-deepwater and long step outs, says Frederic Garnaud, deep offshore research and development program manager at French oil major Total.Once the technology has been observed working smoothly for a few months, subsea all-electric will become the base case for subsea control environments for Total deepwater developments, from 2017 forward, Garnaud says.

“The main benefit of electric control is in the cost reduction because the current technology for subsea control is based on hydraulic control, which requires a network of umbilicals, with electric cables and hydraulic and chemical lines,” he says. “These systems are expensive, very complex, and difficult to install. There is a major cost saving through simplification or removal of the umbilical.

“Electric technology will also be an enabler for frontier developments in deepwater. The industry is beginning to pay some attention to water depths of 3000-4000m. There’s no doubt, in such water depths, electrical control will be much easier to implement. It will really be an enabling technology. If you consider also long tiebacks, over 200km, there’s no doubt as well that electric control will enable those developments.”

By using all-electric, and eliminating hydraulics for power and signals, control-system commands can be sent in rapid succession, with high-speed communication also providing near-instantaneous communication with equipment – such as the status of the electric DHSV – as well as feedback on subsea conditions. Going all-electric also eliminates the potential for hydraulic leaks and the issue of hydraulic-fluid disposal.

Proving up an all-electric subsea tree became a goal for Total in the mid-2000s. It chose the K5F field in the Netherlands as its test bed, using the all-electric CameronDC technology, which Cameron as it was had been working on since 1999, for the gas development’s two subsea wells.

The latter only served to encourage the completion of development of an eDHSV with Halliburton. The second phase on K5F, the planned K5F-3 well, kicked off in 2013, with ongoing work on the eDHSV. Halliburton’s eDHSV uses electric linear actuators, adapted from its DepthStar DHSV. The subsea control modules were also upgraded, compared to what was on K5F.

“What we are doing in the Netherlands is a demonstration of subsea control technology for future assets in the deep offshore environment,” Garnaud says. “All of the components on this well are qualified for 3000m of water, so the eDHSV can run in the Gulf of Mexico or the Gulf of Guinea in deepwater. “Each component of the Xmas tree is also qualified for 3000m water, so we can use it on deepwater applications as well,” he says. Total has also been working on other building blocks for deep offshore developments, including subsea chemical storage. “With this we can completely remove the subsea umbilical,” Garnaud says. “Just install electric power cables with fiber optic for control and that’s it. By installing subsea electric control and subsea chemical storage you can save around 20% of the capex for facilities on the subsea satellite.”

But, it’s still early days and that’s largely due to needing more suppliers that are able to offer this equipment – and compete on tenders. “What is not really available today is the full range of demonstrators for valve control, actuators, the various pressure wrenches for the valves,” Garnaud says. “What’s also missing for real projects is competition among the technology providers. All of the major subsea suppliers, FMC Technologies, GE Oil & Gas, etc., are working on the subject but none of them has a full range of equipment today. What’s important for us from now on is to promote competition in the technology so that, from 2017 on, we are able to launch tenders for full electric control of subsea assets.”

While within Total there is an understanding of the benefits of this technology for deep offshore projects, the challenge will be persuading partners to embrace it as well. Even so, there’s a strong trend towards all-electric across the industry, Garnaud says, following on from moves already made by the likes of the aeronautical industry – Concorde had first electric controls partially replacing hydraulics back in 1969, he says. In fact, the linear actuators on the eDHSV have been derived from aerospace, he says.

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.

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:

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.

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.

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.

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.

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.

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.

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.

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.

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:

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.

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;

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.

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.

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.

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:

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.

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.

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.

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:

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 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.

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.

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).

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:

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:

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).

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:

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:

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:

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).

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:

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:

* 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.

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.