downhole safety valve animation price

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.

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.

Maintaining fluid control and well protection is critical in your shallow depth well operations. The SelecT™ subsurface safety valve from Baker Hughes addresses the unique challenges that shallow set safety valves (typically <1,000 ft) endure.

The tubing-retrievable SelecT valve includes an ultra-strong power spring that delivers the high closing forces needed to reliably and consistently close the valve in the presence of paraffin and other produced solids.

The SelecT is engineered to avoid failures due to wireline damage during downhole interventions. The valve’s advanced flapper design prevents damage and ensures that all seal surfaces are protected from wireline contact—even during accidental closure of the valve during wireline operations.

Ensure greater seal integrity with the SelecT valve’s patented advances that include thru-the-flapper self-equalizing system. And the radial punch control fluid communication system eliminates accidental communication associated with linear shifting sleeves.

Downhole Safety Valve nipples. The anchoring mechanism’s design and construction enables the use of standard locking profile or slips mechanism when the existing profile is damaged.

Avoids recompletion and reduces cost by allowing retrofitting of Wireline Retrievable Sub Surface Safety Valves in damaged Downhole Safety Valve nipples

PLUSCO 621-622 Safety Valve Sealant will improve the overall performance of the safety valve by insuring a continuous seal for extended operation. It eliminates line leaks, improves the hydraulic pump performance, maintains tighter seals and valve seating and reduces fluid friction in the system. The benefits of sealing, lubricity and operations efficiency are provided by PLUSCO 621-622 Safety Valve Sealant. Safety Valve Sealant will insure a continuous flow of the gas well without interruption or unnecessary shutdown.PLUSCO 621-622 Safety Valve Sealant is available in two grades depending on the severity of the leak in the system.

PLUSCO 621-622 Safety Valve Sealant is a high tech safety valve additive specifically designed for sealing hydraulic controlled surface or subsurface safety valves.PLUSCO 621 is designed for slow weeping leaks while PLUSCO 622 is for heavy pinhole type leaks.

A surface-controlled subsurface safety valve (SCSSSV) system without external wires or hydraulic lines needed for the valve"s operation is now available to the petroleum industry. Any of the current down-hole safety valves, such as Hydril, Otis, Camco or Baker, can be fitted to the valve operator. This is a totally fail-safe valve system, which can be overridden manually at the operator"s choice to accomplish a number of different modes. The valve"s operator is acoustically controlled by the operator"s predetermined settings at the surface. The predetermined settings at the surface. The receiver, translator, and valve actuator are packaged and placed in a special mandrel that is packaged and placed in a special mandrel that is run as a part of the tubing string. The hydraulic valve operator is mounted on a length of production tubing between the mandrel and valve. The full-flow valve is at the bottom of the down-hole string. Any length of production tubing may be run below the valve. Hookwall hangers can be run in as may be needed.

With the movement of the oil industry into the more or less hostile environment of offshore operations, it was apparent immediately to the oil operators that an automatic "fail-safe" valve was needed for the producing oil or gas "flow string".

A valve was produced that would respond to changes in flow rate either above or below levels preset into the valve. The first valve to be so adapted and so employed was the differential pressure, spring-loaded valve. Abnormal increases in the flow rate across the valve caused it to close. This valve was very simple in construction, could be set in the production string and removed by means of a production string and removed by means of a wireline. The differential pressure valve and its "sister" valve, the ambient pressure valve, which closed automatically if the rate of flow or resultant pressure across the valve dropped below a preset valve. These safety valves became known to the oil industry as "storm chokes", but actually the term "storm choke" is a registered patent term; therefore, such valves should only be referred to as down-hole production string safety valves. production string safety valves.

Downhole Safety Valve is an integral part of Well Integrity Mangement System and acts as a failsafe equipment to prevent uncontrolled release of reservoir fluids. Periodic inspection and maintenance of downhole Safety Valve is essential under normal service conditions. Each Downhole Safety Valve should be tested and lubricated at specified regular intervals as recommended by ADNOCs Standard Operating Procedure and as dictated by field experience. Since it is a Critical Safety Equipment, preventive maintenance of Wireline Retrievable type downhole Safety Valve is being carried out annually which involves valve retrieval, leak/function test and redressing if required.

Current practice within ADNOC Onshore is to carry out redressing with third party for all Wireline Retrievable Safety Valve annually or in case they are observed to be passing (not meeting the maximum acceptable gas leak rate of 15 scf/min for gas and 400 cc/min for liquid) or do not pass function test carried out during 6 monthly and yearly Preventive Maintenance Schedule.

The cost incurred for third party redressing is substantial and can be optimized by evaluating the possibility of carrying out redressing in-house with available resources and using Original Equipment Manufacturer redress kit in situations where internal leak is not observed in the valve and valve can be redressed without the need to open tension spring and flow tube which requires extensive redressing setup available with third party.

The WellStar® tubing-retrievable safety valve is a general production, hydraulically operated, downhole TRSV. The rugged hydraulic actuator of the WellStar safety valve provides durability and isolates the internal workings from well fluids through its unique construction. The metal-to-metal (MTM) sealing integrity in the body joints and closure mechanism places it in a premium valve category while featuring an economical price. Proven through years of installations, the simple, compact design enhances the valve’s overall reliability and provides for trouble-free operation.

Aberdeen-based oil and gas production technology business Pragma said it has developed an advanced downhole safety valve to create an improved well control solution for cable deployed Electric Submersible Pumps (ESPs) retrofitted to production wells.

The new valve will enable on and offshore installations to meet all safety regulations while improving the operational footprint at the wellsite during installation and retrieval by reducing time, cost, personnel and risk.

An API 14A qualified subsurface safety valve (SSSV) is a legal requirement for producing wells in many regions. These devices generally use a flapper style mechanism and are incorporated in the production tubing during completion. However, when an ESP is retrofitted to a well, its surface control lines run through the inside of the production tubing, obstructing the SSSVs and creating the requirement for an additional safety valve. A rig would usually be mobilized to deploy the valve and then the ESP in separate runs, however cable deployment now provides significant cost and efficiency savings.

Pragma said its ESP safety valve has been designed to complement this type of deployment. It is a compact device, integrated within the lower portion of the ESP assembly and is deployed and retrieved through the production tubing in the same run as the ESP. It is the only device on the market which offers wellbore closure below the ESP control lines, the developer said. By installing the valve between the ESP and ESP packer, the valve does not rely on the integrity of aged well completion components unlike alternative systems.

The valve’s functionality is based on a novel pressure differential, or lift actuated design, requiring no pressurized chambers, hydraulic control lines or electrical power, which safeguards reliability. The valve will fail-safe close when the ESP is switched off and can be opened and closed as many times as required. The technology can also be applied to alternative artificial lift systems including capillary strings, gas lift velocity strings, progressive cavity pump and jet pump systems. A high temperature version is also available.

Pragma Technology Manager, Matt Manning, said, “Like a demand valve, or pressure regulator between the tank and mouthpiece of deep-sea diving equipment, our valve uses the ESP’s lifting capability to open or close it in line with production. The unique design advantages of this technology, combined with its compact nature, not only provide greater safety and reliability assurances to the operator, but also lower installation, operation and retrieval costs. The technology has been developed in-house and we are conducting prototype testing, with field trials and API 14A certification planned later this year.

“As the oil and gas industry continues to evolve, it’s important the supply chain also adapts to deliver quality solutions to support cost reduction and production optimization. The ESP safety valve is just one example of how Pragma continues to pioneer advanced technologies to deliver safety and efficiency gains.”

The surface-controlled subsurface safety valve (SC-SSSV) is an integral part of the overall safety system of any well, and it is the only method that provides subsurface isolation in case of emergency caused by uncontrolled surface or subsurface events. The effectiveness of these valves can be threatened by leaks, plugs, or breaks in the control lines (CLs). This paper describes a methodology that deploys CLs on the inside of the tubing, reducing cost and ensuring continued effectiveness of SC-SSSVs.

Functional SC-SSSVs must be installed in production tubing in all gas and oil wells, irrespective of location, as a safety barrier to halt flow in case of a catastrophic failure. SC-SSSVs are held in the open position by introducing hydraulic positive pressure from the surface. This pressure is applied through a CL in the tubing/casing annulus running from the valve to the surface. In case of an emergency shutdown, the hydraulic pressure will be lost, forcing the safety valve to close.

CLs for SC-SSSVs could leak, plug up, or break, leading to loss of the capability to control the valves’ operating condition, causing environmental and safety concerns in addition to a loss of production upon closure of the valve.

The valve is run into the well using a standard wireline unit. The valve is located inside the existing SC-SSSV and locked into position. Once the valve is locked into position, the wireline running tool is retrieved. The valve has an internal stinger receptacle. The receptacle is used to communicate CL fluid to the valve.

The hydraulic fluid required to control the new SC-SSSV valve will be transferred to the valve through a ¼- or ⅜-in. capillary string. The capillary tubing and stinger used for transferring the CL fluid will be terminated at surface through a hanger system or a modification to the current tubinghead-hanger arrangement. The hanger is installed below the existing production tree.

As per the preset plan, the operation was carried out and completed in 3 days (daytime operations only). The first 2 days were dedicated to installation, and the third day was dedicated to testing the system. The most critical part of the operation was the installation of the capillary line, because it required high accuracy in taking measurements and making the final cut to accommodate the line exactly between the downhole valve and the hanger mandrel.

As a result of the successful trial of this system, this innovation is currently being practiced in existing wells and will be continued for future development projects because of its safety profile and cost-effectiveness.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164370, “Innovative Methodology To Riglessly Restore the Functionality of Subsurface Safety Valves (SC-SSSVs) With Damaged Control Lines,” byMohamed Fahim, Hossam Elnaggar, Abd Allah ElBarbary, Mohammed Abu Arab, Ashraf Keshka, Hamdi Bouali Daghmouni, and Mohamed Al Karra, ADCO, and Ammar Soufan, Joseph O’Connor,and Magdi Elasmar, Baker Hughes, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10–13 March. The paper has not been peer reviewed.

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.

A downhole safety valve refers to a component on an oil and gas well, which acts as a failsafe to prevent the uncontrolled release of reservoir fluids in the event of a worst-case-scenario surface disaster. It is almost always installed as a vital component on the completion.

These valves are commonly uni-directional flapper valves which open downwards such that the flow of wellbore fluids tries to push it shut, while pressure from the surface pushes it open. This means that when closed, it will isolate the reservoir fluids from the surface.

Most downhole safety valves are controlled hydraulically from the surface, meaning they are opened using a hydraulic connection linked directly to a well control panel. When hydraulic pressure is applied down a control line, the hydraulic pressure forces a sleeve within the valve to slide downwards. This movement compresses a large spring and pushes the flapper downwards to open the valve. When hydraulic pressure is removed, the spring pushes the sleeve back up and causes the flapper to shut. In this way, it is failsafe and will isolate the wellbore in the event of a loss of the wellhead. The full designation for a typical valve is "tubing retrievable, surface controlled, subsurface safety valve", abbreviated to TR-SCSSV.

The location of the downhole safety valve within the completion is a precisely determined parameter intended to optimise safety. There are arguments against it either being too high or too low in the well and so the final depth is a compromise of all factors. MMS regulations state that the valve must be placed no less than 30 m (100 ft) below the mudline.

The further down the well the DHSV is located, the greater the potential inventory of hydrocarbons above it when closed. This means that in the event of loss of containment at surface, there is more fluid to be spilled causing environmental damage, or in the worst case, more fuel for a fire. Therefore, placing the valve higher limits this hazard.

Another reason relates to the hydraulic control line. Hydraulic pressure is required to keep the valve open as part of the failsafe design. However, if the valve is too far down the well, then the weight of the hydraulic fluid alone may apply sufficient pressure to keep the valve open, even with the loss of surface pressurisation.

As part of the role of the DHSV to isolate the surface from wellbore fluids, it is necessary for the valve to be positioned away from the well where it could potentially come to harm. This implies that it must be placed subsurface in all circumstances, i.e. in offshore wells, not above the seabed. There is also the risk of cratering in the event of a catastrophic loss of the topside facility. The valve is specifically placed below the maximum depth where cratering is expected to be a risk.

If there is a risk of methane hydrate (clathrate) plugs forming as the pressure changes through the valve due to Joule–Thomson cooling, then this is a reason to keep it low, where the rock is warmer than an appropriately-calculated temperature.

Most downhole safety valves installed as part of the completion design are classed as "tubing retrievable". This means that they are installed as a component of the completion string and run in during completion. Retrieving the valve, should it malfunction, requires a workover. The full name for this most common type of downhole safety valve is a Tubing Retrievable Surface Controlled Sub-Surface Valve, shortened in completion diagrams to TRSCSSV.

If a tubing retrievable valve fails, rather than go to the expense of a workover, a "wireline retrievable" valve may be used instead. This type of valve can fit inside the production tubing and is deployed on wireline after the old valve has been straddled open.

The importance of DHSVs is undisputed. Graphic images of oil wells in Kuwait on fire after the First Gulf War after their wellheads were removed, demonstrate the perils of not using the components (at the time, they were deemed unnecessary because they were onshore wells). It is, however, not a direct legal requirement in many places. In the United Kingdom, no law mandates the use of DHSVs. However, the 1974 Health & Safety at Work Act requires that measures are taken to ensure that the uncontrolled release of wellbore fluids is prevented even in the worst case. The brilliance of the act is that it does not issue prescriptive guideline for how to achieve the goal of health and safety, but merely sets out the requirement that the goal be achieved. It is up to the oil companies to decide how to achieve it and DHSVs are an important component of that decision. As such, although not a legal requirement, it is company policy for many operators in the UKCS.

While the DHSV isolates the production tubing, a loss of integrity could allow wellbore fluid to bypass the valve and escape to surface through the annulus. For wells using gas lift, it may be a requirement to install a safety valve in the "A" annulus of the well to ensure that the surface is protected from a loss of annulus containment. However, these valves are not as common and they are not necessarily installed at the same position in the well, meaning it is possible that fluids could snake their way around the valves to surface.