Packer Accessories and tailpipe assembly

The Purpose of the Packer Accessories and tailpipe assembly is described in this article.

1. the ability to isolate the well below the packer;
2. the ability to land off downhole pressure and temperature gauges and redirect flow into the tailpipe higher up;
3. the ability to guide the exit from and retrieval into the tubing string of wireline tools;
4. the provision of seal bore and millout extensions as necessary.

Millout extensions

Installed directly below permanent packers to provide the required length and ID to accommodate standard milling tools.

Seal bore extensions

used for long seal assemblies to accommodate tubing movement.

If a polished bore receptacle completion is desired then there is no need for a tailpipe unless it is considered necessary to have a means of obtaining pressure isolation beneath the polished bore receptacle in the event of a workover or to allow retrievable downhole pressure and temperature gauges to be installed.

The height of the tailpipe above the perforated interval depends upon whether it is intended to run wireline surveys across the perforated interval. If downhole surveys are required the base of the tailpipe should be set 150 ft above the top perforations or alternatively 30 ft if no surveys are intended.

Normally if wireline work is envisaged a wireline entry guide (WEG) is installed at the base of the tailpipe. If a landing nipple for gauges is to be installed then a 30 ft pump joint is located above the WEG and above this the landing nipple and the perforated flow tube to allow fluid entry into the production string.

A lower tailpipe isolation nipple may be required to accept plugs to:

1. isolate production from the perforations;
2. allow pressure testing of the tubing;
3. allow setting of a hydraulic set packer.

If required the nipple will be installed above the perforated joint. If a selective nipple system is used and the well depth exceeds 7000 ft, a 30 ft pup joint would be located beneath this nipple. In addition, if a permanent packer is installed, a millout extension would be fitted. Finally if a locator seal assembly is to be used and an extended length seal bore is required, the sealbore extension would be fitted above the millout extension, beneath the packer.

Plugs

Packer plug, pump-out and push-out plugs are used to temporarily isolate the tubing. Both the pump-out and push-out plugs are run with the packer, while the packer plug can be set when the packer has been previously set and retrieved with a work string.

·The following equipment should be considered when running a permanent packer and tail pipe:

• wireline entry guide/mule shoe;
• landing nipple to land a plug;
• flow coupling directly above the landing nipple to safeguard the nipple against erosion failure;
• a tubing section to enable the tail pipe to be cut off should a plug become stuck in the landing nipple;
• a packer milling extension of approximately six feet to provide space for the catch sleeve of the milling tool.

The major operational requirements for well circulation are as follows:

1. Well kick-off or production initiation.
2. Well killing or the re-establishment of hydrostatic overbalance.
3. Chemical injection into the flow stream.
4. Gas lift.

Circulation equipment

A variety of devices and techniques are available to allow communication between the annulus and the tubing:

1. Sliding Side Door (SSD) or Sliding Sleeve (SS).
2. Side Pocket Mandrels (SPM) with shear or injection valve.
3. Ported nipple.
4. Exposed ports on extra long tubing seal receptacle after reciprocating seal receptacle.
5. Perforating or tubing punch.

The most commonly used circulation devices are the ported nipple, SPM and SSD. Difficulties experienced with well deviations and seal failure has led in considered cases to their elimination from completion strings, with dependence being placed on tubing punching or coiled tubing.

Landing nipples

The majority of wells will include at least one landing nipple in the completion string. This is usually a "no-go" nipple at the bottom of the well conduit (string), where it may be used for:

• preventing wireline tools larger than the "no-go" dimensions from passing below the tubing;
• permits recocking of hydraulic jars (jarring upwards);
• location of BHP gauges;
• location of plug for pressure testing conduit.

Additionally wireline nipples may be installed in a variety of other locations in the well conduit to offer the operational facilities, such as:

• Installation of SSSVs, chokes, etc.
• Landing nipples may incorporate ports to provide tubing/annulus communication. Flow through the ports is governed by wireline run tools (separation sleeves, side door chokes), which are landed and locked in the nipple profile.

Slip, packer and collar type lock mandrels may be used where no landing nipples are available, however, the permissible differential pressure needs to be carefully analysed.

The basic choice between nipple systems is whether a no-go or selective nipple design is chosen. If a no-go nipple system is used then its use is checked by reference to a production performance optimisation package to calculate the effect on pressure loss of the reduced bore of the no-go shoulder. If it represents a major restriction to flow, the installation of flow couplings around the nipple is recommended. The bore of the nipple selected must be smaller than the smallest nipple bore used higher up the string, e.g. there must be sequential nipple bore reduction.

If a selective nipple is considered, then it will offer the capability to set the nipple size equal to the minimum nipple bore used higher up the string. The major problems identified with selective nipples are:

1. In deep wells, e.g. greater than 7000 ft, cable stretch may pose a problem in identifying exact nipple locations. For such cases, a minimum nipple spacing of 30 ft is recommended.
2. The reliability of selective nipple operation is considered with the level of technical expertise of wireline crews with the system.

Gauges

Downhole data is required, to manage the reservoirs.

The permanent downhole gauges are principally targeted at subsea completions and other areas where well intervention to run static and flowing well surveys is economically prohibitive.

Conduit design considerations:

• permanent gauges vs. static/flowing well intervention surveys (equipment reviewed in Production Operations Well Services Guide, Well intervention activities - Document 2: Wireline operations);
• landing nipple requirements for flowing surveys vs. packer/collar/slip mandrels (Production Operations Well Services Guide, Well intervention activities - Document 2: Wireline operations);
• multiple completions vs. commingled with downhole flow meters.

A joint of tubing is usually run below the no-go landing nipple to protect the survey gauges.

Side Pocket Mandrels, SPMs

SPMs are fitted in the well conduit where it is necessary to install a valve that will provide communication between the tubing and the annulus. The valves may be installed/retrieved by wireline or coiled tubing techniques.

For chemical injection the normal technique is to use a SPM with an injection valve.

A V-shaped locator with a grooved extension provides for continued orientation while moving the kick-over tool with side-pocket equipment. Equipment entry into the side-pocket before the orienting finger leaves the groove provides optimum installation conditions.

Sliding Side Doors (SSDs)

Sliding sleeves (also referred to as Sliding Side Doors, SSDs) are part of the tubing string and provide communication between the well production conduit and various annulus Various applications include: fluid displacement; selective testing, treating or producing multiple zones; commingled production; well killing (by fluid circulation); kicking off wells (gas lift); pressure equalisation; ·chemical injection.

The sleeve within an SSD may be shifted by:

1. wireline methods;
2. coiled tubing methods;
3. pressure application to the tubing after dropping or running a shifting dart;
4. pressure application to the annulus

They may be selected in either the shift down to open or shift up to open versions.

Jar up to open sleeves, as opposed to jar down to open, have the advantage that a greater force can usually be exerted by upward jarring especially using hydraulic or spring jars. Downward jarring force, especially in deviated wells, is somewhat limited. Where a large differential pressure, annulus to tubing, is expected, down to open sleeves may be preferable, which place the tool below the communication port preventing tools being blown up the tubing.

Most sliding sleeves incorporate landing profiles, enabling a selection of control devices, including straddle tools to isolate a leaking sleeve, to be locked in.

The sliding side door is preferable to a ported nipple or a SPM if high circulation rates are required, e.g. well killing. However, the SSD should not be considered for use without careful analysis when:

1. CO 2 or H 2S is produced, as seal damage may occur.
2. If the temperature is greater than 225°F, whereby seal damage may occur.
3. In highly deviated wells where jarring may be difficult. In such cases a SPM may be preferred.

Do not install sliding sleeves opposite perforations unless it is unavoidable. Ensure there is at least 6 ft between blast joints and sliding sleeves.

Bottom hole chokes and regulators

There are usually wireline run/retrieved calibrated orifices to restrict fluid flow in the tubing. During the design stage appropriate landing nipples have to be selected and located for the installation of chokes and regulators to:

• reduce gas/oil ratio under certain conditions;
• prevent freezing of surface controls;
• prolong the flowing life of a well by maintaining bottom hole pressure;
• reduce water encroachment

Variable length joints

These can be of two types; one that is manually adjusted to help in spacing out, usually below packers in dual or triple completions, and one that allows limited tubing movement to facilitate making-up below multiple string packers and to allow for setting tandem hydrostatic packers.

Safety joints

These are used between packers in dual and triple completions and in selective completions using hydrostatic single-string packers. The shear pin safety joint is a device that enables stuck tubing to be sheared off, but because it introduces a weak point, its use should be restricted wherever possible.

Tubing cutters can be used to cut the tubing at any desired depth in most wells, but where sand production is a problem, possibly preventing the cutter reaching the desired depth, a safety joint could be considered.

Flow couplings and blast joints

These are important aspects of life-of-the-well completion planning. They are designed to inhibit the effects of corrosion/erosion caused by flow turbulence and jetting actions.

Flow couplings should be used in the tubing string of a flowing well to protect the tubing above and below turbulence-inducing equipment, such as safety valves, from the abrasive action of the turbulence. A flow coupling is, in effect, a length of tubing usually with enhanced wall thickness, the inner surface of which is specially hardened. In general the length is twenty times the inside diameter, although a minimum of 3 ft is recommended.

Blast joints are used in the tubing string opposite the perforations in producing zones where the jetting action of fluid can erode the outside of the tubing.

Extension of blast joints beyond the perforations should never be less than 8 ft downstream and 5 ft upstream of the flow direction.

Flow couplings should be considered in high rate gas wells above and below completion accessories which restrict the tubing or induce turbulence, such as SSSVs and side pocket mandrels (SPMs).

Wing guide subs

They are used to centralise blast joints in the casing, particularly in deviated wells. They should be installed at least every 40 ft (12 m) (or part of 40 ft) of the blast joints.

Wireline entry guides and tubing shoes

Tubing shoes (or "mule" shoes) are short, cut-away lengths of tubing fitted to the bottom end of a tubing string to facilitate stabbing into a packer or packers. The outside should be barrel shaped to aid entry into the packer bore and to prevent hold-ups when running, and the inside bottom edge should be chamfered to aid wireline re-entry. When the tubing string is stepped down in diameter below the packer, some form of centraliser(s) should be fitted to, or near the shoe, especially in deviated wells.

When selecting the type of guide to be used, remember to think about the equipment that may have to pass through the guide during the life of the well.

Magnetic Fluid Conditioner (MFC)

This tool is designed specifically to eliminate or reduce paraffin (wax) and scale. The magnetic flux created by the tool, located within the well conduit near the reservoir, conditions the produced fluids such that scale and wax do not form within the tubing.

Reported benefits include:

• reduced paraffin and scale deposition/deposits;
• reduces corrosion;
• reduces pour point;
• reduces viscosity and yield point.

Permanent Downhole Gauge (PDG) and systems

A number of manufacturers/supplies can now offer PDG systems. The systems vary depending on the application (e.g. fibre optic system, retrievable sensors, etc.) and overall requirements (e.g. reservoir management, ESP control, flow control, etc.). Reliability of PDG systems is a concern (75% probability of surviving for five years after installation, most failure occuring immediately after installation).

Perforations

The distance between the closest perforations of adjacent zones should preferably be more than 30 ft, to allow for packer, packer accessories and blast joint positioning.

Minimum distance between equipment

• Between sliding sleeves/packer setting sleeves: one joint of tubing
• Between two sliding sleeves: (30 ft)
• Between blast joints/packer setting sleeves: 6 ft
• Between sliding sleeves/no-go nipples: 6 ft

Experienced and competent wireline operators should be capable of locating a landing nipple within 0.1 to 0.2% of its actual depth. The minimum recommended distance between landing nipples, therefore is:

• Depths to 10,000 ft: 15 ft
• Depths from 10,000 to 15,000 ft: 25 ft

Example of completion design

7" tubing, utilised to minimise pressure drop, reduces the number of wells required and defers compression. Low fluid velocities minimise potential erosion/corrosion problems at high flow rates.

4" tailpipe permits all wireline work to be conducted through safety valves (7" size tubing string).

Continuous corrosion inhibition is provided through injection points as deep in the well as possible.

Special 13% Cr tubing is utilised where severe corrosion is expected, i.e. in 4" tubing tailpipe sections and above safety valves.

Tubing is landed in tension to prevent buckling in the reduced diameter section.

Premium thread VAM tubing is selected to provide a metal-to-metal gas-tight seal, with a 95/8" production casing also using a metal-to-metal seal premium thread.

The 13% Cr tubing has couplings specially copper plated to minimise any galling tendency.

All wireline accessories are 9 Cr-1 Mo to prevent corrosion.

A Baker wireline entry guide (mule shoe) permits safe re-entry of wireline tools run below.

An 'R' as opposed to 'RN' type nipple gives large through-bore for logging or through-tubing perforating.

An 'R' nipple provides a facility for setting a plug prior to pulling tubing and for landing Ameradas for pressure surveys.

One joint of tubing below the 'R' nipple protects Ameradas during surveys.

'RD' as opposed to 'RO' sliding sleeves are selected because of the increased port area.

The lower sliding sleeve provides an alternative flow path if the plug becomes stuck in the 'R' nipple. The upper sliding sleeve gives a large port area for routine well killing. It is positioned above the chemical injection side-pocket mandrel to avoid corrosion and inhibitor deposits in the annulus.

A Baker 'SAB' packer is used as it is the hydraulically set equivalent of the model 'D' already in use, and simplifies setting tubing in tension. The bottle assembly below the packer permits pulling of the packer.

The packer is set in 95/8" casing as it backs-up liner lap. A contingency completion with the addition of a 7" 'SAB' packer and anchor latch permits the liner lap to be straddled.

A side-pocket mandrel with shear disc permits non-routine well killing.

A specially-designed streamlined crossover from 7" to 4" is used to prevent wireline tool hang-up or completion hold-up during running.

Flow couplings are used at points of turbulence.

A wireline retrievable SCSSV is installed below the predicted crater depth.

Tension type tubing hanger is used to permit tubing to be hung off in tension.

The control line outlet via the tubing hanger pack-off avoids having to orientate the tubing hanger.

A stainless steel trim, solid block Xmas tree is employed to combat corrosion.

The upper master valve is fitted with a Baker 'CAC' actuator to provided a wireline cutting capability.

The tubing is latched into a permanent packer and pulled into tension eliminating the need for dynamic seals.

Although the H2S partial pressure is below the critical value, materials in the completion string have Rockwell C hardness between 18 and 23.

The tubing collapse resistance exceeds the worst design case by factor of 1.1 (tubing pressure zero, annulus liquid filled, plus maximum surface casing head pressure).

The tubing burst resistance exceeds the worst design case (well killing) by a factor of 1.6.

Note that this design could be challenged, for example, why not a monobore completion, why not 13 Cr tubulars to surface, what type of VAM connection, etc.