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Completion flow control accessories
Flow-control accessories add to the flexibility of the cased-hole completion design and perform a multitude of tasks, such as:
- Temporarily plugging off the tubing string.
- Establishing temporary communication between the tubing and the annulus.
Profile seating nipples and sliding sleeves have a special locking groove and a honed sealbore to allow a flow-control device to lock in the nipple and seal off when installed. By design, the sleeves and nipples will have a smaller inside diameter (ID) than that of the tubing string. For this reason, careful consideration must be given to the overall application and completion design when selecting and sizing the various models of profile seating nipples and sleeves. This is especially true in any case in which through-tubing operations or perforating are planned.
Correct application of flow-control accessories can greatly reduce the time and money spent on diagnosing well problems (such as tubing or leaks) should they occur. Strategically placed profile seating nipples above and below the packer aid in isolating the leak to the packer or the tubing string. Once the source of the failure is known, a plan can be formulated to resolve the problem. Not much can be done to fix a packer leak without well intervention. However, special flow-control devices are available to straddle across sections of leaking tubing and deter workovers. In either case, the knowledge gained by being able to use flow-control accessories and devices to perform downhole diagnostics is extremely valuable in planning corrective action to be addressed in the subsequent workover.
- 1 Wireline re-entry guides
- 2 Profile seating nipples
- 3 Sliding sleeves
- 4 Blast joints
- 5 Flow couplings
- 6 Blanking plugs
- 7 Bottomhole choke
- 8 Subsurface safety systems
- 9 References
- 10 Noteworthy papers in OnePetro
- 11 External links
- 12 General references
- 13 See also
- 14 Category
Wireline re-entry guides
In some operations, it is necessary to run electric wireline, slickline tools, or coiled-tubing assemblies past the end of the tubing string and into the casing below (Fig. 1). Upon retrieving these tools, there may be problems pulling them back into the tubing string if the tubing is run open-ended and unprotected. Sharp edges and square shoulders of pin threads, couplings, or muleshoes can cause the tools to snag or hang up on re-entry. The wireline re-entry guide is run on the end of the tubing string (or the tailpipe below the packer) and is designed to facilitate re-entry into the tubing string of those electric-line or slickline assemblies. It has an internally beveled, bell-shaped ID that eliminates any sharp edges or square shoulders and helps align the tools as they are pulled back up into the tubing string.
Profile seating nipples
Profile seating nipples are often referred to as:
- Top no-go
- Bottom no-go
As the names indicate, each has a unique machined profile with a locking groove to accept a flow-control device that is run and installed on slickline or coiled tubing. The profile seating nipple also has a honed and polished sealbore to allow the slickline device to not only land and lock into the nipple, but also to seal off, assuming the accessory item to be installed also has a packing stack.
Profile seating nipples are positioned at strategic locations within the tubing string to allow the accurate placement of:
- Slickline plugs
- Check valves
- Bottomhole chokes
- Downhole flow regulators
- Bottomhole pressure recorders
At least one profile seating nipple is recommended near the bottom.
Top no-go profile seating nipple
The “top no-go” nipple accepts a lock assembly with a no-go shoulder located on the lock itself (Fig. 2). When the lock assembly is run in the hole, the no-go shoulder on the lock engages or locates on top of the nipple. Once located, the locks are engaged into the locking groove, and the installation process is complete. Care must be taken when designing the completion to ensure that there are no ID restrictions above the nipple to prevent passage of the lock assembly. The “top no-go” nipple is generally run when a single nipple is required in the hole and the largest ID possible is required through the nipple profile. However, more than one “top no-go” may be run if the IDs of the profiles are reduced sufficiently as the nipples progress in the hole to allow passage of the appropriate locking assembly through the nipple located immediately above the intended target nipple.
Bottom no-go profile seating nipple
The “bottom no-go” nipple has a no-go shoulder located in the bottom of the nipple (Fig. 3). The lock assembly or slickline device landed in this type of nipple locates the nipple by landing on the bottom no-go. Once landed and located in the nipple, the locks can be engaged and the installation completed. Because its ID will not allow passage of any flow-control device through the nipple, the bottom no-go nipple is always run as the lowermost nipple in the completion. Another benefit of having a no-go nipple in the completion is that any other slickline tools or tubing swabs that are lost in the tubing string should not fall to the bottom. The lost equipment usually can be fished out of the tubing string or, in cases when it cannot, the tubing can be pulled to recover the tools.
Selective profile seating nipple
“Selective” type profile nipples are perhaps the most versatile of the three (Fig. 4). In such a design, an unlimited number of the same size and type profile seating nipples may be run in the hole, because the locking assembly or flow-control device is able to find and selectively land in any of them. In most systems, either the packing stack or a collett indicator is used to help the slickline operator locate the nipple, and alternately picking up and slacking off through the nipple actuates the locks and sets the flow-control device. The benefit of this type system is a larger ID through the completion and fewer slickline accessory items that must be inventoried. Generally, it is still advised that a no-go nipple be run on the bottom of the tubing string to prevent any lost tools from falling into the cased hole below the completion.
In oil- and gas-well completions, the sliding sleeve provides a means of establishing communication between the tubing and annulus for (Fig. 5):
- Fluid circulation
- Selective zone production
- Injection purposes.
The sliding sleeve is ported from ID to outside diameter (OD) and has an internal closing sleeve that can be cycled multiple times using slickline or coiled-tubing shifting tools. When in the open position, the sleeve allows communication from tubing to annulus, and when closed, pressures are once again isolated.
The sliding sleeve also incorporates a nipple profile and polished sealbore above and below the ports to allow the landing of various flow-control devices or an isolation tool should the sleeve fail to close. The isolation tool locks into the profile in the upper end of the sleeve, and seal stacks on the tool straddle the ports to achieve isolation. The success of sliding sleeves depends on well conditions. Operational problems in the opening and closing of sliding sleeves may be caused by:
- High temperature
- Sour gas
The blast joint is used in multiple-zone wells in which the tubing extends past a producing zone to deter the erosional velocity of the produced fluids and formation sand from cutting through the tubing string. In most cases, the blast joint is simply a thick, heavy wall joint of steel pipe. However, there are also more sophisticated designs that use materials such as Carbide® for severe service applications. Care must be taken when running and spacing out the tubing string to position the blast joint evenly across the open perforations. It is wise to run enough length of blast joint to provide 5 to 10 ft of overlap across the perforations to allow for errors in tubing measurements.
Flow couplings are usually the same OD as the tubing couplings and have the same ID as the tubing string with which they are run. They are run above and below any profile seating nipple and sliding sleeve in which it is anticipated that the turbulence created by the flow through the nipple restriction can reach erosional velocity and damage the tubing string. The flow coupling does not stop the erosion. Its thick cross section will extend the life of the completion, because more material must be lost to erosion before failure occurs than in the case of the tubing string alone. Flow couplings are recommended when a flow-control device is to be installed on a permanent basis (i.e., safety valve or bottomhole choke).
Blanking plugs may be landed in profile seating nipples or sliding sleeves to temporarily plug the tubing string, allowing pressure to be applied to the tubing string to test tubing or set a hydraulic packer, or to isolate and shut off the flow from the formation. The basic blanking plug consists of:
- A lock subassembly
- A packing stack
- A plug bottom
Each size and type of blanking plug is designed to fit a specific size and type of profile seating nipple or sleeve. Slickline blanking plugs always have an equalizing device incorporated into the design to allow pressure above and below the plug to equalize before releasing the lock from the nipple. This prevents the toolstring from being blown up the hole.
Bottomhole chokes are flow-control devices that are landed in profile seating nipples. The bottomhole choke restricts flow in the tubing string and allows control of production from different zones. It can be used to prevent freezing of surface controls. The choke assembly consists of:
- A set of locks
- Packing mandrel
- Packing assembly
- Choke bean.
The choke bean is available with orifices of varying sizes. The orifice size must be predetermined and sized specifically for the intended application.
Subsurface safety systems
If a catastrophic failure of the wellhead should occur, the subsurface safety valve provides a means to automatically shut off the flow of the well to avoid disaster. There are basically two types of downhole safety valves—subsurface-controlled safety valves and surface-controlled subsurface safety valves (SCSSV).
Subsurface-controlled safety valves
The subsurface-controlled safety valves (often called velocity valves or Storm® chokes) are wireline retrievable and are installed in standard profile seating nipples in the tubing string below the surface tubing hanger (Fig. 6). A subsurface safety valve requires a change in the operating conditions at the valve to activate the closure mechanism. There are two models of subsurface controlled safety valves. The velocity valve contains an internal orifice that is specifically sized to the flow characteristics of the well. The valve is normally open and is closed by an increase in flow rate across the orifice. This creates a pressure drop, or differential pressure, across the valve that causes it to close. The velocity valve reopens when the pressure is equalized across the valve.
Another type of subsurface-controlled valve is the gas-charged or low-pressure valve. This valve is normally closed, and the bottomhole pressure must be higher than the preset pressure valve for the valve to remain open. If the flow rate of the well becomes too great and the bottomhole pressure falls below the preset value of the valve, the valve will automatically close. It is reopened by applying pressure to the tubing string to raise the pressure above the preset pressure value of the valve.
For either valve to work properly, the well must be capable of flowing at sufficient rates to close the valve, and the catastrophe must be severe enough to create the conditions necessary to actuate the closing system. The settings of the valves are critical to success, and they must be checked periodically.
Surface-controlled subsurface safety valves (SCSSVs)
The SCSSVs are also installed in the tubing string below the surface tubing hanger. They are controlled by hydraulic pressure through a capillary (control) line that connects to a surface control panel (Fig. 7). Most SCSSV designs today use a flapper to form a seal. Both elastomeric and metal-to-metal seal designs are available.
The SCSSV is a normally closed (failsafe) valve and requires continuous hydraulic pressure on the control line to keep it open. The pressure acts upon an internal piston in the valve, which pushes against a spring. When the hydraulic pressure is relieved, the internal spring moves a flow tube upward and uncovers the flapper. The flapper then swings closed, shutting the well in. Ball valves work similarly. The surface control panel, because of a change in flowing characteristics that exceed predetermined operating limits, generally initiates the closing sequence. However, any failure of the system that results in loss of control-line pressure should result in the valve shutting in the well.
To open the SCSSV, the pressure above it must be equalized (usually by pressuring up on the tubing string), and hydraulic pressure must be reapplied to the control line. Some models have a self-equalizing feature and can be reopened without the aid of pressuring up on the tubing. Whether the valve is working or not, most models have a pump-through kill feature that allow fluids to be pumped down the tubing to regain control of the well.
The SCSSV is available in a tubing-retrievable model and a wireline-retrievable type. The wireline-retrievable SCSSV is installed in a special ported safety-valve nipple. The capillary line is connected from the surface control panel to the ported nipple. The hydraulic pressure applied at the surface communicates to the valve through the ported nipple. The wireline-retrievable SCSSV can be pulled and serviced without pulling the tubing string out of the hole. Because of the design and the use of elastomeric seals, they are somewhat less reliable than the tubing-retrievable version. The wireline-retrievable valve has a smaller ID, and reduces flow area for production to pass through. The reduction in ID can create a pressure drop across the valve and turbulence in the tubing above it. In high-flow-rate wells, the turbulence can lead to erosion of the valve or tubing string. Access to the tubing string below the valve is restricted when the wireline-retrievable SCSSV is installed. The valve must be removed before performing any through-tubing workover or wireline operations below the valve.
The tubing-retrievable model is more robust and offers a larger internal flow diameter. This helps eliminate turbulence and increases production capabilities. It also allows full-bore access to the tubing string below the valve. One disadvantage, in some instances, is its large OD. This may limit the size of tubing that can be run into certain sizes of casing. To service the tubing-retrievable SCSSV, the tubing string must be retrieved. To avoid this and extend the life of the completion, it is possible to disable the valve permanently by locking it open. A new wireline-retrievable SCSSV can be inserted into the sealbore of the retrievable valve, enabling the well to continue production without interruption.
- Subsurface Safety Systems Catalog. 1995. Baker Hughes Inc. BSS-2-10M-95118 Rev.9/95.
Noteworthy papers in OnePetro
Allen, T. and Roberts, A.P. 1993. Production Operations, fourth edition, I and II.
Factors and Conditions Which Cause Seal Assemblies Used in Downhole Enviornments to Get Stuck. Baker Oil Tools—Engineering Tech Data Paper No. CS007.
Patton, L.D. and Abbott, W.A. 1985. Well Completions and Workovers: The Systems Approach, second edition, 57–67. Dallas: Energy Publications.