The designer must ensure that there is critical flow through the choke in order to eliminate the effects of downstream pressure variations on the formation. This is achieved when the FTHP is approximately 1.7 times the downstream flowline pressure.

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Tubing movement and stress behaviour are a function of the well temperatures and pressures: The changes in temperature will cause the tubing to expand and contract.

For example, 10,000 ft of tubing suspended in a well will shorten by 16.6 inches with a temperature drop of 20°F. Pressures inside and outside the tubing above the packer act on the differential areas, changing the tubing length according to Hooke's law. The differential pressures between the inside and outside acting on the cross-sectional area of the packer bore at the tubing seal causes helical buckling. The pressure differential between the inside and outside of the tubing has a balancing effect. The tubing diameter increases as the internal pressure exceeds the external pressure, the result is that the tubing length decreases. The opposite is true if the annulus pressure exceeds the tubing pressure.

If tubing movement is restricted, compensating forces will be generated in the tubing string.

If tensile stress is high, consider using latched packers to carry some of the load. If compressive stress is high, pull tension at tubing hanger, or use moving seal assemblies with packer so that tubing is always in tension.

Tubing Movement compensation

Two methods are generally used

1. Landing the tubing in tension/compression: This method is limited by material strength. Landing and spacing procedure is critical and often difficult achieve.
2. Allowing free movement of subsurface seals: Locator tubing seal assemblies and seal receptacles can compensate for length changes. Ensure that the sealing elements do not leave the polished bore or mandrel. Landing and spacing is less critical.

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.

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.

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The sand production philosophy for a particular field and production system must be formulated after careful evaluation of a number of interacting factors which range from the well and surface facilities design to the operating procedures for the production system.

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This article describes the Standard Completion Designs.

Monobore completion

Completion with fullbore access across the payzone, without diameter restrictions (but not necessarily with a constant diameter from top to bottom). The monobore concept optimises the opportunity for well intervention through the Xmas tree, i.e. rig-less, and is applicable to any completion diameter. By working through the Xmas tree, many well intervention operations can be conducted without the need to kill the well and pull the tubing string.

Coiled tubing completion

The development of larger sizes of coiled tubing have increased the application and development of coiled tubing completions and associated hardware accessories, such as Gas Lift Mandrels which can be spooled. The main advantage over conventional tubing is that it can be run quickly into the well without having to make up or break tubing joints and hung off under live well conditions.

Wellhead splitter system

This system allows more than one well to be drilled from a single wellbore with multiple surface, intermediate, and production casing and tubing strings. The Downhole Splitter System is essentially the same as the surface splitter, allowing drilling, casing, and completing more than one well from a single conductor. In both cases each well is independent for service and workover requirements.

Early planning of artificial lift is essential for long-term profitability of the wells. Decisions on the artificial lift method to be used may not be available at the field development planning stage.

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This article describe the completion packer selection, specifications, classification, setting mechanism, etc.

Packer selection/specification

packer selection must take into account:

• type of hole: open, cased, liner completed;
• type of well: producing, appraisal, injection;
• well content: oil, gas (sweet, sour), water, steam, abrasive material;
• natural well pressure: high, low, flowing, shut-in - in the tubing;
• imposed well pressure: high, low - in the annulus - especially during completion pressure testing;
• well temperature: flowing, shut-in - range of temperature changes;
• vertical: straight, deviated - small angle, large angle; ·production method: natural flow, gas lift, pump;
• drawdown rate: high, low;
• completion method: tubing latched in tension, setdown in compression, multiple straddle pack, tailpipe, extension required below packer;
• tubing hanger design: suitable for packer setting/releasing method;
• minimum bore: ability to pass tools and equipment required further downhole;
• packer function: annulus/tubing isolation, zone isolation, damage straddling, cement squeezing;
• also to be taken into consideration are the pressure and temperature changes, especially during stimulation operations;
• casing damage caused by the slips;
• hang-off requirements (tailpipe assembly).

Packer classification

Retrievable:

The packer is run as an integral part of the tubing. Except for the retrievable bridge plug, the tubing cannot be pulled without pulling the packer. The packer is set mechanically, hydraulically or a combination of both. It is released by manipulation of the tubing, either rotating or pulling (shearing lock pins). Generally used where the well may have to be worked over regularly (i.e. electrical submersible pump applications), temporary completions (i.e. production testing) or well intervention activities (i.e. stimulation or casing leak detection).

·The following aspects need to be considered when running retrievable packers:

-pulling the packer out of the well may swab the well in;

-equalisation of pressure across the packer before pulling may be difficult (care should be exercised on shallow set during unseating operations);

-straight pull release packers may prematurely shear and release due to tubing contraction;

-deposits above the packer may render it non-retrievable.

Permanent:

The packer is set within the casing and the setting mechanism (tubing/wireline) can be released from the packer. Except for the case of a permanent bridge plug the tubing can be run and resealed in the packer. The packer may be set mechanically (by tubing), hydraulically or electrically (by wireline). As the name implies it cannot be retrieved, but can be destructively removed (i.e. milling). generally used in high pressure differential applications.

·Permanent/Retrievable: This class of packer combines the advantages of the permanent packer (i.e. large bore, withstands higher pressure differentials etc.) but when required can be released and recovered, entire, from the well.

In general, a permanent packer will be selected if:

·the predicted maximum differential pressure across the packer exceeds 5000 psi;

·the temperature at setting depth exceeds 225°F;

·H2S is present and the temperature at the packer is less than 160°F;

·infrequent workovers are envisaged.

Otherwise a retrievable packer may be recommended.

Packer setting

Mechanically

The packer may be set by one or combination of: ·rotation (standard 'J' slot latch arrangement); ·compression (slacking of the tubing weight into the packer; ·tension (pulling, overweight, up on the packer).

Hydraulically

The packer is set by applying pressure to the tubing so as to cause a pressure differential between the tubing and annulus. Commonly used in deep or highly deviated wells, or offshore environments when the platform motion plays a significant role. It is also a consideration if control lines are used with the subsurface safety valve or permanent downhole monitoring applications.

Electrically

The packer is set by a setting tool on electric wireline (wireline set). The wireline setting tool is released and recovered with the wireline. This method is more commonly employed for setting bridge plugs or when the exact location of the packer is critical.

Packer bore

·No bore - bridge plugs. To isolate the casing or tubing. Sometimes referred as cement retainers.

·Single bore - for use with a single conduit.

·Dual bore - for use with two conduits in dual completions.

Packer forces

There are two prime forces acting on a packer:

·hydraulic pressure forces (differential pressure acting )

·tubing-to-packer forces.

The tubing-to-packer forces need to be calculated at the design stage.

Force needed to prevent unseating. Permanent packers will withstand pressure differentials from above and below. Retrievable packers may be either compression set, tension set or both.

The assumptions and actual tubing set-down force need to be documented to prevent mishaps during subsequent well intervention activities

Operating envelopes (safe performance window)

The permanent packer rating envelope is a means of describing the functional limits of a packer under combined pressure and applied axial (tensile/compressive) loading. When requesting an envelope for a permanent packer, specify the packer model, size, material and casing size. The ratings derived from envelope graphs are for unplugged packers. Plugged packer ratings can be significantly lower.

Recommendations

• ·Select a packer with element metal shoe and shoe support systems (metallic back-up rings) in high-pressure applications to provide anti-extrusion back-up for the elements.
• ·Typical packer element combination is a 90-70-90 Schure hardness combination.

Schure hardness is a rating system to determine the suitability of rubber to a pressure environment. The higher the number, the greater the hardness and the more suitable for use with higher pressures. The hardness rating system is used for 'O'rings, stripper rubbers and packer elements.

• ·No 'O'-rings.

This article describe the categories and types of seals used for completion equipment.

2 categories of seals:

• static seals where the sealing surfaces do not move relative to one another,
• dynamic seals where the sealing surfaces do move relative to one another.

3 types of seals:

• polymeric or resilient seals. Which are either elastomeric (natural or synthetic rubbers) or plastomeric e.g. Teflon.
• metal-to-metal seals.
• metal encapsulated polymeric seals (combination of the first two types).

1. Polymeric/ Resilient seals

• O-ring: The workhorse, self energised, static conditions
• T-seal: Self energised, with anti-extrusion rings for HTHP and for dynamic applications.
• V- seal: Chevron ring with self energising lip-seals, used in stacks and supported by back-up elements.

Polymeric seals: Nitrile, Viton, Aflas, Chemraz, Peek, Teflon.Functional requirements should include the well conditions (temperature, pressure, well liquids & gases), the seal seat design, the mechanical requirements, the required life and the compatibility with chemicals to be used used.

Nitrile

The first material to be considered is the nitrile compound. This has been a workhorse for the oil and gas industry for a long time. Nitrile rubber is a copolymer of a diene and an unsaturated nitrile.

Nitrile elastomers can be used over a temperature range of -20°F (-28.9°C) to 450°F (232°C) depending on the application. Special compounding must be done for low temperature service. For use as O-rings or other seals that might have movement, the upper temperature limit is 275°F (135°C).

Nitrile elastomers are subject to swelling if used in the presence of aromatic fluids such as toluene or xylene. The swell is usually in excess of 25%. These elastomers are also affected by heavy fluids such as zinc bromide and calcium bromide. Also, nitrile cannot be used as an active seal where H2S is present.

Viton

The fluorocarbon elastomer, better known as Viton, isused extensively in downhole equipment. This elastomer is made up of vinylidene fluoride and hexafluropropylene. Fluorine-containing polymers have long been known for their outstanding resistance to hostile environments. Of the many fluoropolymers available, the fluorocarbon elastomer has played an important role in the oil and gas industry.

Fluorocarbon elastomers perform adequately in sour environments. The sour fluids or gases could contain such materials as carbon dioxide and methane. When dealing with this type of fluid or gas, the elastomer must be selected on the basis of how all the compounding ingredients will affect the seal. Nitrile would have a somewhat lower interaction with CO2, however, nitrile cannot be used because of the H2S present.

If organic amine corrosion inhibitors are going to be used in the well, then Viton is not recommended for seals such as O-rings, Vee-rings or other type seals where there is a possibility of seal movement. Amines were one of the first curing systems used, therefore, the inhibitor continues to cure the material until it becomes hard and brittle. The rate of reaction is dependent on concentration of the inhibitor, the pH of the solution and temperature. Actual field data indicates damage to this elastomer can occur when the temperature is as low as 190°F (88°C) and the concentration of inhibitor is 0.5%.

·Viton is the registered trademark of DuPont Company.

Aflas

Aflas is a copolymer of propylene and tetrafluoroethylene. Aflas elastomers can be used in sour environments as well as those conditions where organic amine corrosion inhibitors are used. This compound has been tested in organic-amine-corrosion inhibitors at 330°F (165.6°C) in a 10% solution of both water-soluble and oil-soluble inhibitors. No cracks were evident in this compound, however, cracks were observed in the Viton compound when tested under the same conditions.

Company does not recommend use of Aflas where temperatures are expected to be below 100°F (37.8°C). Tests conducted at low temperatures along with field experience have shown Aflas is subject to sealing problems.

·Aflas is the registered trademark of Asahi Glass Company, Inc.

Chemraz

Chemraz is a member of the perfluoroelastomer polymer family of which Kalrez® is in this same family. Chemraz is molded of an elastomer that has the broadest chemical resistance of any elastomeric material. Chemraz combines the resilience and sealing force of an elastomer with chemical resistance approaching that of Teflon.

Chemraz resists attack by nearly all chemical regents, including inorganic and organic acids, alkalines, ketones, esters, aldehydes, alcohols and fuels. As a result they provide long-term service in virtually any chemical and petrochemical process streams, including many where additives or impurities cause other elastomers to degrade or swell.

Tests have indicated that at low temperatures, below 40°F this particular material is not recommended.

·Chemraz is the registered trademark of Green-Tweed & Co., Inc.

PEEK

Polyetheretherkestone (PEEK) is a high temperature, crystalline aromatic polymer. The armoatic structure of this material is responsible for its performance at high temperature and in chemically hostile environments. This material is excellent for deep, hot, sour oil and gas wells. It can be used as back-up rings for O-rings and Vee-packing. This material offers a unique combination of properties with outstanding thermal characteristics and resistance to an extraordinarily wide range of solvents and proprietary fluids.

·PEEK is the registered trademark of ICI Americas

Ryton

Polyphenylene Sulfide (Ryton) can be compounded with a variety of materials to reduce the brittle nature of the Ryton and to improve the sealability of the compounds. The material has been used as back-up ring for Vee-packing and O-rings. Certain combinations of Ryton and other materials alter the brittle properties of Ryton and make it suitable for vee-ring seals at high temperature and pressure. Ryton can be used in temperatures to 450°F (232.2°C) and in pressures to 10,000 psi.

·Ryton is the registered trademark of Phillips Petroleum Company

Teflon

Other non-elastomer materials used in downhole applications are glass and molybdenum-disulfide-filled teflon. These materials can be used as primary seals when backed up by a harder material such as PEEK or Ryton.

Chemical resistance

The resistance to a range of relevant chemicals such as inhibitors, completion fluids, acids, CO2 and H2S has to be considered. Fluids which are present only during a short time interval may get trapped in the confined space of the seal seat, leading to a long time or even continuous exposure of the seal.

Mechanical properties

The polymer grade is finally selected by comparing the mechanical properties of the different grades with the mechanical requirements for the application (considering service pressure, pressure differentials, extrusion gap, dynamic requirements etc.).

2. Metal-to-metal seals

Metal seals are different from resilient seals in that they cannot easily flow into and fill the roughness between the mating surfaces to prevent fluid passage. They require a much higher contact pressure than resilient seals and it is found that contact pressures that produce only elastic deformation of the contact area do not suffice to establish a gas tight seal in a "dry" state. Seals that are wetted by a liquid film provide better sealing performance and the viscosity of the liquid plays an important role.

Static metal-to-metal seals can be energised to such an extent that they develop a high contact pressure, capable of providing bubble tight gas sealing. With dynamic metal seals permanent deformation of the metal seal contact surfaces is not acceptable. Hence, bubble tight gas sealing of metal dynamic seals that are not wetted with a liquid film seems to be a utopia.

3. Comparison Polymeric seals /metal seals

Polymeric seals

• needs a lower contact pressure to establish a reliable seal.
• Perfect sealing (bubble tight) can be achieved, even when used for dynamic applications.
• Polymeric, especially elastomeric, seals are very forgiving of manufacturing olerances and can cope to some extent with seal surface damage or wear.
• Handling and assembly precautions are not too critical.
• Dynamic seals made of polymeric material can cope better with water-based luids and are more forgiving on the requirement for fluid cleanliness than metal seals.
• Economically more attractive.

Metal seals

• better suited to high temperature and/or high pressure conditions.
• more resistant to chemical attack, for instance from well effluents with H2S and CO2, or from well treatments with Amine-based fluids.
• not effected by rapid gas decompression.
• do not suffer from creep or stress relaxation.
• Frictional behaviour is more constant and easy to predict.
• withstand greater forces.

4. Seal behaviour

Plastomeric seals or metal encapsulated polymeric seals act on plastic deformation and can also deform the confining interface (usually the grooves). When this occurs the space to be sealed is enlarged thereby decreasing the pressure rating of the assembly and also the bolt fatigue life. For example, flat washer-like seals are severely affected by the conditions described above.

Shallow tapered seals are being used successfully in the subsea environment: AX new style, CX, DX, FX, Grayloc, KX, NX, VX and VGX. In these seals, the separation forces are reduced as the seal circle is a minimum; closer to the parallel bore. The exception is CX, where to prevent key seating, the seal circle is larger.

To prevent buckling and cocking of the seal a centralising belt is necessary. This belt functions as the load flank (inner flank) of the API ring groove.

5. Seal selection criteria

In the selection of seals the following aspects should be considered:

• the most important function of a seal is that it should only seal;
• the seal should only be exposed to fluids, pressures and temperatures and not to load transfer, separation forces, bending moments and shear forces; such forces should be taken by the geometry of the connection.

The following API gaskets are examples of bad seal design:

• R. Which causes clear flange stand-off;
• RX and BX. Experience has revealed that these seals seldom achieve flange face to face contact.

These API gaskets transfer loads, align the mating members, provide shear resistance, are plastically deformed, and are often harder than the non-repairable confining groove, which will consequently be deformed. A typical example is groove deformation of the dual tree tops.

Zero flange stand-off has been proven impossible. Statements in vendor catalogues that they can achieve this should be examined closely and not automatically accepted.

6. Seal energisation

It must be possible for seals to be tested, and, as a consequence of this, they must also be re-energisable and/or retrievable. This is, however, not a feature that can be expected of integral hanger seals. The casing hangers can only be retrieved by splitting the casing, and the tubing hanger retrieved only after removing the entire tubing. Therefore it is recommended for all pack-offs to be retrievable without having to pull the confining strings. The present BRX seal and Gray's tubing hanger seal are, therefore, suboptimal on practical grounds.

Re-energisation can be achieved through reload. Torque, weight, and radial energisation are the most common energising methods. Of these, radial energisation is the most precise method, but also the method in which machining tolerances are more critical. All other methods rely on excessive force and unpredictable friction.

A good seal removes the necessity for re-energisation. However, some seals need re-energisation, either through plastic injection or through tie-down screws, which results in undesirable penetrations in the pressure vessel.

The use of elastomer in seals has its limitations:

• maximum pressure of 30,000 to 40,000 kPa (4000 to 6000 psi) depending on containment;
• maximum temperature of 200°C (400°F) for fluor elastomers with the right carbon black and particle size, and 150°C (300°F) for nitriles;
• incompatibility with H2S, CO2 and amines;
• explosive decompression;
• fatigue life;
• wear;
• friction;
• erratic energising behaviour. For example nitrile rubber behaves like a fluid under heavy pressure and as a solid under low temperatures. This has created many deformed casings which precluded access to the well bore.

7. Testing, field experience & seal design and development

It should be pointed out that for demanding applications, the suitability of a certain seal design combined with a seal material should be tested under realistic conditions or should be proven by field experience. Laboratory tests in some cases can under estimate the severity of the application, while in other cases the tests are over-conservative (e.g. swelling in immersion tests). As improvement in a certain property of the polymeric seal (by selecting another polymer or by additives) often leads to a reduction in other important properties, seal development requires careful attention. Applying a seal seat design, developed for more moderate service, in HTHP operations, may lead to unrealistic requirements being placed upon the seal material. Therefore, changing the seal seat design (e.g. reducing the extrusion gap to 0.1 mm or smaller or application of an anti-extrusion ring) should be considered, as it is often easier to adapt the metallic seat than to find a better elastomeric seal material.

This article describes the Completion design considerations.

Reservoir considerations

Reservoir drive mechanism may determine whether or not the completion interval will have to be adjusted as gas-oil or water-oil contacts move. A water drive situation may indicate water production problems. Dissolved gas drive will result in pressure depletion and may indicate artificial lift. Dissolved gas and gas drive reservoirs usually mean declining productivity index and increasing gas-oil ratio.

Secondary recovery needs may require a completion method conducive to selective injection or production. Water flooding may increase volumes of fluid to be handled. High temperature recovery processes may require special casing and casing cementing materials.

Stimulation may require special perforating patterns to permit zone isolation, perhaps adaptability to high pressure and/or injection rates, and a well hook-up such that, after the treatment, the zone can be returned to production without contact with kill fluids.

Sand control problems alone may dictate the type of completion method and maximum production rates. On the other hand, reservoir fluid control problems may dictate that a less than desirable type of sand control be used (e.g. a resin consolidation process rather than a gravel pack to facilitate inflow profile, hence, GOR control).

Multiple reservoirs penetrated by a well pose the question of single or multiple (selective or commingled production) completions and often dictate a completion conducive to wireline or through-tubing type recompletion systems to simplify and reduce workover frequency and cost.

Artificial lift may mean single completions even where multiple zones exist, in addition to using larger tubulars than would be needed for natural flow.

Drilling and completion process considerations

• Minimise or eliminate formation damage, i.e. underbalanced operations.
• Poor quality cementations can lead to annulus pressures and loss of well integrity.

Casing design

The casing design should specify the minimum casing diameter and the maximum casing shoe setting depth for all strings.

The inflow system

The interface between producing formation and wellbore/producing conduit defines the inflow system of the well completion.

The outflow system

The well outflow system defines the flow path within the well completion, from inflow element within the production casing/liner to surface. It includes the tubing, tubing accessories, safety devices, artificial lift or pressure boosting facilities (within the well) and Xmas tree. This will determine the maximum production/injection rate.

Selection and specification

• type of well
• design life
• well configuration
• reservoir
• operating conditions
• artificial lift requirements
• well intervention techniques
• equipment features
• equipment housing
• valve/packer and equalising systems
• hydraulic actuation systems
• lock-open and insert systems
• development status
• field experience

Standards and quality

API and ISO specifications

Safety aspects

Where it is possible for equipment to have a fail-safe capacity, such as subsurface safety valves, this feature should be specified.

The degree of well protection required is determined by the following factors:

• production potential of well
• the potential danger to life, the environment, equipment and reservoir
• the probability of loss of control occurring
• the ease and cost with which control can be restored.

Well killing philosophy

Potential problems should be identified, and the findings incorporated in the well design. Design considerations should include:

• ·Kill method. Bullhead (minimising the requirements for downhole communication devices, and hence potential leak paths, or reverse circulation (minimising potential damage to the formation).
• ·Requirement for permanent facilities, i.e. provision of a kill valve or kill connection at the wellhead. Offshore, permanent pipework from the well to a kill facility/boat deck connection may be necessary.

Annulus/tubing seals

Apart from the tubing head and the integrity of the tubing and connections, sealing between the casing and tubing rests with the packer and the sealing elements in such equipment as anchor seals, locator seals, telescopic/swivel/travel joints, tubing seal receptacles and sliding sleeves.

A packer is a subsurface tool used to provide a seal between the tubing and the casing (or wall) of a well and is generally located immediately above the reservoir concerned. This seal prevents vertical movement of fluids in the annulus, and thus provides a means of production control.

Seal elements can be in the form of 'O'-ring moulded elastomer seals or chevron seals ('V'-packing).

In gas wells with low differential pressure across the packer, the use of moulded seals on anchor seal assemblies is generally recommended, but these seals are made of Hycar and should not be used in high condensate ratio wells. Moulded seals should not be used on dynamic seal assemblies.

Consideration must also be given to the question of stabbing downhole, whether it is more desirable to stab:

• a component with external seals into a polished bore receptacle, or
• a component with internal seals over a polished mandrel.

Circulation and communication devices

Circulation and communication devices include sliding sleeves, side-pocket mandrels and ported nipples. Both side-pocket mandrels and ported nipples require insertion of a valve or other device before they become operational. These should be selected for their specific function, and whether they are used for automatic (usually pressure) or wireline operation.

Side-pocket and ported nipple equipment have the advantage that the elastomer can be retrieved and replaced with the sleeve/valve by wireline methods.

Where practical, corrosion resistant (CRA) alloys instead of chemical injection. The simpler the design the less well intervention requirements.

Tubing

The selection of a tubing string requires the specification of:

• material selection
• thread/connection type
• operational parameters
• dimensions.

A number of computer-based packages have been developed to allow optimisation of the tubing size selection and configuration based upon matching the inflow and tubing performance relationships.

Blast joints are universally recognised for protection from external erosion.

Flow couplings above and below turbulence-inducing equipment can reduce the rate of internal erosion

13 Cr materials are more susceptible to HCl corrosion, and inhibitors used for carbon steel tubulars are not effective on stainless steel tubulars.

Used with permanent type packers to provide isolation between the producing zone and the annular space above the packer when the tubing is located into the packer.

The seal assemblies are designed with external seals on the tubing which pack-off in the polished bore of the packer or a packer extension (used to retain the same packer bore diameter as the tubing). Basic seal units include two seal stacks, but any number of seal units can be screwed together to increase the length of the assemblies.

Types of assemblies

Locator seal assemblies:

The tubing locator seal assembly does not lock into the packer. The tubing string can't be landed in tension except that of its own weight, however, the tubing can be landed with setdown weight. Careful calculation is required to ensure that with maximum shortening the seal remains in the packer bore. Tubing expansion above the original design estimate is liable to cause buckling.

Anchor seal assemblies:

The anchor tubing seal assembly is latched to the packer. the string can be landed in tension to take up expansion during production. helical buckling is prevented if sufficient tension is pulled. The risk of leakage is reduced.

Latching the tubing can produce problems in tubing recovery (deviated holes, corrosive wells, production zone above the packer, solids settlement in annulus) If packer fluid is used with latched tubing, a solids-free fluid should be used.

Stingers:

used with the hydraulically set, single string permanent packer.

Seal nipple assemblies:

normally used as the method of sealing the production tubing at the lowest of two or more seal bore packers, set one above the other in the well bore. Since the seal nipple does not have a locating shoulder, it can pass through the seal bore in the upper packer and seal in the lower packer. It can be spaced out such that as it seals in the lower packer, an anchor seal or locator seal assembly can be landed in the upper packer.

Polished Bore Receptacle (PBR):

This is frequently used for wells where a production liner has been installed whereby the production tubing can be run and located in a seal bore at the top of the liner. It offers a simple and cheap completion technique but the seals may be prone to damage from solids settling out of the fluid in the annulus and to be a safe completion it requires an effective cement bond in the liner lap region to provide fluid isolation.

Installing a moving or dynamic seal assembly is dictated by the predicted maximum string movement and its ability to tolerate the stresses.

For cases where the triaxial stress/tubing movement is small a number of alternatives are feasible:

1. use an anchor seal assembly whereby a static seal is inserted into the packer bore;
2. use production tubing of increased wall thickness or tensile strength and higher strength tubing couplings;
3. if the tubing movement is less than 2 ft, use can be made of a telescopic joint.

If the above alternatives are not viable, or if the predicted tubing movement and stress are too great, a dynamic seal assembly will be required.

Recommendations

The selection is influenced by past equipment records (seal durability and reliability), by the extent to which the running and retrieval of the string is affected by the incorporation of the seal assembly. For example the polished bore receptacle and locator seal assembly both have the advantage of theoretically being easily retrievable, although operators have reported seal sticking after extended periods of installation. However, since it is the moving seal system which has to be run into the seal bore during installation, the possibility of seal damage must be considered.

This article descirbes the Tubing and Casing Connections Functional and Operational requirements.

Functional requirements:

- strength -sealing properties, -resistance to damage, corrosion or erosion.

Operational requirements:

-easy to make-up and break-out in the field (e.g. handling, stabbing, testing, etc); -reusable;

Connection types

For low pressure wells API 8RD thread connections have been the standard in the tubing strings. Non upset has proved more effective than upset (EUE) 8 RD tubing.

Connections provided with metal-to-metal seals are commonly referred to as Premium connections.

Threaded connections can be divided in two groups, namely the integral connections and the threaded and coupled connections. Each group can further be divided into several types, depending on the sealing mechanism and the existence of a torque shoulder

Integral connection

The geometry of the pipe ends are different so that they can be connected without using an intermediate part. Two types of integral connections are common:

·Upset type connection: this type of connection has pipe ends with an increased wall thickness. The pipe may be externally upset, internally upset or both.

·Non-upset or flush type connection: this type of connection has pipe ends with OD and ID close to the pipe.

-Integral connections halve the number of threaded connections, and thus the number of potential leakage paths.

-There is no possibility of receiving a coupling made of a different, and thus wrong, material.

-In general, the integral type of connection has a higher torque capacity than the threaded and coupled connection. Designed with an external torque shoulder, while most threaded and coupled connections have the torque shoulder is located at the pin nose.

-There is a risk corrosion (ringwork) at the upset region of joints in the presence of CO2.

Threaded and coupled connection

The joint is externally threaded on both ends of the pipe. The single joints are joined by an internally threaded coupling, to form the connection.

Comparison of integral and threaded/coupled connections

In recent years there has been a move away from integral type connections, towards the use of threaded and coupled connections.

-Threaded and coupled connections are generally cheaper to produce and the pipe ends can be re-cut should the threads be damaged.

-The manufacturing process of threaded and coupled connections is a lot simpler than that of integral connections as no upsetting or swaging is required.

- Less risk of leakage due to geometric errors in the machined connection parts

Thread forms

·API round type thread, a tapered thread with stabbing and loading flanks of 30° and rounded crests and roots

·API buttress type thread, a tapered thread with stabbing and loading flanks of 10° and 3° respectively, and flat crests and roots, parallel to the thread cone.

·Modified buttress threads, used for Premium connections.

Connection sealing

Threaded connections utilise three basic mechanisms to establish a leak tight joint.

·tapered interference fit thread seal (API)

·metal-to-metal seal (premium)

·resilient seal (semi-premium)

Tapered interference-fit thread seal

Tapered interference fit thread seals, such as the API round and API buttress threads, are not inherently leak tight, but have helical leak paths included in the design. Leak tightness of these connections is thus obtained by establishing a high contact pressure on the thread flanks and sealing the remaining leak path(s) with a thread compound.

Metal-to-metal seal

Sealing relies on metal-to-metal contact between the two mating sealing surfaces from both pin and box. Therefore, the thread itself does not have a primary sealing function but serves to transmit externally applied loads. At the sealing contact area the surfaces will deform elastically, so as to be able to seal under changing loads without having a permanently deformed seal.

Resilient seal

The API round and API buttress thread connections as well as the Premium connections can all be applied with an additional seal made from polymeric material. Generally employed is Teflon. The property of the material will tend to change with the time.

Do not use the same seal ring twice.

Testing and qualification

The tests to be performed simulate the load conditions which can be imposed on connections during service:

• repeated make-up and break-out tests at various make-up specifications;
• internal pressure sealing tests under different combinations of loading;
• internal pressure sealing tests during thermal cycling;
• external pressure sealing tests under axial loading;
• tensile or burst tests to failure.

Operational considerations

• in all offshore wells, in deep or high pressure land wells and in all gas wells, use Premium connections, i.e. metal-to-metal seals;
• in corrosive conditions, give preference to non-upset internal flush connections;
• where space is at a premium, consider using integral joint tubing;
• synthetic seal joint rings (usually Teflon) can be used for extremely high gas pressure, and should be replaced every time the joint is broken;
• for onshore low pressure wells (flowing, gas lifting, pumping) API EUE is recommended. For gas and gas/condensate wells, all the previously mentioned connections with the exception of API EUE and Hydril A95 are recommended. Non-upset API tubing is not recommended for heavily loaded pumping wells.

Material selection is determined by the abrasion and corrosion properties of the fluid, the pressures and the mechanical and hydraulic loadings on the completion string under operating conditions, e.g. stimulation, injection and production conditions.

Read more …

When specifying or designing valves, reference should be made to the Operating parameters for that particular well. All valves purchased must at least meet the standards set in API 6A PSL 1, 2, 3 or 4 and in several areas must exceed those standards. Cases where the standards are exceeded are specialised exceptional cases. The preferred route is to purchase to API 6A latest edition at the PSL-3, PR-2 level.

Read more …

The well completion typically includes the perforations, sand exclusion system, (liner), tubing, wellhead, tubing accessories, packers, associated safety equipment and Xmas tree.

The perforations, gravel pack etc. provide the 'inflow system' into the well structure, while the tubing with flow controls, safety devices for isolating the reservoir, the Xmas tree and, where necessary, artificial lift or pressure boosting facilities, provide the 'outflow system' (well conduit) within the well structure.

1. General completion design considerations

Well and completion design must take into consideration the following requirements:

• artificial lift needs
• well service/maintenance options.
• reservoir: fluid volumes, sand exclusion, number of zones, stimulation requirements, etc.
• future requirements: secondary recovery, injector, etc.
• operating conditions: pressure/temperature, corrosion, scale, wax, etc.
• government legislation: safety requirements, annulus vent/flare restrictions (downhole gas separation), etc.
• surface facility constraints: pipelines, process equipment, etc.
• company safety and environmental considerations.
• data gathering requirements: permanent downhole monitoring, etc.
• maintainability, accessibility, intervention frequency, etc.
• standardisation of equipment.

Production operations input into well design

• regulations governing the provisions of subsurface safety valves;
• statutory requirements on maintenance of equipment and its frequency.
• sand control
• well killing
• sampling
• safety equipment
• corrosion inhibition
• well spacing
• flow control

Corrosion generally involves carbon dioxide (CO2), sweet corrosion, or hydrogen sulphide (H2S), sour corrosion. In both cases, water must be present for corrosion to occur.

The problems can be minimised through the circulation of corrosion inhibiting chemicals or the selection of corrosion resistant alloys. The primary factors that affect the severity of corrosion are the gas partial pressure, temperature, pH, chloride concentration and flow velocity.

Sweet corrosion

Sweet corrosion is caused by CO2 which dissolves in the water phase to produce carbonic acid. This lowers the pH, resulting in a highly corrosive environment.

If the predicted corrosion rate is determined to be too severe for carbon steel (with inhibition) then 13% Cr stainless steel will probably be adequate for most sweet service applications, as long as the operating temperature is below 150°C.

Sour corrosion

Sour corrosion is caused by the presence of H2S and water, even in trace quantities. Careful material selection must be made in H2S environment, as the corrosion process may lead to failure by cracking.

The hydrogen atoms resulting from the corrosion process can diffuse into the metal causing a significant reduction in ductility. This is called hydrogen embrittlement.

The maximum susceptibility of steel to hydrogen embrittlement problems is at room temperature. Above 80°C the degree of embrittlement becomes small.

Two types of cracking:

a. Sulphide stress corrosion cracking

SSCC can occur when a metal is subjected to a tensile stress while in contact with H2S dissolved in water. Cracking can occur suddenly and can lead to an unacceptable release of toxic fluids. A guidance document issued by NACE (National Association of Corrosion Engineers in Houston, USA), referred to as MR-01-75, is the basic code of conduct to which most oil companies adhere.

b. Hydrogen induced cracking

In most steels which have been rolled into plate to be made into vessels and pipe, non-metallic inclusions are rolled out into thin sharp-edged platelets which can act as sites for the accumulation of gaseous hydrogen. This accumulation of hydrogen can lead to the development of cracks even if no external load is present.

Oxygen corrosion

In aerated environments, oxygen reduction can occur in the presence of water, resulting in the corrosion of steel. In water injectors, the level of dissolved oxygen should be below 5 to prevent this form of metal attack and reduce the amount of corrosion deposits injected into the formation. Reducing oxygen to this level is extremely difficult and the use of GRE or polyethylene (PE) lined pipe should be considered for these systems.

Corrosion management

The data collected during inspection and corrosion monitoring activities are a major asset. Commercial software packages can provide a framework for the uniform storage of corrosion-related inspection data for all equipment.

The most cost effective way to handle carbon dioxide problem is using 13% chrome N-80 tubing equipped with premium connections.

Sweet gas fields can be divided into three groups:

1. CO2 partial pressure under 2 psia - No corrosion protection is used with no evidence of downhole corrosion.
2. CO2 partial pressure 5 to 20 psia - Most fields in this group used inhibitor batch treatment since start-up. Corrosion failures have occurred in unprotected wells and there is some evidence of corrosion despite regular nhibitor treatment.
3. CO2 partial pressure over 20 psia - There were many instances of corrosion pitting rates greater than 10 millimetres per year and documented cases of corrosion failures with monthly inhibitor batch treatment. Many operators use stainless steel production tubing to avoid corrosion.

Corrosion control alternatives

• Monitor only
• Stainless steel tubing
• Partial stainless steel
• Inhibitor batch treatment
• Inhibitor squeeze treatment
• Continuous inhibitor injection via annulus
• Continuous inhibitor injection via capillary

The Christmas tree is the cross-over between the wellhead casing and the flowline. The wellhead is the cross-over between the Christmas tree and the various casings.

• controls the wellhead pressure and the flow of hydrocarbon
• enables the well to be shut off in an emergency
• provides access into the well for well intervention activities.

Wellhead/christmas tree interface

The selection of the wellhead is normally by the Drilling Engineer in conjunction with the well structure design.

Both drilling and production requirements need to be addressed in the wellhead design, as it provides the crossover between the BOP and the various casings during the drilling phase of the well life cycle and as mentioned above controls the wellhead pressure and hydrocarbon flow during the production phase. The design should be in accordance with API specification 6A.

There are basically two types of wellhead, the individual spool type and the compact wellhead. The compact wellhead is a technically superior design which offers enhanced safety and rig time savings without incurring a direct cost penalty.

Christmas tree bottom connection

The Christmas tree connection to the wellhead or the tubing head spool should be rated to the maximum closed-in wellhead pressure. The connection should be designed to accept the shear loads, the loads imposed during wireline, coiled tubing and snubbing operations, such as bending moments of the lubricator, vibration, etc. It must be demonstrated by calculation that the tree/wellhead connection is adequate to meet these demands during its working life.

A suitable connection between Christmas tree and wellhead is the multi-segmented clamp. This device is quicker and safer to install than the more traditional flange and allows the drilling function to line up the Christmas tree accurately with the flowline. In principle it is recommended that dual seals are used, generally this is accomplished by way of extended neck tubing hangers.

Tubing hangers

During wellhead maintenance and other operations a back pressure valve is normally installed in the tubing hanger. To accommodate this, a profile should be machined into the tubing hanger to receive the valve and/or running tool. This should preferably be a wireline profile, which allows setting and retrieving the back pressure valve to be performed under lubricator control.

It is recommended not to use threaded profiles. They may become corroded or eroded by well fluids and wireline passing across.

The tubing hanger must withstand the forces exerted during well completion, such as setting the well conduit in tension or compression, and subsequent forces during well production, well stimulation etc.

Control lines

The tubing hanger also houses the termination or passage of the control line for the SCSSV and any other devices fitted downhole. The line should be a continuous path from the valve nipple to the surface. The wellhead body should not incorporate a fluid path for any control line (SCSSV or other downhole devices).

Wellhead ports

The wellhead design will incorporate a minimum number of outlets, including testing ports, tie down screws etc. Each annulus should have two outlets oriented at 180° to each other. The orientation of each annulus outlet should be the same, with the "A" annulus (production tubing to casing annulus) uppermost. The "B" should be the next lowest with subsequent casing outlets in line below each other.

During the producing phase of the well life cycle the annuli ports provide access to each casing for: pressure monitoring; pressure bleed off; fluid levels and samples; passage of fluids for artificial lift gas lift/hydraulic lift) usually only A annulus; passage of fluids for well killing/circulation; injection of corrosion inhibitors; access for pressuring the annulus to operate downhole tools such as SCSSVs.

• "A" annulus should have two flanged gate valves, with the same pressure rating as the tree on each outlet (in some instances, a single gate valve and a comparison flange is installed). The outlet used for sampling or gas lift should have a profile to insert a back pressure valve. The other side may be terminated with a flange, needle valve, and pressure gauge.
• "B" annulus: One outlet should have a single gate valve with a sampling/bleed down arrangement. The other side may be terminated with a flange, needle valve and pressure gauge.
• "C" annulus: One outlet should have a single gate valve with a sampling/bleed down arrangement. The other side may be terminated with a flange, needle valve and pressure gauge.

When there are more than three annuli on the wellhead these should be treated in the same way as the "C" annulus.

In general the "A" annulus ports are specified 2" nominal for well killing and gas injection purposes. The minimum diameter ports for the "B" and "C" annulus should be 1" nominal to avoid plugging. The specification of port sizes should take into consideration the life cycle requirements such as artificial lift requirements but also corrosion monitoring and remedial work requirements.

Christmas tree types

Subsea trees need to be designed to allow ease of tie-in to the tubing spool/wellhead, umbilical connections (hydraulic/electric), etc. and connection of tie-backs, flowlines, etc. in underwater conditions. The control and safety valves need to be operated via the umbilical lines.

Surface trees on the other hand are "simpler" in design since there is no need for running/guide bases, tie-in of umbilicals, etc.

There are two basic types of tree: solid, and composite. Solid trees are machined from single blocks of material. Composite trees consist of standard valves bolted together about a central body.

Solid type tree

The advantages of using trees constructed from a single block of material is the reduction in potential leak paths, and their higher pressure rating. It is also used for dual completions.

Composite trees

This type of tree should only be used for low pressure and low risk applications. Selection should ensure that the valves used have been designed for this type of application, and that gaskets do not project into the core of the tree and thereby obstruct the flow and wireline tool strings. All other features should apply equally to both types of tree.

Tree configurations

Dual trees

Dual completions are widely used, although problems in optimised gas lifting of both strings tend to favour single completions where gas lifting will be employed.

Splitter system

This allows two wells to be drilled, cased and completed from a single wellbore. Each well is independent, permitting concurrent operations

Operating requirements

• ·regulations governing the provision of one or two master valves;
• ·statutory requirements on the maintenance of the tree and other related pressure equipment;
• ·required maintenance frequency: what, where, when, and how.

Space requirements

The limits of the available space for the wellhead equipment should be defined at the initial stages of a project, not before detailed design commences.

Repressurisation

An important consideration in designing surface equipment is repressurisation after a shutdown, a SCSSV leak-off test, and tree maintenance. For example, in the case of the well being shut in and depressurised with full pressure below the closed SCSSV, there has to be some means of equalising the pressure across the sub-surface valve before it can be opened.

There are several scenarios possible for the repressurisation of a Christmas tree:

1. Using the equalisation feature of the sub-surface valve (if fitted).
2. Repressurisation of the string above the SCSSV from another well via the Production Manifold (or the Kill Manifold, bearing in mind the directions on kill systems and the kill philosophy, as discussed in Section 3.1.3).
3. Pumping into the string above the SCSSV a fluid which is compatible with the produced hydrocarbons (e.g. diesel) and pressurising this fluid until the flapper opens.
4. Using a supply of inert gas at sufficient pressure for same.
5. Using a combination of the methods described under b. and d.; if the other well cannot supply sufficient pressure this deficiency can be made up by an additional supply of inert gas.

Inter-well connection features

• ·Minimum line diameter of 2" (50 mm).
• ·For low pressure, normal temperature (non-gas) applications, any quick connecting rigid piped system or flexible hoses are acceptable.
• ·For high pressure, high/low temperature gas and H2S applications any suitable metal-to-metal seal system may be used.
• ·In all cases where jointed or flexible hoses are used there should be a documented and auditable means of determining whether the system is certified for use, i.e. pressure test certificates or insuring authority approval for use.
• ·In all cases where either jointed rigid line or flexible hoses are used suitable anchoring devices should be used to restrain the line in the event of a failure. This is a mandatory safety requirement.

Chemical injection

Injection lines should be designed in compliance with the general safety principles where required. Chemicals should be injected into the main body of the tree where the fluid flow is most turbulent and injection points should be large enough to withstand shear forces. The diameter of the injection line should be as large as possible and the connection to the tree flanged. For example 21/16" (50 mm) diameter is adequate to withstand most shear loads and vibration. Ring joint flanges can be used but cognisance should be taken of the comments on BX joints.

Sampling

No sampling points should be provided on the body of the tree. When a sample has to be taken close to the Christmas tree the sample point should be downstream of the choke, at the lowest pressure and at a point of high turbulence, to ensure that a representative sample is obtained.

Measurement

The preferred approach for obtaining wellhead pressures is to install an instrument flange, with ports for the sensors, between the Flowline Wing Valve (FWV) and the choke. The flange can also be used for chemical injection. The flow measurement is normally taken on a straight section of the flowline.

Safety criteria

Christmas trees and ancillaries must be designed to meet the minimum safety criteria and the installation should be suitable for its intended purpose. The design should comply with internationally recognised standards such as API 6A, ISO 9000, ISO 10423.

Well control intervention operations need to be a consideration during the well and facility design.

The safety logic of the process or platform installation should be taken into account during the design. For example, does the plant have emergency shut-down (ESD) and operational shut-down (OSD) systems? If so, what is the operating philosophy during these types of shut-downs? What effect will this have on the design of the tree?

All trees should have a (lower) master gate valve (LMG). This is the ultimate safety barrier and is one of the most important safety devices on the tree. In all wells the principle of operating a valve "one away" from the LMG must be incorporated in the design. The LMG should only be closed in an emergency situation.

When positioning casing outlets, valves, instruments, etc. consideration should be given to the space restrictions for normal operation and maintenance of the equipment. See ASTMS F-1166-88 (Recommended Installation of Valves) or similar.

Valve sequencing

Closure of the actuated valves on a Christmas tree is normally automatically sequenced through a dedicated well shutdown system. Before the design of a well is undertaken, the sequencing of the SCSSV, SSV and choke must be defined as it will have an influence on the control systems of the tree.

Typical examples of the sequential valve operations in an integrated production system are:

·Emergency Shutdown [ESD]

1. Choke closes under automatic actuation
2. Flow wing (or injection wing) valve closes (SSV)
3. Upper master gate valve closes (SSV)
4. SCSSV closes.

·Operational Shutdown (Unit Shutdown) [OSD/USD]

1. Choke closes under automatic actuation
2. Flow wing (or injection wing) valve closes (SSV)

·Planned Shutdown

1. Choke is closed under automatic actuation, by the operator
2. Flow wing (or injection wing) valve closes
3. Upper master gate valve closes
4. SCSSV closes (depending on the work to be done).

Lubricator connection

Lubricators are tubulars temporary fitted into the Xmas tree to enable well intervention activities on a well under pressure.

a. Single completions

With a flanged tree-to-cap connection (composite trees) and studded connection (solid block trees), due regard should be taken to seal selection. For similar reasons to the Christmas tree bottom connection, this uppermost connection or joint should be strong enough to withstand all the forces that will be imposed on it.

b. Dual completions

With this configuration the tree connection (each flange for each string) can be 'D' shaped. These are acceptable for low pressure, sweet applications. Their disadvantage is the uneven loading on the bolts of the 'D' shaped flanges. This type of connection should not be used in sour service.

An acceptable alternative for sour service is the figure of eight or oval shaped one piece connection that covers both top outlets. The bolts are more evenly tensioned and the flange less susceptible to differential movement.

c. Seals

The seal most predominantly used for lubricators is an 'O' seal, with the load being taken by an ACME thread. Provided the 'O' seal is regularly replaced, and pressure tested prior to well entry, this type of joint is wholly adequate.

In very high pressure applications, metal-to-metal seals have been used and are becoming more widespread. However, a change from 'O' seals to metal-to-metal seals will mean a change of lubricators and this should be carefully considered against the advantages of this state-of-the-art seal.

Wellhead/Christmas tree seals

Acceptance criteria

Selecting seals is an important aspect of wellhead design as a wellhead relies heavily on seals for its pressure integrity. 700 kPa (100 psi)/3 minutes is a common standard for leakage rate.

For tubular premium connections a limit of 0.001 cm3/second is normally accepted

Types of seals

Tt is recommended to use metal-to-metal seals; metal encapsulated polymer seals should only be used for pressures below 28,000 kPa (4000 psi). Pure elastomeric and/or plastomeric seals should be confined to wellhead/Xmas tree running tools and testing tools.

Xmas tree parameters

BOP/Christmas tree connections

The main consideration is the selection of a matched strength connection, e.g. the properties of the connector should meet the capability of the casing assembly to which the connection is to be made. Most of the subsea connectors and modern multi-segmented clamps are good examples of this design philosophy.

Surface wellheads

BOP/Christmas tree connections can be either clamped with two-piece clamps and hubs or flanged with raised face flanges. Both of these design features have their advantages and disadvantages, however a major objective is to have a low profile wellhead.

Raised face flanges were used in older connections and over the years these have evolved into R type connections with ring gasket and grooves. The grooves are shallow for R seals and deep for RX seals. The seal flank of the RX seal is identical to that of the R seal but the load flank is sometimes omitted. Some valve bonnet seals employ a similar design feature. See API Specification 16A. The major suppliers have manufactured various types of connectors for surface wellheads.

Conventional two piece clamps have the following advantages:

• ·The reduction in time of the high risk operation of nippling up and down, during which time the protection offered by the pressure tight vessel is not provided.

The nippling is best done by means of torque wrenches, as accidents can occur while using flogging spanners.

• ·They can act as better heat sinks. With API seal technology clamps without expandable washers have better fire resistance acting as a better heat sink.

Conventional two piece clamps have the following disadvantages:

• A higher profile and therefore extra head room is needed.
• They are heavy and very difficult to energise. In particular for medium to high pressures (more than 34,474 kPa/5,000 psi) and medium to large sizes (more than 346 mm/135/8").
• Faulty castings and forgings can and have contributed to low and unacceptable performance. See DEN 65189.
• Stresses in clamps and hubs exceed those in flanges and bolts.
• The lack of proper alignment. This is a problem with AX style gaskets. For example while machining new heads two features are often faulty; the API ring groove and the API bolt holes, despite the generous tolerances. When bolt holes require repairing, threaded bushings are recommended over welding.
• Aligning bolts is difficult. Firefighters prefer flanges instead of clamps because they can align flanges easier by using bolts of different lengths. For the same reason conventional spools are also better than unitized wellheads, if not splittable. Similarly studded connections are preferred over flanges. This apparent conflict highlights the vulnerability of sealing within the plastic limits of the steel. Therefore in these applications it is recommended to use of elastic seals, such as AX, Grayloc, and similar.
• Heavy clamps are difficult to handle.

Subsea wellheads

In subsea applications multi-segment clamps and riser connections are used. BX style seals are excluded because either they are not vented or, if they are, venting of the ring gaskets is not reliable as the vent becomes plugged. Both situations create hydraulic lock on the groove.

The major suppliers have manufactured various types of connectors for wet applications. Among these are:

• ·The Vetco H4. The H4 Multiple Load Shoulder features a slimmer profile which can withstand bending moments better due to a deeper swallow and is also easier to stab-in.
• ·Cameron's modified Collet connectors. Cameron uses the standard Hub with Single Load shoulder for its collet connector thereby providing a larger OD.

Male/female profiles are inconvenient as they prevent bi-directional installation. API double box profiles are a good alternative provided that the ring gasket belt acts as the matching double pin. The modified/recessed Grayloc has been used in such profiles.

In the design of marine hubs, male/female profiles must be incorporated, to allow the easy alignment of the mating members, thereby freeing the gasket from such a duty.

Selection criteria

The ideal connection should maintain the maximum equivalent pressure rating of the assembly, require little stud tensioning (to avoid over-torque), resist external loads (bending, shear, vibration, temperature expansion), allow easier seat rework and have reusable seals

Face to face contact is vital for fatigue resistance, bending, shear and axial alignment. Ideally the bolt circle should be inside the contact area to have all fasteners working together. This also helps while the BOP is in the following state:

• ·tension: during testing;
• ·in compression: by hanging off;
• ·in shear: during slant drilling.

Subsea "spool" tree

The "spool" tree system does not currently fulfil the necessary two barrier reservoir isolation criteria under all conditions. This stems primarily from the barriers available during operations necessary to install or remove the wireline plugs in the tubing hanger/tree. With the current design there is heavy reliance on the shear rams of the Drilling BOP to provide not only the disconnect facility, but in some instances, the only barrier between the reservoir and the environment.

Seal testing

External testing of the upper seals checks these seals the wrong way around, as the test pressure in this case comes from below, while the actual well bore pressure comes from above. The reverse situation applies to the lower seal.

Also the auxiliary seals, which are used to facilitate the pressure testing of the assembly, should have the same integrity as the main metal-to-metal seals. This means that metal-to-metal seals should not have elastomers to test against.

Some pressure energised purpose-designed seals, such as elastomeric or metallic cup testers, suffer as they are undirectional. Although they are good at sealing pressures from the wellbore they do not seal from the well test port side. Therefore they are sometimes not considered for selection for the wrong reasons.

For spool type wellheads the situation is even more complex. There are:

• Primary seals. A misnomer for the first/low pressure seal to be installed;
• Secondary seals. A misnomer for second, critical or crossover seals.

The mechanical part of the assembly must be designed with tight tolerances in accordance with the practical rule of thumb:

• Gap (mm) ´ Pressure rating (kPa) = 13,000; or
• Gap (0.001") ´ Pressure rating (thousands psi) = 75.

For example, for 100,000 kPa (15,000 psi) systems, 0.13 mm tolerances (0.005") should not be exceeded.

As a corollary each pressure rating requires a different geometry and/or different machining tolerances.

The designer must ensure that there is critical flow through the choke in order to eliminate the effects of downstream pressure variations on the formation. This is achieved when the FTHP is approximately 1.7 times the downstream flowline pressure. There are additional factors to be considered in choke selection.

1 Actuated chokes

By its very nature the choke is subjected to very high pressure drops, which can lead to mechanical problems.

1.1 Start up and shut down

With zero pressure in the flowline and maximum CITHP the choke is subjected to the maximum pressure drop it will experience. It is essential that during this phase of production the choke is capable of moving off seat. During the latter part of the lifespan of the well, this pressure difference will gradually reduce as the field depletes.

When selecting a choke the tendering vendors should be able to prove by calculation or demonstration that the offered choke and actuator combinations will perform at the extremes of the operating envelope and not 'freeze' in one position. Experience has shown that with multiple orifice chokes this problem may be overcome by fitting "concave" front and back discs. These discs are machined to give a smaller area of contact between the fixed and moving discs, thus reducing the effort needed to overcome the effect of the pressure difference. Several designs of chokes do offer a positive shut off, however, for isolation purposes:-

 Under no circumstances is the choke to be regarded as a positive shut off device.

In cases of chokes with a rotary action, a high pressure differential will cause wear and at times failure due to seizing of any thrust bearings fitted. The construction of the thrust device should be examined to determine if failure would cause production down time or migration of hydrocarbons to the atmosphere.

In the selection of seals and seal material the normal guidelines should be followed to ensure that all elastomeric seals are compatible with the fluids produced. Consideration should be given to metal to metal seals between the choke 'bonnet' and body.

Where the choke has a linear movement the effect of the differential pressure should be determined: the direction in which it acts; its effect on the valve. High differential pressure may cause control valve type chokes to ""bind" or "freeze"" in one position, although pressure balance ports should resolve this problem.

There are three common types of control choke trims, the Plug and Cage, Internal Sleeve and the External Sleeve Trims.

The selection of the actuator for the intended service is critical, it should be able to open and close the choke under all anticipated operating conditions. When signalled to close by either an ESD/OSD alarm or normal control the choke should be able to close smoothly and quickly. Normally the choke is first to close on a sequenced closure of all the well valves. This prevents undue erosion of the other valves in the system.

1.2 Normal operations

The choke should operate smoothly under control of the actuator. The control system should not "hunt" or generate any random choke movements. The choke should still be able to move smoothly if held in a fixed position for long periods.

Due to the nature of the choke, very high turbulence is generated directly downstream of the device. This problem must be considered at the design stage, otherwise erosion of the downstream flowline may occur in a relatively short time span. A standard arrangement is to fit a hardened pup piece downstream of the choke.

One advantage of the control choke is that the turbulence it generates can be directed into itself, which limits its downstream effect. The major turbulence is in the centre of the fluid flow and not impinging on the internal surface of the choke. In this case the need for hardened pup pieces or wear sleeves may be eliminated.

2. Positive chokes

The significant features are:

1.the bleed screw assembly does not allow removal of the blanking plug prior to depressurisation;

2.if erosion of the blanking plug threads or seat occurs, the screw assembly may be replaced;

3.the metal to metal blanking plug seat has an elastomeric back-up seal;

4.the blanking plug is tightened using a spanner as opposed to a hammer union.

All new designs of positive chokes should exhibit the above features. In addition there should be competent persons trained to examine and gauge the internals of the choke. The threads and sealing surfaces form primary barriers against loss of pressure containment, internal corrosion and wear.

2.1 Maintenance

At some stage in the life span of the well maintenance will be required on the choke. Therefore when the choke is selected initially a check should be made on the space needed to fit special tools for internal maintenance. Removal tools for choke internals can be heavy and quite long (depending upon the size of choke), therefore adequate access space is important. Prolonged maintenance caused by incorrect positioning of chokes or space constraints increases well downtime and operating costs.

For safety considerations there should be adequate valving to ensure that chokes can be isolated and depressurised in accordance with EP 55000 section 35 (block and bleed).

This article describes the wellhead technical specifications, Operating Envelope  and Operating Philosophy.

The operating envelope

When defining the type of equipment and service for a project the information given should cover virtually all areas of concern. Therefore the production envelope must cover the total lifespan of the project. If, for example, there was a need for water injection or gas injection on a project, the expected flow rates and water/gas properties would also be included.

For example, this envelope should include:

• Fluid Properties: oil, gas, water steam etc.
• Maximum surface pressures and temperatures
• Maximum and minimum flow rates
• Flow rates for oil/condensate and gas at differing (maximum and minimum) water cuts
• Solid content in terms of sand (including an example of a short term production if for instance a gravel pack fails)
• Maximum CO2 content over the lifespan of the field
• Maximum H2S content over the lifespan of the field
• Gas lift volumes, dewpoint, composition, CO2 and H2S concentrations for the lifespan of the field
• Drilling fluid properties including spudmud, KCl polymer mud etc.
• Completion fluid properties
• Well clean up and stimulation fluid properties
• Formation produced and possibly injected water compositions
• Potential for producing wax (asphaltenes).

The most effective tree design can be determined with the input of the users and maintainers (Operating Philosophy), in combination with the information contained in the operating envelope. All information obtained should be treated as a range. In using these ranges it may be cost effective to move up or down in sizes of equipment.

The data appearing in the following sub-paragraphs is representative of a typical Operating Envelope. However, this information should not be used as a basis for equipment selection.

Oil properties

 Maximum Surface Temperature

Maximum Surface Pressure (Flowing / Closed in)

Maximum Oil Production / % water

Typical Solid Content (Sand)

Maximum Solids Content (Short Term, Gravelpack Failure)

Total gas (reservoir and gaslift)

 Water cut (%)

Reservoir gas (MMscft/d)

Gaslift gas (MMscft/d)

Total (MMscft/d)

Maximum CO2 Concentration (Reservoir + Gaslift Gas) % by Volume.

Maximum H2S Concentration (Reservoir + Gaslift Gas) ppm (V).

The maximum CO2 and H2S concentrations will be experienced towards the end of the field lifespan.

Gas lift

Maximum Surface Temperature

Expected Maximum Surface Pressure

Flow RateA s Indicated Above

Water Dew Point °C at x barg

Expected C02 Concentration % (V)

Expected H2S Concentration ppm (V)

Properties of other fluids

The well will also come into contact with one or more of the different types of drilling mud that are available on the market, e.g. Gypsum (lignosulphonate mud), Polymer Spudmud, KCI Polymer Mud and possibly chalk mud to drill the reservoir section.

For well completion and workover operations Calcium Chloride brines and inhibited sea water (corrosion inhibitor and biocide) will be used. For well clean up and stimulation HCl and/or HF acid will be used (HCl acid concentration is 10%, HF acid 7.5%, HCl 1.5% concentration).

Formation water analysis

Formation water (mg/l) Sea water (mg/l)

Sodium, Potassium, Calcium, Magnesium, Iron, Barium, Strontium, Boron, Chloride, lodine, Sulphate, Sulphide, Bicarbonate, pH, Formate, Acetate, Propionate

n-Butyrate.

Operations philosophy

Designing an operations philosophy

It is always advisable to start the design process with an operating philosophy. This should take into account the needs of the production operator, the well services personnel and other functions involved in the asset management of the well.

•  List all the internal and external factors acting upon the well.
• List all subjects (Criticality, Manning, Availability, Sparing, Maintenance and Inspection etc.).
• Formulate 'options' for each of the subjects.
• Identify the equipment required.
• Select the equipment that meets the preferred option.

Clearly defined standards should be available. These standards should be adhered to, unless the well is of a new type or there is a clearly documented justification for deviating from the standard model.

Space requirements

The limits of the available space for the wellhead equipment should be defined at the initial stages of a project. Preferably as soon as possible after project initiation and certainly before detailed design commences. If not, problems may be encountered at a later stage and mistakes may prove costly.

Retrieval of an Electrical Submersible Pump (ESP) requires similar precautions to those taken during installation and some additional points should also be considered when retrieving ESPs.

Analysis of the reasons for ESP failure may not be possible if additional damage is sustained by the equipment during retrieval from a well, or during subsequent storage and transport. This may result in a repetition of design errors, and may jeopardise warranty claims.

The same handling procedures and precautions taken with new equipment should be applied to used equipment. In many cases equipment retrieved from a well can be repaired and re-used with considerable cost savings in comparison to the use of new equipment. To minimise repair costs the same care is required when handling, lifting and packing used equipment as is required for new equipment.

Pulling out of the well

It is desirable to have a vendor engineer on site during the pulling of a failed completion. A full "pull" report should be filled out by the engineer as an aid in diagnosing reasons for failure. Cable should be inspected for armour damage (such as wear or explosive decompression) and damage noted on the pull report. The bands should be cut off with a cutting tool. The condition of the bands should be noted. If bands show signs of corrosion, a different metal should be used for future banding material. Rig personnel should note whether bands are missing as the tubing is pulled. If a large number of bands are found to be missing, it may be necessary to retrieve the bands from the well prior to installation of a new Electrical Submersible Pump. Cable protectors should be recovered, cleaned, and oiled.

All accessories should be examined and damage noted. Obvious pump/motor damage should be noted. This will include an estimate of potential bearing wear in rotary gas separators, a check on the ability of the Electrical Submersible Pump and motor to turn freely, recording of obvious overheating (such as discoloured motor housing), recording of condition of motor oil and seal protector oil, etc.

As a minimum the following checks should be made and the information recorded prior to and during a pulling operation:

• data gathering of Electrical Submersible Pump information prior to failure (including rates, pressures and ammeter charts);
• visual inspection of surface controller with a check on protective and monitoring devices and input voltage values;
• electrical check of cable prior to pulling and visual inspection during pulling;
• electrical check of cable after disconnection from motor;
• external damage check of Electrical Submersible Pump, seal and motor (physical damage and signs of overheating);
• pump intake check for plugging;
• pump and motor check for shaft rotation and side play;
• check on condition of motor oil (discolouring/water content);
• condition of seal section oil; 
• check on resistive values of motor.

The wellhead is simply a crossover between the various casings and the Christmas tree or -temporarily - the BOP.

Unitized wellheads

The evolution from spool type wellheads to compact, or uniheads has occurred over a number of years. This evolution has generated a wellhead which is technically superior, offers enhanced safety and rig time saving, without a direct cost penalty. Experience has also shown, that there need be little or no distinction between the designs for exploration and development applications, provided that the unihead is maintainable.

Standardisation

The objective is not a standardization of equipment geometry and/or vendor but rather one of approach to the design.

Sealing

Endless and axi-symmetric seals are a must.

Seal interface geometry must be designed with tight tolerances.

Rule of thumb: Gap times Pressure rating equals a constant (0.005" ´ 1 5Ksi).

Corollary: Higher pressure ratings require tighter machining tolerances.

BOP connections

API connections are sub-optimal.

For new installations, state of the art connections - available from all vendors - should be considered.

On existing API connections, fasteners should be upgraded.

Housing

Matched strength connections are a must.

Coupling-like connections and/or butt-weld 'HOTHED' are cost effective.

Slip-on heads - fillet or socket welded - are not recommended.

Casing suspension

Matched strength connections are a must.

Coupling-like connections are cost effective.

Dated segmented slips are not encouraged.

Mandrel type hangers, emergency slips and seal assemblies must be run through and tested under BOP protection.

Internal geometry

45° seat angles are technically superior and cost effective.

Seat areas should be in line with the cross-sectional area of the supporting system: (surface casings) or landing plates for special cases.

Centralisation and/or nesting of items is paramount for sealing. A gun barrel approach is supported, items to have the same internal diameter drift. Outlets should be minimised and their sealing capabilities optimised.

This article describe the design and selection criteria necessary in the construction of safe and cost effective Wellheads and Christmas trees.

Read more …

In the design process for all wells, consideration should be given to the repressurisation of the Christmas tree after it has been closed in. Several approaches may be taken depending on the circumstances and the design of the well.

Read more …

Examples of programs for Pressure Testing Wellheads.

1. Onshore

20in Casing

After installing the 20in casing and 20.3/4in -3 000 psi CHH, pressure test CHH and BOP’s to 500 psi against the bag type annular preventor and cement plug with the BHA in the casing prior drilling out the shoe track.

13.3/8in Casing

After bumping the 13.3/8in plug pressure test the casing to 2 500 psi.

Install the 20.3/4in x 3 000 - 13.5/8in x 5 000 CHS. Pressure test casing mandrel hanger top seal and wing valves to 2 500 psi with the cup type tester. Pressure test ring joint cavity to 2 500 psi.

9.5/8in Casing

After bumping the 9.5/8in plug pressure test the casing to 2 500 psi using the HP cementing head.

Install the 13.5/8in x 5 000 - 11in x 5 000 THS. Pressure test CMH top seal and wing valves to 2 500 psi with cup type tester. Pressure test ring joint cavity to
2 500 psi.

7in Liner

The liner should be tested according to the liner procedures as described under Pressure Testing 1 - Liner Lap Testing.

2. Offshore

13.3/8in Casing

After bumping the 13.3/8in plug pressure test the casing to 2 500 psi.

Install the 20.3/4in x 3 000 - 13.5/8in x 5 000 CHS. Pressure test casing mandrel hanger top seal and wing valves to 2 500 psi with the cup type tester. Pressure test ring joint cavity to 2 500 psi.

9.5/8in Casing

After bumping the 9.5/8in plug pressure test the casing to 2 500 psi using the HP cementing head.

Install the 13.5/8in x 5 000 - 11in x 5 000 THS. Pressure test CMH top seal and wing valves to 2 500 psi with cup type tester. Pressure test ring joint cavity to
2 500 psi.

7in Liner

The liner should be tested according to the liner procedures as described under Pressure Testing 1 - Liner Lap Testing.

3. Pressure Testing with a Slip and Seal Assembly

In case a slip and seal assembly is used to hang off the casing, the ring joint cavity should be pressure tested to a maximum of 50 % of the minimum collapse value as given in the following table.

* Do not exceed 3000 psi  the 7in slip and seal assembly

The duration of each individual pressure test should be 15 minutes at a stabilised pressure.

BOP’s and surface equipment should be pressure tested to 5 000 psi against the plug type tester.

When specifying or designing valves, reference should be made to the information contained in the Operating Envelope for that particular well.

All valves purchased by must at least meet the standards set in API 6A PSL 1, 2, 3 or 4 and in several areas it must exceed those standards Cases where the standards are exceeded are specialised exceptional cases. The preferred route is to purchase to API 6A latest edition at the PSL-3, PR-2 level.

End connections

For safety reasons valves or pipe fittings with screwed connections are not recommended. The valve flanges on wellheads should be to API standards although the recommended standard on line pipe or processes is ANSI. All wellhead valves should have flush internal joints to prevent erosion and the build up of sand.

Body and bonnet

Preference should be given to forged bodies and bonnets with the minimum number of penetrations. The bonnet should be bolted to the body with standard bolts or studs.

To ensure a good seal, an understanding of seal technology should be applied so that seals are not used to transfer loads, align components etc. Ideally, the internal cavity of the valve should be round with the body to bonnet seal a metal to metal one. Although metal to metal seals are more difficult to install, these are currently preferred as, once fitted correctly, they have a longer lifespan.

In some low pressure, low temperature, clean service process applications it may be cost effective to have elastomeric seals.

Gate

The true floating single slab, double seat arrangement has preference. This helps to prevent build up of debris between the gate parts and also prevents pressure locking of the valve when fluid is retained between the gate slabs (in split gate assemblies) with no pressure in the body. Ideally the gate should have a minimum number of components with no chance of a component becoming detached from the gate and flowing down the process line.

When open, the gate should provide a smooth bore within the valve to prevent erosion and an internal build up of sand.

Care should be taken to ensure that pressure locking of the valve cannot occur under normal operating circumstances. This is particularly important when the process is equipped with an automatic shutdown and bleed down emergency system. The valve should be examined to ensure it can withstand throttling under normal open and closing conditions and that it is not possible for hydrates to build up inside a valve in wet gas service.

Hardfacing

Although hardened faces on the gates is preferable, the type of hardfacing will depend upon the environment to which the valve is subject, i.e. sand production or wirecutting service.

Seat

The valve should have metal to metal seats (gate to seat and seat to body). The valve should seal and be operable under full pressure and flow conditions. More importantly, it should seal effectively in both directions in the low pressure, low differential case. It is not necessary for the valve to have a block and bleed capability (a single valve is considered "one" block in the double block and bleed situation.

The best approach is to have valves that only need 'standard' tool box tools for assembly and disassembly.

Stem

All Wellhead and Christmas tree valves should have non-rising stems, with a (preferably selective) backseating capability. The preference is to have a lockable back seat feature.

Stem packing

When used in a high pressure corrosive environment, the stem packing should be metal to metal. With a non-rising stem the seal is only subjected to linear movement and not a linear and rotational movement. In some process applications elastomeric seals could be suitable provided that the seal is exposed only to fluid pressure and temperature and is restricted to one degree of freedom.

Special consideration must be given to extraordinary service such as steam injection.

Proper handling and running procedures are essential to ensure cable reliability. The majority of cable failures are caused by damage resulting from improper handling.

The ESP cable is often the most expensive item in an Electrical Submersible Pump (ESP) system. It is easily damaged if subjected to incorrect handling procedures. The weight of a drum of ESP cable may exceed 10 tons. If placed directly on the ground the flanges are likely to sink, causing the weight of the drum to rest on the cable. The drum should normally be supported on an axle to prevent damage.

1 Lifting of cables - Electrical Submersible Pump

• Cable drums should be lifted using an axle passed through the drum. A spreader bar should be used to ensure that lifting slings do not bear on the flanges of the drum.
• If a fork lift is used to lift the cable this should be done either by supporting the drum on an axle which can be lifted by the forks, or by placing the forks through the drum from the side. The forks should never be allowed to come into direct contact with the cable.
• At low ambient temperatures, the cable should be kept warm until it is run in the well. The insulation may become brittle at low temperatures causing cracking.

2 Cable sheave assembly - Electrical Submersible Pump

• The cable sheave should be hung in the derrick above the wellhead, or on a mast aligned between the cable reel and wellhead. Make sure the cable sheave is attached securely with chain and safety backup! (cable or chain).
• This sheave should be no more than 30 feet above the ground in order to permit flexibility and avoid shock against the cable during running and pulling operations. The largest available sheave (minimum 54") should be used to minimise flexing of the cable. At very low ambient temperatures the cable should be heated to prevent cracking and damage to the insulation.
• The pothead and flat cable extension must be threaded through the sheave before it is lifted into the derrick.

3 Cable spooling - Electrical Submersible Pump

• The cable should be removed from the cable drum slowly. The cable should be supported between the drum and sheave during installation and pulling operations. The weight of the cable between the sheave and the drum should not exceed 100 lbs (50 kg).
• At all times, there should be some slack between the cable reel and the cable sheave wheel. The Electrical Submersible Pump (ESP) cable should never be subjected to tensile loads during spooling operations.

4 Cable protection - Electrical Submersible Pump

• Electrical Submersible Pump (ESP) power cable is run into the well attached to the tubing string. The cable is fastened to the tubing with bands which may be manufactured from mild steel, stainless steel, or Monel, according to the environment in which they are used. Bands are typically 20 mm wide and 0.6 mm thick. At least 1-2 bands per tubing joint should be used. Bands can be applied manually but are more reliably installed and tensioned with automatic banding machines. Bands should not be put over splices, although three to four additional bands should be used above and below a splice.
• To prevent crushing of a cable between tubing couplings and the casing, cast cable protectors (Cross-coupling protectors) can be used. These are installed over a tubing collar and provide sufficient standoff to ensure that the cable is protected. Typically one protector is required every 2-3 joints of tubing. In deviated wells cable protectors must be used, and may be required on every connection.
• Cable saddles should be used for the flat cable extension to provide sufficient standoff to prevent crushing of the cable between the motor housing and the casing.
• ESP cable is incapable of supporting its own weight when hanging vertically in a well, unless supported by the tubing. Stretching of the cable may result in the breaking of the conductors, and damage to the armour and insulation. Cable bands must be used to ensure that the cable is supported by the tubing.
• The cable should be kept clear of the ground when running into the hole. In a muddy location, place boards or matting to avoid the cable picking up mud and dirt.

5 Cable running procedures - Electrical Submersible Pump

• The rig must be correctly aligned over the wellhead.
• The cable reel should be positioned 75 ft (25 m) to 100 ft (30 m) from the wellhead.
• Where possible cable splices should be made in advance in a clean dry environment. This will improve the reliability of the splice and save rig time. The motor flat cable and splice should be fed through the cable sheave before it is lifted into the derrick. 
• Run or pull the tubing slowly to ensure that the cable is not damaged (max. 2000 ft/600 m per hour).
• Extra care should be taken when running an Electrical Submersible Pump (ESP) into a well for the first time. The driller must be alert to any unusual increase or loss of weight, and should not jar or brake unnecessarily.
• The clearances around Electrical Submersible Pump units in heavy walled casing may be small, and may require that the flat cable guards are omitted over the Electrical Submersible Pump section of the down hole assembly.
• Cross-coupling or other cable protectors should be fitted at the required intervals.
• Cable bands should be used and should be installed with a banding machine. Use of hand banding should be discouraged as it is time consuming and bands are inconsistent. Two bands per joint should be used with 20 ft (6 m) tubing joints. One band should be placed at the midpoint of each joint and the second 18" (50 cm) above each coupling. Three bands should be used on 30 ft (9 m) tubing joints, and for heavy flat cable sections. Cable bands should be tight, but should not crush the armour. The bands must be positioned squarely across the cable and tubing, with the bands at right angles to the tubing. The bottom and top edges of each band must be flush with the tubing. Bands should be counted and entered on the completion tally. Any band that is loose should be removed and replaced.
• The flat cable and cable guards should be banded in a straight line up the side of the protector and Electrical Submersible Pump. The first band should be positioned immediately above the pothead using a flat guard which has the bottom end slightly chamfered. The flat cable and guards should be used up to the cable splice.
• The flat cable guards should not be placed over voids, screens, or at changes of assembly diameter. If necessary, the end of a flat cable guard may be cut to fit.
• The cable must be positioned in the slip door guide slot before the slips are set.
• Cable continuity checks should be made regularly while unit is being run in. Cable checks are normally made approximately every 2000 ft (600 m).
• The round cable should run in a straight line up the tubing. The tubing must not be allowed to rotate while running into the hole.
• Backup tongs should be used to prevent rotation of the tubing string when tightening tubing connections. The swivel should be locked to prevent rotation of the hook. Any rotation of the tubing string will lead to cable damage.
• The slips should be maintained in good condition with sharp dies of the non-rotating type. 
• If cable crushing or armour damaged is suspected it must be inspected by the ESP engineer and running in continued only if the cable is undamaged. If necessary cable can be repaired by field splicing but this should be avoided if at all possible.

Minimum checks that should be carried out during the installation process:

• check cable physical condition;
• check pothead physical condition;
• check conductor continuity;
• check phase to phase and phase to ground resistance for all phases; 
• perform pothead pressure check.

6 Checking cable and motor - Electrical Submersible Pump

• Electrical continuity of the cable and motor can be checked using an ohmmeter. When connected between any two phases the reading should be the resistance of two conductors and two stator windings in series. The reading between any two of the three conductors should be the same.
• The insulation of the cable and motor windings to ground must be checked with a high voltage megohmmeter. For a new cable (without a motor connected) the electrical resistance between any two phases, or between any phase and ground should be infinite. With a motor connected the phase to phase reading will be low, but the resistance of all phases to ground should be infinite. Since all three phases are connected together within the motor a ground fault on any of the phases will be measurable on all of the conductors.
• Phase rotation equipment should be used to mark the phases, to ensure that the motor rotates in the intended direction.

Prior to leaving location it is recommended that a well test is carried out to the Electrical Submersible Pump using a dedicated test separator with the rig on site.

This will ensure that any immediate problems can be rectified without having to move a rig back. In addition the use of a dedicated test separator with crew and the vendor engineer will enable accurate well testing to be carried out under controlled conditions. The well should be produced at several different rates within the recommended Electrical Submersible Pump range to verify the pump curve and identify problems (such as phase reversal). Care must be taken during the initial start up that sufficient fluid flow is generated from the formation to cool the Electrical Submersible Pump motor. For a depleted reservoir, with the well standing full, significant time may pass before flow from the formation is initiated. This should be calculated beforehand, discussed with the vendor representative and if necessary the unloading carried out in stages. Surveillance of the installation during the initial test is the responsibility of the vendor engineer but should include monitoring of downhole pressures and condition monitoring of the motor if available.

Guidelines for starting and operating an Electrical Submersible Pump (ESP) system.

1 Personnel

A field engineer from the pump supplier should be present whenever an Electrical Submersible Pump is to be started for the first time. The field engineer should remain on the location until the well has stabilised and the Electrical Submersible Pump is operating properly. The field engineer should remain available for at least 12 hours after a pump is started.

2 Starting the Electrical Submersible Pump

An Electrical Submersible Pump (ESP) may be started and the well cleaned up using a soft starter or VSD, even when it is intended to operate the Electrical Submersible Pump on a fixed supply frequency. This will reduce the start-up current surge and allow initial clean up and production at a low flow rate, which can be increased as the well cleans up. In a new well the use of a VSD allows the well to be tested at multiple flow rates, permitting validation of the pump design. The inclusion of downhole pressure and temperature sensors to monitor the performance of new wells is recommended.

Electrical Submersible Pumps may be started with the flowline valve closed, to avoid excessive flow rates, or may be started with the flowline open. The risk of Electrical Submersible Pump damage due to excessive flowrates is normally small compared with the risk of pumping against a closed valve, but will depend on the well and Electrical Submersible Pump characteristics.

After the preliminary checks listed above have been carried out the Electrical Submersible Pump may be started. The supply voltage with no load connected should be observed and recorded. The voltmeter should remain connected for a load voltage check. After the start button has been pressed the Electrical Submersible Pump should start within 0.2 seconds.

3 Motor current

Use of a VSD or soft starter will reduce the starting current of the motor to a maximum of approximately 300% of the nameplate current for the first few seconds of operation, before falling back. If no VSD or softstarter is used the initial current may be up to 450% of the nameplate current depending on the cable characteristics.

The current drawn may initially be higher than the expected operating current, if the well is filled with high density brine or completion fluid. If no check valve is fitted the current may be lower than the normal operating current until the tubing is filled. Over- and underload trips levels may need to be temporarily reset to prevent disconnection of the power. The Electrical Submersible Pump assembly should be connected and run on a test bench or in a test well prior to installation. Data obtained in a test well allows accurate estimates of the start-up and operating currents to be made, and has been found to reduce the incidence of Electrical Submersible Pump failures occurring during the first days of operation. If no test data is available the normal operating current should be calculated from the Electrical Submersible Pump and motor specifications and compared with the values measured.

No more than three attempts should be made to start a Electrical Submersible Pump if abnormally high starting currents indicate that the Electrical Submersible Pump is stuck. Other techniques, such as reversal of two phases or acidising to remove scale should be tried before the Electrical Submersible Pump is pulled.

4 Sand production

If initial sand production is expected the likelihood of damage to the Electrical Submersible Pump will be reduced if flow rates are restricted until the well has cleaned up. This should preferably be done using a VSD as use of a surface choke will increase will increase downthrust while the sand is passing through the pump, causing rapid wear.

5 Stopping an Electrical Submersible Pump

Unless a potentially damaging condition such as unbalanced operation is detected a pump should not be stopped until any solids in the wellbore have been produced to surface. When a pump is stopped, fluid will drain back through the Electrical Submersible Pump and suspended solids may settle out in the pump preventing the pump from being restarted, unless a check valve is fitted.

6 Re-starting an Electrical Submersible Pump

If the pump is stopped for any reason fluid may drain back through the Electrical Submersible Pump causing the impellers to rotate in the reverse direction, or backspin. Sufficient time must be allowed for backspin to stop before attempting to restart a pump or damage to the Electrical Submersible Pump will result, such as breakage of the shaft. The use of a backspin relay to detect pump rotation is recommended.

7 Current and voltage measurements

The voltages and currents in each of the phases should be measured and recorded.

The voltages and currents in all three phases should remain within 5-10% of each other. Unbalanced currents or voltages may indicate a faulty power supply, motor or cable. If severely unbalanced conditions are observed at start-up the system should be shut down within a few seconds to prevent damage. Minor imbalances between the loading of the phases is common.

Unbalanced loading may be due to small differences in the impedance of the cable conductors and stator windings, or to differences in the supply voltages of the three phases. In some cases changing the phase connections may reduce the imbalance. Care should be taken not to reverse the direction of rotation of the motor when changing phase connections.

8 Over and underload settings

The uncertainties inherent in the design of an ESP system make accurate prediction of the motor current under operating conditions difficult. The current will depend on the frequency and voltage of the electrical supply. Unless the 'normal' values for these parameters are known the measurements at any instant are relatively meaningless. The upper and lower limits of current which will trigger a shut down must be set on the basis of the current actually measured following start-up or during normal operation of the system. To avoid damage to the motor in the event of closure of a SSSV or flowline valve the undercurrent trip must be set to approximately 85-90% (certainly above the idlemotor load) of the normal operating current. The overcurrent trip is normally set at 110-120% of the normal operating current. Since the current will be approximately proportional to the density of the fluid within the Electrical Submersible Pump the trip settings may need to be adjusted as the well cleans up, and whenever changes in the composition of the produced fluid occur. The vendor engineer should monitor the current during all start-up and initial running periods to enable the first setting of under/overload trips to be made.

The importance of the correct settings for over and underload trip settings is emphasised. The fall in motor current under pump-off or shut-in conditions is small and may not be detected if the undercurrent trip is incorrectly set, causing unnecessary damage to the motor and pump. Increases in fluid density or changes in supply voltage will increase the current drawn by a motor and may mask the decrease caused by pump-off or shut-in conditions.

Some controllers and CAO systems for Electrical Submersible Pump operation include facilities for automatic resetting of the over and undercurrent trips by continuously monitoring the current drawn and adjusting the trip levels to reflect the average current during a pre-set period. Gradual changes in current due to variations in fluid density can be discriminated from sudden changes due to pump-off or shutting in of the well.

9 VSD

The over and underload settings for a VSD may need to be adjusted in a similar manner to the settings for a fixed speed Electrical Submersible Pump. In addition the settings must be adjusted following any change in operating speed. The frequency at which a pump is operated should be monitored and recorded with the voltage, current and flowrates. The values of voltage, current, and flowrate are of little value unless the supply frequency is known.

10 Phasing

In common with other 3-phase induction motors, ESP motors will rotate in either direction depending on the electrical phase sequence. The phase sequence can be changed by reversing any two of the three conductors, with the third remaining in its original position. This is usually done at the vented junction box.

Electrical Submersible Pumps are capable of producing large volumes of fluid when rotating in the wrong direction. Accurate measurements of the wellhead pressure and flowrate may be required to identify the correct direction of rotation. A pump will produce less fluid when running in reverse. The most reliable method for ensuring that a pump rotates in the correct direction is the use of phase rotation instruments before the Electrical Submersible Pump is run into the well.

11 Voltage adjustment

The voltage supplied to the downhole Electrical Submersible Pump can be adjusted by selection of different secondary tappings on the transformer. The exact voltage required will depend on the cable losses, which will be proportional to the current drawn by the motor. The optimum voltage can be determined either by calculation or, in case of doubt, by experimentation.

An ESP motor will draw an increased current if supplied with power at a voltage which is either higher or lower than the optimum. Measurement of the current at each of the voltages available from the transformer allows the optimum voltage to be determined. At the optimum voltage the current drawn will be at a minimum.

12 Initial testing

Following the initial start-up and stabilisation of an Electrical Submersible Pump installation the pressures and flow rates must be accurately monitored to enable an initial estimate of the pumps performance. If a pump is found to be operating outside its design range, remedial action should be considered. Remedial action might include:

·adjustment of surface choke;

·stimulation (reperforation);

·Electrical Submersible Pump replacement;

·installation of a VSD.

This article describes the key items to address to develop a Wellhead Procurement Strategy.

Vendor selection

To qualify as an acceptable equipment supplier of Wellheads and Christmas trees, the potential supplier's technical ability, quality assurance plan, and commercial viability should conform to internationally acceptable standards and be auditable.

Tendering

Before issuing requests for proposals it is advisable to check if existing supply or price agreements for identical or similar equipment are available. Where such agreements exist, negotiations on a single source basis should be considered. This practice increases the benefits of standardisation and price. It is also possible that a centrally negotiated or tendered worldwide price agreement for wellhead equipment already exists.

Tender specifications

It is a practice to use the nomenclature of a known manufacturer when specifying equipment requirements. This can lead to mistakes and sub optimum design. It is recommended to issue tender specifications which include a functional description of the required equipment, details of the environmental situation, and information on the produced fluids and gases.

This approach gives more enterprising manufacturers an opportunity to submit alternative and sometimes more suitable designs, without invoking the risk of being disqualified because of not adhering to the specification. Provision of a functional description will make it easier to evaluate and qualify designs submitted by potential suppliers. This means the final decision on the acceptability of a proposal will be based upon its design and its suitability according to the specification issued to bidders.

Technical evaluation

The recommended method for evaluating the received tenders is based on a series of tables. These tables break down the bids into discrete sections so that each aspect of the tenders can be compared, e.g.:

• General Requirements
• Technical Specifications
• Standard Equipment, Non-standard & Emergency Equipment and Tools
• Tubing Head, Xmas Tree and Suspension Equipment & Tools
• Handling, Operations & Safety
• Summary of Scores
• Scores Weighted per Items & Groups

It is important therefore that the method of technically evaluating the bids is decided upon before any invitations to tender are issued.

Before rating the proposals, bidders should be coded for ease of reference.

The general requirements are considered for each bidder and given a rating from O (unacceptable) to 3 (exceeds requirement). Each rating is then multiplied by the weighting factor

The ratings are established for the hardware characteristics:

-Handling, Operations & Safety.

Contracting out

When the technical and quality related requirements of all bidders has been compared and evaluated, it merely suffices to award the purchase order to the supplier that offers the most cost effective and safest solution for the operation and its ongoing service support or the fastest delivery.

The purchase order, contract or supply and stocking agreement should address the following elements:

• Focal point for project management
• Quality requirements (normally API 6A with PSL specified as appropriate)
• Manufacturing point (QA rating acceptability)
• Price basis (FOB, C&F or other)
• Fixed pricing to end of contract or 12 months minimum with an agreed cost escalation formula in the contract for thereafter
• Quantity discount structure for subsequent orders if any, or linking the contract to other contracts already existing with other Opco's
• Packaging and FOB charges to be negotiated separately and not to be quoted as a percentage of the equipment value
• Payment terms
• Bank guarantees (if required)
• Spare parts proposal with quoted prices fixed for the first five years of operation and an agreed price escalation formula thereafter
• Required level of after sales services specified
• Availability of Field Service Personnel and their cost
• Buy back clause for equipment remaining at contract campaign end
• Provision of running tools on Loan/Rental
• Quality Control requirements
• Inspection programme during the manufacturing Process
• Quality Plans, where applicable.

This article describes the preferred approach to various aspects of Christmas tree design, with regard to pressures, types of well, equipment, experience, operability and safety. All wellhead valves and components should comply with the current edition of API Specification 6A.

Definition of a christmas tree

A Christmas tree is the cross-over between the wellhead casing and the flowline to the production process. It is defined as all the equipment from and including the wellhead connection through to and including the downstream flange of the choke.

A Christmas tree controls the wellhead pressure and the flow of hydrocarbon fluids and enables the well to be shut off in an emergency. It also provides access into the well for wirelining, coiled tubing and logging operations.

The tree must be designed to withstand all pressure levels such as gas lifting, gas injection, and the pressures arising due to a fracture or kill operation.

Types of trees

There are two types of tree: solid, and composite. Solid trees are machined from single blocks of material. Composite trees consist of standard valves bolted together about a central body.

Solid type tree

The advantages of using trees constructed from a single block of material is the reduction in potential leak paths, and their higher pressure rating. Experience in using solid trees has concluded that the side arm orientation should be reverse "Y". This configuration provides fluid cushioning and limits wall erosion, although it does make the hook up of flow lines difficult. A compromise is to use right angle outlets, which also makes internal inspection easier and is the preferred option. To further ease maintenance and replacement, the flow wing and kill wing outlets should be studded. The solid type tree is also used for dual completions.

Solid type fire resistant tree

Ultimately a so called fire resistant tree is not fire proof. In combination with its large size and difficult configuration this type has not been shown to be cost-effective.

Composite trees

This type of tree should only be used for low pressure and low risk applications. Selection should ensure that the valves used have been designed for this type of application, and that gaskets do not project into the core of the tree and thereby obstruct the flow and wireline tool strings. All other features should apply equally to both types of tree.

Operating philosophy

Before starting the design process it is recommended that an operating philosophy and a reference plan be produced.

Operating philosophy

The operating philosophy shouldconsider the needs of production operators, well services personnel and personnel involved in the asset management of the well.

The designer should be familiar with the current statutory requirements for the installation and before commencing any design work should ascertain the following information:

·Regulations governing the provision of one or two master valves.

·Statutory requirements on the maintenance of the tree and other related pressure equipment.

·Required maintenance frequency; what, where, when, and how.

Reference plan

A reference plan is required to measure the true performance, availability, and OPEX of the well. This plan should indicate the major events over the lifespan of the well. This will ensure that the customer's requirements are followed and maintenance has minimum negative impact on the well(s) production capability.

Operating envelope

The Operating Envelope is a list containing information describing the well, and giving the parameters of various properties. This information should be gathered before design on the Christmas tree commences. The information in the envelope should cover the total lifespan of the well and include fluid properties, surface pressures, temperatures, flow rates, solid and gas content, etc.

Repressurisation

An important consideration in designing surface equipment is repressurisation after a shutdown, a SCSSSV leak-off test, and tree maintenance. It is essential that the repressurisation facilities of the well are adequate and the method for achieving this must be documented at the beginning of the design phase. The proposed method should also be communicated to the facilities designers for consideration. There are various methods and each is dependent on the circumstances and the design of the well.

Chemical injection

For environmental, OPEX and logistical reasons chemical injection should be avoided. Therefore passive corrosion protection is preferred over active corrosion protection.

To achieve this, materials can be selected that can eliminate the need for corrosion inhibitor injection, although this is likely to increase CAPEX.

However there are situations, such as hydrate prevention that demand the injection of a chemical such as methanol and/or glycol. In this situation the general guide for all chemical injection should be followed.

Injection lines should be designed in compliance with the general safety principles. Chemicals should be injected into the main body of the tree where the fluid flow is most turbulent and injection points should be large enough to withstand shear forces. The diameter of the injection line should be as large as possible and the connection to the tree flanged. For example 21/16" (50 mm) diameter is adequate to withstand most shear loads and vibration. Ring joint flanges can be used but cognisance should be taken of the comments on BX joints.

Sampling

For well monitoring purposes it is necessary to take samples regularly at the wellhead. The design of sampling points should follow good oilfield practice. The point at which the sample is taken should be at the lowest pressure possible. It is not policy to provide sampling points on the body of the tree. When a sample has to be taken close to the Christmas tree the sample point should be downstream of the choke, at the lowest pressure and at a point of high turbulence, to ensure that a representative sample is obtained.

Measurement

To maximise production it is essential to monitor the wellhead pressure and temperature. The preferred approach is to install an instrument flange, with ports for the sensors, between the FWV and the choke. The flange can also be used for chemical injection. The flow measurement is normally taken on a straight section of the flowline.

It is not recommended to take pressure readings from the tree cap. To do this would mean that the Swab valve would have to be open. Failure of the tree cap seal would result in a safety hazard and possible environmental pollution. The Swab valve should normally only be open during wireline operations. Should a hot CITHP be required after a regular well test, this is considered to be a planned event, and therefore the pressure can be taken from the tree cap with the Swab valve open as part of the well test procedure. After the HCITHP is taken the Swab valve should be closed.

Kill philosophy

In production systems the policy is to regard well killing operations as a planned event. Although kill facilities should be available, for logistical and economic factors, it is not policy to have permanent hooked up kill systems to producing wells.

Before the design of a well is started the routine (planned) kill philosophy during all stages of the well(s) lifespan must be determined. This philosophy will determine if a kill valve or even a kill connection is needed. For example the kill philosophy will dictate a tubing or casing kill and appropriate connections should be made for this.

Safety criteria

Christmas trees and ancillaries must be designed to meet the minimum safety criteria and the installation should be suitable for its intended purpose. The design should comply with internationally recognised standards such as API 6A, ISO 9000.

The safety logic of the process or platform installation should be taken into account during the design. For example, does the plant have emergency shut-down (ESD) and operational shut-down (OSD) systems? If so, what is the operating philosophy during these types of shut-downs? What effect will this have on the design of the tree?

All trees should have a (lower) master gate valve (LMG). This is the ultimate safety barrier and is one of the most important safety devices on the tree. In all wells the principle of operating a valve "one away" from the LMG must be incorporated in the design. The LMG should only be closed in an emergency situation.

When positioning casing outlets, valves, instruments, etc., consideration should be given to the space restrictions for normal operation and maintenance of the equipment. See ASTMS F-1166-88 (Recommended Installation of Valves) or similar.

Valve sequencing

Closure of the actuated valves on a Christmas tree is normally automatically sequenced through a dedicated well shutdown system. Before the design of a well is undertaken, the sequencing of the SCSSSV, SSV and choke must be defined as it will have an influence on the control systems of the tree. References should be made to the Production Operations Philosophy, which contains the departmental standard on valve sequencing.

Typical examples of the sequential valve operations in an integrated production system are:

 ·Emergency Shutdown [ESD]

 1.Choke closes under automatic actuation

2.Flow wing (or injection wing) valve closes

3.Upper master gate valve closes

4.SCSSSV closes.

·Operational Shutdown (Unit Shutdown) [OSD/USD]

 1.Choke closes under automatic actuation

2.Flow wing (or injection wing) valve closes

 ·Planned Shutdown

 1.Choke is closed under automatic actuation, by the operator

2.Flow wing (or injection wing) valve closes

3.Upper master gate valve closes

4.SCSSSV closes (depending on the work to be done).

Closing the choke first has the advantage of stopping the flow across the other valves before they are closed. In remote locations or non-critical low pressure/producing wells this sequence may be different due to the reduced number of valves. However the principle of closing an actuated choke before any other valve should be followed.

In wells with a positive (fixed bean) choke the SSV has to close against the flow, thereby taking the place of the choke in the sequence. In this situation the SSV should have the capacity to survive repeated closures with the well flowing.

It should be noted that where the choke is remote from the wellhead, the section of flowline between it and the Christmas tree should be pressure rated.

Christmas tree selection

Design Parameters

When selecting a wellhead system, the first action should be to produce a description of the parameters of the envisaged process, or the operating envelope. This description will be the basis for the design and selection of equipment for a potential or existing application.

When considering corrosion, attention should be given to the properties of the well fluids, drilling fluids, brine, etc. that come into contact with the equipment.

The data from exploration testing and sampling should be considered as a range of values. Each of these will vary over time between a given minimum and maximum. Depending on the effect that a particular property can have on well equipment, its maximum value, during the lifespan of the well, should be taken as a design parameter.

All aspects of the process in developing a specification of a Christmas tree should be documented: its basic functions, operational requirements, etc.

The type of well should then be classified. For example the design of a tree that will be used for a well producing low pressure water will be different from that of a tree used for a high pressure gas well. To assist in the selection process, wells have been categorised in terms of production rate, pressure rating and gas oil ratio (GOR). These categories are:

 PROLIFIC WELLS

Over 1000 bbls/d.

Over 2000 GOR (scuft/bbl)

Over 600 lb rating. (max. working pressure 1440 psi).

AVERAGE WELLS

500 to 1000 bbls/d.

Under 2000 GOR (scuft/bbl)

Under 600 lb rating (m.w.p. 1440 psi).

LOW PRODUCERS

Under 500 bbls/d.

Very low GOR (scuft/bbl)

Very low pressures.

Consideration should also be given to the potential changes in a well during its productive life to ensure these do not have an impact on the classification of the well. For example changes in GOR, BS&W, gas lift requirement, reservoir pressure, etc., as well as the material specification, type of service C0 2, H 2S, etc.

Wellhead/christmas tree interface

Christmas tree bottom connection

The preferred approach is to use the compact wellhead design. This provides greater safety during drilling and completion phases as well as providing adequate access to the annulus. It also reduces the overall height of the surface equipment.

The bottom connection to the wellhead or the tubing head spool should be rated to the maximum closed-in wellhead pressure. The connection should be designed to accept the shear loads, the loads imposed during wireline, coiled tubing and snubbing operations, such as bending moments of the lubricator, vibration, etc. It must be demonstrated by calculation that the tree/wellhead connection is adequate to meet these demands during its working life.

A suitable connection between Christmas tree and wellhead is the segmented clamp. This device is quicker and safer to install than the more traditional flange and allows the drilling function to line up the Christmas tree accurately with the flowline.

Tubing hangers

During wellhead maintenance and other operations a back pressure valve is normally installed in the tubing hanger. To accommodate this, a profile should be machined into the tubing hanger to receive the valve and/or running tool. This should preferably be a wireline profile, which allows setting and retrieving the back pressure valve to be performed under lubricator control.

It is recommended not to use threaded profiles. Experience has demonstrated that these threads may become corroded or eroded by well fluids. Damage has also been caused by wireline wire passing across the apex of the threads. The same criteria apply for dual completions.

Control lines

The tubing hanger also houses the termination or passage of the control line for the SCSSSV and any other devices fitted downhole. The control line should be a continuous path from the valve nipple to the surface. The wellhead body, however, should not incorporate a fluid path for the SCSSSV control line or other downhole devices. Older designs have had a chamber or path for the hydraulic fluid as part of the wellhead, which provided an easier way of terminating the control line, but increased the number of seals to be installed and tested. When, with the older design, problems were encountered with the downhole device it was possible to exceed the overall pressure rating of the wellhead assembly. For example: it was possible to have a SCSSSV hydraulic pressure of 6000 psi in a 5000 psi rated wellhead. With the pressure path of the control line independent and continuous from the valve nipple to the Christmas tree/Wellhead exit point, this potential problem is avoided.

Casing outlets

The interconnection between wellhead and casing outlet must provide two barriers between fluid flow and environment, and each intermediate annulus should have two outlets on the surface. During the venture life of the well the annuli provide access to each of the casings for:

 ·Pressure monitoring

·Bleed off

·Passage of gas lift gas. ("A" Annulus usually)

·Well kill, via the "A" Annulus.

The outlets for each of the annuli are normally oriented at 180° to each other. The orientation for each of the casing outlets should be the same. This means that the outlets for the ""A", "B"" and "C" annuli should be in line with each other. The "A annulus, production tubing to casing annulus, should be uppermost, the "B" next lowest with subsequent casing outlets below that.

If there is a height constraint, the casing access points may be staggered around the casing head. If possible this should be avoided as it leads to a more complicated casing tie in arrangement, thereby creating access problems and potential safety hazards.

All annuli should have pressure monitoring facilities and sample/bleed off points. Sample/bleed points should be designed in accordance with good sampling practise, with earthing points, drains, etc. Configuration of the tree should be as follows:

 ·"A" Annulus: In the event of a tubing or packer leak the "A" annulus is likely to come under full reservoir pressure. As such it is the most important annulus and should be treated separately from the "B" and "C" annuli. The "A" Annulus should have two flanged gate valves, with the same pressure rating as the tree on each outlet. The outlet used for sampling or gas lift should have a profile to insert a back pressure valve. The other side may be terminated with a flange, needle valve, and pressure gauge.

·"B" Annulus: One outlet should have a single gate valve with a sampling/bleed down arrangement. The other side may be terminated with a flange, needle valve and pressure gauge.

·"C" Annulus: One outlet should have a single gate valve with a sampling/bleed down arrangement. The other side may be terminated with a flange, needle valve and pressure gauge.

When there are more than three annuli on the wellhead these should be treated in the same way as the "C" annulus.

Gate valves

All tree valves are normally gate valves of identical design. The actuated valves on a tree differ in their mode of operation from the non-actuated valves in that they are reverse acting. This means that the valve is closed when the gate is in the fully "out" position. All the valves fitted to the tree and "A" annulus should be capable of withstanding the same pressure as the tree.

Specification guidelines for tree valves

The valve configuration of a Christmas tree should conform to the wellhead safety principle of always providing an ultimate safety barrier. Group policy gives preference to complying with international standards such as ISO, and API, etc., over the national standards such as B.S, DIN, etc. In some operating environments it is even necessary to exceed existing standards.

Recommended features of tree valves

Due to safety considerations it is not recommended to have valves or pipe connections with screwed fittings. Therefore all tree valves should preferably have forged bodies and flanges with a minimum number of penetrations. The recommended design is the true floating single slab, double seat arrangement and non-rising stems, with a (preferably selective) backseating capability. Ideally the stem packing should be metal to metal. However, in some cases elastomeric seals could be allowed.

Wire cutting valve

Sometimes, in an emergency during wireline operations, it may become necessary to cut the wire. In such a situation it is essential that this can be done quickly and efficiently and may be achieved by installing a wire cutting valve in the tree. If installed, this valve should be fitted in the upper master gate position.

The difference between wire cutting valves and non-wire cutting valves is in the design of the slab, and the power of the actuator. With a wire cutting valve it should be possible to cut the largest size of braided wire used (7/32" repeatedly without causing damage to the gates or seats. In some applications a booster, or add-on actuator is used to transform a nominal actuator into a wire cutting one.

Coiled tubing cutting valve

Occasionally during coiled tubing operations it will be necessary to shear the coiled tubing. A coiled tubing BOP has this capability, therefore the installation of a separate coiled tubing cutting valve in the tree is not necessary.

Tree valve actuation

Valves are opened or closed either by hand or actuators. Actuated valves can be triggered automatically or manually. However whether the tree has two actuated valves (UMG and FWV) or a single SSV, they must close immediately when triggered.

Automatic hydraulic actuation is the most common system used. An alternative to hydraulic actuation may be used if it does not compromise the other design parameters.

Automatic actuator design

There are several factors which affect the design of actuators. These are as follows and generally conform to API specification 6A:

·Actuator fluid volume and overall dimensions should be minimised to reduce size and response times.

·For maintenance and replacement, size and weight should be minimised but should not compromise the pressure integrity of the tree.

·All actuators must have a fail-safe action.

·Actuators should not interfere with the back seating capability of the valve.

·In an emergency the tree valves should close in the quickest possible time. The normally accepted time is 10-20 seconds; including the cutting of wire. Factors to consider are the effects of other wells closing simultaneously, system capacities, hydraulic line lengths and diameters. In multi-well systems the hydraulic fluid is bled back to the fluid storage tank, which may create a "bottle neck" in the unit and increase well closure times.

·During wireline operations normal control of the well is transferred to the wireline operator. In an emergency it must be possible for the operator to shut in the well.

·Wireline control of the well is traditionally done by disconnecting the fixed hydraulic line to the actuator and connecting a flexible hydraulic hose. The hydraulic flexible line may be approximately 200 feet long and 1/2" in diameter. When this is done it must be demonstrated by calculation or otherwise, that the actuator closure time is not affected.

·In a wire cutting application the actuator should have enough force to cut the largest size of braided wire (7/32") in use, independent of well pressure.

Although manual tree valves should not have rising stems, some designs of actuator have a central shaft which protrudes from the actuator body when the valve is closed. Care should be taken to ensure "pinch" points are not created between these shafts and any other equipment structure. If this is unavoidable, then stem protectors/shrouds should be used.

Manual actuation of tree valves

Manual valves should not be hydraulically or pneumatically triggered, or have a gearbox. These devices isolate the operator from the "feel" of the valve during its travel and therefore do not provide direct control. If an unnoticed fault develops they may give a false indication of the position of the valve. An operator should be in physical contact with the valve; counting turns to ensure the valve is fully open or fully closed. Experience has also shown manual gearboxes on valves to be maintenance intensive.

Production chokes

Adjustable chokes

As stated earlier, a tree has several important functions, one of which is flow control of the produced fluids. On integrated platforms and modern processing plants flow control from the well is provided using adjustable chokes. These devices have been in operation for many years and are used by numerous cpmpanies.

Adjustable chokes are designed to withstand very high pressure drops and vary the fluid/gas flow at the same time. Control of the chokes may be by simple on/off local manual panels, or sophisticated distributed control systems.

For many years these devices have been used to apportion well flow. The well should be tested frequently and the choke opening (number of steps taken by the actuator, or percentage of choke opening) calibrated against measured well flow. Provided the calibration is carried out frequently and is repeatable this approach is supported. However, it should not be used for fiscal or custody transfer measurement.

The high pressure drops which are normally associated with chokes often cause severe turbulence and eventual erosion in the downstream pipework. This problem should be considered in the design phase. An acceptable solution is to install hardened pup pieces directly downstream of the choke, or target tees instead of flowline bends.

Chokes must always be fitted in accordance with the manufacturers instructions and never be inverted. Flow reversal may cause premature catastrophic failure of the choke internals.

There are several types of chokes available, the main types being:

 ·Control valve types, with trims and plugs similar to process control valves, but designed for high pressure drops

·Variable orifice chokes, normally a needle valve configuration

·Multiple orifice chokes, normally two rotating discs with one or more holes in each disc.

When considering the selection of chokes, the following factors should be considered:

 ·Very high pressure drops

·Erosion of downstream pipework

·The effect of high pressure differentials on start up

·The degree of required choke control

·Valve sequencing and shutdown philosophy

·Maintainability, access for the removal of internals, etc.

·Vibration levels to be expected as a result of the pressure drop

·Acoustic levels during the high pressure drop production phases.

There should be a device to ensure pressure is bled off from the choke internals prior to any maintenance operation.

For more information on the selection of tree chokes see Section 8 to this document.

Positive chokes

Positive chokes are mainly used in remote, non-critical areas, in low pressure applications and where the choke may be some considerable distance from the tree. Once the fixed bean or orifice is fitted, the flow rate from the well cannot be changed. To vary the flow rate a different sized bean must be fitted. This normally entails breaking open the pressure envelope, which should only be done by trained personnel who are aware of the consequences of mis-aligned seals or badly fitted chokes.

As replacing a large bean in a vertically installed choke is a difficult operation, this should be considered during the design phase if this is not to become a serious operating problem. Fixed bean devices should always be installed in accordance with the manufacturer's instructions. They must never be reversed.

Lubricator connection

Single completions

With a flanged tree-to-cap connection (composite trees) and studded connection (solid block trees), due regard should be taken of advice given in the previous article. The Christmas tree bottom connection, this uppermost connection or joint should be strong enough to withstand all the forces that will be imposed on it.

Dual completions

With this configuration the tree connections (each flange for each string), can be 'D' shaped. These are acceptable for low pressure, sweet applications. Their disadvantage is the uneven loading on the bolts of the 'D' shaped flanges. This type of connection should not be used in sour service.

An acceptable alternative for sour service is the figure of eight or oval shaped one piece connection that covers both top outlets. The bolts are more evenly tensioned and the flange less susceptible to differential movement.

Seals

The seal most predominantly used for lubricators is an 'O' seal, with the load being taken by an ACME thread. Provided the 'O' seal is regularly replaced, and pressure tested prior to well entry, this type of joint is wholly adequate.

In very high pressure applications, metal to metal seals have been used and are becoming more widespread. However, a change from 'O' seals to metal to metal seals will mean a change of lubricators and this should be carefully considered against the advantages of this state of the art seal

Close co-operation is required between the designer, drilling personnel, production personnel, engineering staff, and the representative of the  Electrical Submersible Pump supplier.

An integrated discipline approach during the installation phase is important to ensure that the installation is of the required standard, and results in minimum deferral of production.

The quality of work and the procedures employed during installation of Electrical Submersible Pump (ESP) equipment are critical factors in the success of an Electrical Submersible Pump application. Care and time taken in assembly and running of Electrical Submersible Pump equipment can prevent premature failure of the equipment, and will extend runlife.

Prior to installation of an Electrical Submersible Pump (ESP), a meeting should be held with all personnel involved to discuss the running procedures and safety precautions. Also the following mechanical and electrical safety considerations should be considered:

• If the tubing parts, or is dropped into the well, the reel of cable may be pulled from the spooler towards the rig floor.
• The sheave should be hung with a primary hanging device which should be rated to at least twice the maximum breaking strain of the cable. A secondary safety chain should be tied to the sheave.
• Standard safety procedures for the lifting and handling of heavy equipment should be employed. The weight of the (Electrical Submersible Pump) ESP power cable may exceed 10 tons. 
• When electrical power has been connected to the switchboard and junction box, only an electrician or the Electrical Submersible Pump supplier's engineer should open the junction box or switchboard. The electrical supply to the switchboard will be between 380 and 3000 volts. Work on the surface cable requires specialised equipment, and should only be conducted by a suitably qualified electrician. 
• Signs should be displayed on the junction box and motor controller, warning of high voltage. The switchboard, motor controller, vented junction box and wellhead must be properly grounded.

The transport and handling of Electrical Submersible Pump (ESP) components should reflect the high cost and fragile nature of the equipment.

Flexing resulting in permanent distortion of the equipment will cause accelerated wear when the Electrical Submersible Pump is operated. Bearings manufactured from hard, brittle materials such as ceramics are also subject to damage from rough handling and shocks. Limited shock resistance is provided by the use of compliant mountings for these bearings, but these do not provide complete protection from damage if a pump is dropped.

During transport and handling it is important to ensure that Electrical Submersible Pumps, motors and seals are rigidly supported along their length. Manufacturers can provide transport boxes which give limited support. During manufacture Electrical Submersible Pump (ESP) components are straightened to within 0.003 in (0,075 mm). Correct lifting and handling procedures are required to ensure that their straightness is maintained during unloading and while being picked up from the catwalk.

Webbing straps should be used for handling components covered with corrosion resistant plating or coatings, to ensure that the coatings are not damaged.

The assembly of the Electrical Submersible Pump unit and cable connection must be carried out by the Electrical Submersible Pump (ESP) supplier's field engineer. In order to comply with the requirements of the manufacturer's warranty any instructions or recommendations given by the field engineer should be followed.

The engineer should be allow sufficient time to ensure that the assembly of the downhole Electrical Submersible Pump is of the highest possible standards. It is not the intention to give a detailed assembly instruction as these will differ for different makes of pump. Detailed assembly instructions will be available from the vendor and should form part of either the workover programme or be included as part of the standard wellsite reference manual.

The following list gives a guideline as to the minimum checks that should be carried out during the installation process:

• check motor/pump physical condition;
• check mechanical rotation. Equipment should be free from drag or rough spots during hand rotation;
• check oil condition and level. Time must be given for proper filling of oil especially in cold conditions;
• check condition of mating flange surfaces;
• check condition of shaft extensions;
• carry out all electrical resistive checks; 
• check Electrical Submersible Pump intake and discharge condition.

As already stated cleanliness and the requirement to ensure a complete filling of motor and seal assembly with clean oil are paramount requirements for all Electrical Submersible Pump (ESP) assemblies. Installation of the cable pothead should be carefully witnessed to ensure correct makeup of this equipment as due to its small size and the high current passing through it, it is often a weak link in the cable assembly.

Electrical Submersible Pump (ESP) completions are not as tolerant to changes in downhole conditions as other forms of artificial lift. Care must be taken to minimize the well PI impairment.

The density of the completion fluid should be reduced to the lowest value permissible and consideration given to relaxing the requirement for maintenance of a full fluid column to surface (for depleted reservoirs incapable of flow). This will ensure that losses will be minimised and pump and motor load at startup (which is proportional to fluid density) will be minimised reducing the stresses imposed on the Electrical Submersible Pump (ESP) assembly and the maximum motor temperature.

The cleanliness of the wellbore and well fluid is also essential to avoid damage to the Electrical Submersible Pump (ESP) assembly or plugging of intake screens. Solids which may be present on the wellbore include: scale; rust; packer rubbers; electrical tape; debris from perforating guns; ball sealers; mud and cuttings.

Every effort should be made to ensure that all debris, scale, and other solids present are removed by circulation prior to installation of a pump. LCM should not be used.

Following a stimulation care should be taken that all unspent acid or solids are properly removed from the well. If back production of significant quantities of fines or sand is expected after a stimulation, the well should be produced clean using an alternative form of lift prior to Electrical Submersible Pump (ESP) installation.

Well deviation and dogleg severity should be checked prior to Electrical Submersible Pump (ESP) installation. If the maximum dogleg severity exceeds 3°/100 ft at any point above the pump setting depth, the pump supplier should be consulted to confirm that the Electrical Submersible Pump (ESP) assembly will not be damaged while running into the hole.

A scraper and gauge ring should be run prior to Electrical Submersible Pump (ESP) installation to ensure that no cement or 'tight spots' are present in the casing. The clearance between an Electrical Submersible Pump (ESP) assembly and the casing is often small, and damage to the pump or cable may result if the internal diameter of the casing is smaller than expected.

The following procedures on handling of equipment and cables are recommended to properly install or pull an Electrical Submersible Pump unit:

• The Electrical Submersible Pump, motor, and cable must be assembled and handled during installation or removal according to the manufacturer's instructions.
• The Electrical Submersible Pump (ESP) supplier's field engineer should be present whenever a pump is run or pulled. Time should be allowed to ensure that the ESP is assembled and filled with oil correctly and care taken to prevent moisture or dirt from entering the equipment. Considerable time may be required for oil filling at low ambient temperatures. Failure to fill the motor and protectors correctly with oil will lead to premature failure of the Electrical Submersible Pump (ESP). Electrical checks of the downhole unit and cable should be repeated every 2000 ft (600 m) while running in the hole to ensure that the cable has not been damaged.
• Although considerable improvements have been seen in cable splices they are still a significant source of ESP failure. Where possible splices should be made in a controlled environment and the number of field splices should be minimised.
• Flexing and distortion of the Electrical Submersible Pump (ESP) assembly or its components should be avoided to prevent damage or premature failure. Appropriate lifting equipment and techniques should be used when lifting components of the ESP assembly to the rig floor to avoid flexing. All equipment should be handled utilising a spreader bar to prevent damage. The use of slings is not recommended.
• Downhole equipment must be run with care, and the appropriate type and number of cable protectors used to minimise damage resulting from the cable rubbing against the well casing, particularly in deviated wells and wells with liners or other restrictions.
• Motor centralisers should be used to provide additional protection for the cable and to ensure that the motor remains centred in the casing. This ensures that fluid is able to flow around the entire circumference of the motor to give maximum cooling efficiency, and to avoid hot spots in the motor.
• If any damaging act occurs (such as the dropping of the Electrical Submersible Pump assemble during transport) the equipment should be replaced until it can be checked at a workshop as internal damage is often not visible on the outside.

Checks prior to running an Electrical Submersible Pump (ESP)

Well and derrick

• A tubing pup joint 4-6 ft (1.5-2 m) in length is required to run the Electrical Submersible Pump. It should be of the same size and connection type as the production string.
• Provision should be made for installation of the cable sheave approximately 30 ft (10 m) above the rig floor. The cable should be kept below and clear of the backup tongs. 
• The tubing slips should be of a type which will avoid damage to the cable, and prevent the cable from becoming wrapped around the tubing. Backup tongs should be available for tightening of the tubing.

Electrical Submersible Pumps  equipment

• Check that the Electrical Submersible Pump (ESP) assembly has been run under load prior to shipment. Check that the flowrate, head, and power data recorded while testing has been provided, and in accordance with the design.
• Check material and equipment to ensure that all items shipped have been delivered to the location.
• Check that the surface equipment is certified for use in the intended location, and has the required zone classifications.
• Remove box covers and note the type and serial numbers of all items of the ESP equipment. Information should be taken from the nameplates on motors, pumps, gas separators, seals, flat cable extension, well cable, and switchboard.
• Ensure switchboard is located at least 150 ft (50 m) from the wellhead and that the vented junction box (if required) is installed between the wellhead and switchboard.
• Check switchboard for proper fuses, potential transformer set-up and current transformer turns ratio.
• Check to see if flat cable is of the proper length and type for the motor.
• Check design of Electrical Submersible Pump (type and number of stages) against the completion programme. 
• Check that the power transformers are of the correct type, and that the primary and secondary voltages and kVA ratings are consistent with the power supply and motor type.

Electrical Submersible Pumps Power supply

The transformers, generators, and junction box will normally be installed prior to moving the rig onto the location. The equipment should have been checked and confirmed to be operational by the responsible electrical engineer prior to the rig move. The positions of the items should be checked and the ratings compared with the pump and motor specifications. Provision for required surface cut-out switches (overpressure and/or no flow switches) should have been made and discussion with vendor representatives held to ensure correct hook-up with surface controllers.

Sequence of Operations:

1. M/U flow head assembly and pressure test selectively to 150 bar as follows:

1) From bottom up against bottom master valve.

2) From bottom up against swap and fail safe valve.

3) From bottom up through open fail safe valve against low torque valves of kill and flow line.

4) From top down against kelly cock.

Once the pressure test is successful, do not break the connection until the perforation is completed.

Note : - Prepare the BOP stack for running of annular operated tools. It must be possible to monitor pressure all times and bleed off at any desired moment. (Remove check valves if any). A 2", 1502 WECO thread should be available on the floor to hook up the pressure recorder.

2. M/U TCP string as per tool string diagram.

a) 5" bull plug.

b) 5" TCP's (RDX DP charges, 12 spf, 60 deg phasing).

c) 5" Safety spacer.

d) 3 3/8" Mechanical Firing Head.

e) 2 3/8" EUE Tubing (1jnt.).

f) X-O: 3 1/2" IF box x 2 3/8" EU.

g) 5" Radial Shock Absorber.

h) 5" Vertical Shock Absorber.

i) 3 1/2" Ported Sub.

j) 7" RTTS bottom Straddle Packer.

k) 3 1/2" DP (+/- 450 m)

m) 7" RTTS top Straddle Packer.

n) RTTS Safety joint.

o) FUL-FLO Hydraulic Circulating valve.

p) Jar

q) APR OMNI Circulating valve.

r) RD APR-TYPE "A" Circulating valve.

s) Radioactive Tag Sub.

t) 4 3/4" DC's (+/- 150 m).

u) 3 1/2" DP (to surface).

Note : - Measure the distance from mid-packer rubbers (bottom straddle) to top shot (should be 10.81 m). This is important as there is only 12 m between the bottom of the existing perforations and the top of the proposed perforations.

- Measure the distance from the bottom of the string to the top shot and from the top shot to the radio active marker sub.

- Ensure that the OMNI valve is in position 15.5 (refer to diagram).

3. RIH TCP string on 150 m of 4 3/4" OD Drill Collars. Drift DC's. Fill up with clean KCL brine. Test to 300 bar.

4. RIH on drifted, 3 1/2" DP to +/- 2372 m.

Note : - Sparingly dope pin ends of DP only.

- RIH 1 stand/minute. Fill up whole string with brine.

5. Rig up Schlumberger. Run GR-CCL and correlate. Perforation intervals as follows:

2297-2312 m AHORT (net 15 m)

2330-2347 m AHORT (net 17 m)

2362-2380 m AHORT (net 18 m)

Note : - Reference log LDL-CNL-NGS-AMS dd 11.02.88

- ORT-TBF = 7.98 m

- Determine gun spacing from position of radioactive marker.

- The top straddle packer should be above the top of the existing perforations at 1834 m.

- The bottom straddle packer should be below the bottom of the existing perforations at 2277 m.

6. Space out string such that the flow-head can be installed at an appropriate working height with the guns at the required depth.

Note : - Ensure the kelly cock is not across the BOP rams.

7. Set RTTS Straddle Packer with 20,000# weight.

Note :

- Prior to setting packer, at the packer setting depth, pull an extra 15 cm to compensate for the packer stroke.

- Mark the string at RT level as the packer is set. Check the distance from the original mark to the new mark and check against the space out calculation.

8. R/U kill line to the pump unit and the flow line to the choke manifold. Pressure test the lines to 200 bar against the flow head and the choke manifold. Rig up nitrogen lines and pressure recorder.

9. Close rams, pressure up the annulus to 1500 psi, and cycle OMNI valve to circulating position 11.5. Hold annulus pressure at first cycle for 10 minutes to test packer seat. Halliburton service personnel should be on floor.

10. Pump nitrogen to displace 600 m of brine out of the drill string.

Note : - Ensure the annulus is open during this operation.

11. Cycle the OMNI valve to well test position 2.5.

12. Install Vann Systems shot detection equipment.

13. Drop Detonating bar. Detect guns fired.

14. Flow well until zero pressure at choke manifold (or brine cushion reaches surface).

Note :

- The brine cushion should not reach surface due to the low reservoir pressure, however, due to the high porosity of the KNNCY (PI=52-76 m^3/d/b), pressure equalisation will occur very rapidly. In order to circulate out the perforation debris it is important to reverse circulate the tubing contents at the earliest point after equalisation.

16. Close the pipe rams and cycle the OMNI valve to position 11.5 (circulating position). Reverse circulate with clean brine until the returns are the correct weight. Dump returns until clean brine returns observed. Reverse circulate at least twice the hole volume.

Note : - If the OMNI valve does not function with annulus pressure, open the APR-TYPE "A" circulating valve by putting an extra 1000 psi on the annulus (total of 2500 psi=172 bar).

17. Cycle OMNI valve to position 2.5 (well test position) and observe well, keeping tubing full, for 10 minutes.

18. Open rams and unseat the packer. Observe the annulus.

19. Reverse circulate tubing/conventionally circulate?. Observe well.

20. Rig down surface equipment and POOH.

Note : - Be prepared for losses. If possible, just live with the losses; keeping the hole filled. If losses are large, cure with HEC. As a last resort use salt graded LCM.

Attachments:

- Downhole sketch.

- TCP string configuration.

- Straddle packer diagrams.

- OMNI valve toolposition diagram.

Contractors:

- TCP ASSEMBLY: Vann Systems

- FLOW HEAD/TEST STRING: HES

- NITROGEN SERVICES: HES

- GR-CCL: Schlumberger

General notes:

- All depths refer to TBF unless stated otherwise.

- KCl brine: SG 1.08, 3% KCl with 1 litre/m^3 Coat B1400X inhibitor (pH=10). The brine does not have to be filtered on site, but should be ordered as a 20 micron, filtered brine with less than 20 ppm solids. It is very important that all the hoist tanks; and the trucks used for the transportation of the KCl brine, are clean.

This article describe the requirements and specifications for workshop intended to support well services operations.

The work undertaken by a typical workshop may include:

• quality assurance checking of new equipment;
• pressure testing of equipment;
• make-up and testing of new sub-assemblies;
• valve testing;
• testing and calibration of bottom-hole pressure/temperature survey equipment;
• maintenance, setting and testing of gas lift equipment;
• maintenance of wireline tools and surface equipment;
• ensuring that all items used meet the various specifications. 

Additionally, the workshop plays an important role in the investigation and analysis of equipment failures. A well-run workshop, provided with all necessary facilities, should enhance the well servicing operations and thus minimise loss of production.

1. Layout

When planning the layout of a workshop, the following should be taken into account:

• The movement of heavy equipment.
• Free access to all the facilities of the workshop
• specific areas requirement for tools returning from field, cleaning, maintenance/ inspection, storage.
• Safe areas for pressure testing must be established.

2. Equipment, general

The following items of equipment are considered necessary in order to undertake general workshop operations:

• Test pump unit, air-driven with 5000 and 10,000 lb/in2 test systems. The unit should be equipped with low pressure/high volume pre-fill pump and accumulators fitted with high pressure relief valve circuits.
• Make-up and break-out torque machine capable of handling minimum and maximum sizes of tubulars, e.g. 2 7/8" to 7".
• Swivel-mounted tubular vices and pipe stands.
• Bench-mounted grinding machine.
• Martin Decker or Foxboro type portable pressure recorder.
• Portable air-driven wire bush for cleaning purposes.
• Horizontal storage racks inside and outside the workshop for storage of tubulars such as sub-assemblies, pup joints, etc. (preferably wall-mounted).
• An overhead travelling crane.
• Vacuum pump for testing valve balls, flappers and seats.
• Standard flat-jaw and tubular vices.
• Equipment cleaning baths.

3. Specialised equipment

Some of the items of specialised equipment which may be considered are:

• Amerada test and calibration temperature bath and dead-weight tester.
• Gas lift valve test and calibration equipment.
• Durometer for elastomer hardness checking.
• Hardness tester (Rockwell, Brinell, etc.) for metals.
• Thread/profile comparator.
• NDT equipment (flaw detectors, eddy-current detectors, etc.).
• Inspection equipment such as:
• inside and outside micrometers;
• Vernier calipers;
• depth indicators, etc.

4. Lifting equipment

All lifting equipment must be inspected and tested on a regular basis, and records kept showing dates of tests, repairs, modifications and maintenance carried out, and by whom.

The above inspection and testing not only applies to workshop lifting equipment, but equally to field operational wireline equipment.

All lifting equipment must be listed in a register, and each item must be stamped with its own unique number.

5. Access

Access is an important factor to be considered in the layout of a workshop.

6. Principal operations

The workshop undertakes many tasks in support of well servicing operations.

• equipment procurement;
• make-up of sub-assemblies;
• inspection;
• testing and calibration;
• overhaul and repair;
• certification.

6.1 Equipment procurement

Replacement of unserviceable equipment and acquiring additional new equipment to meet changing demands is generally part of the service provided by the well services workshop.

6.2 Make-up of sub-assemblies

A workshop makes up completion sub-assemblies from their component parts in accordance with requirements. This may not be possible at the well-site because of lack of facilities. Completed sub-assemblies are normally ready for immediate use on leaving the workshop having been drifted, functionally checked, operated, and pressure tested.

6.3 Inspection

No item of wireline or sub-surface equipment should be used in the field which has not been thoroughly inspected in the workshop, in order to prevent unnecessary delays at the well site.

Items such as link (spang) jars, hydraulic jars, knuckle joints, thread connections and all toolstring components utilised in H2S service should regularly undergo crack detection inspection.

6.4. Testing

Testing forms a large part of the work undertaken by the workshop. It supplements inspection to ensure items are suitable to meet the design requirements of the well, and can play an important role in the investigation and analysis of equipment failures. Testing must ensure that the item being supplied for use in the field conforms with the appropriate specification under which it was procured.

6.5  Pressure/vacuum testing

The pressure tests can range from low pressure leak testing of joints to full rated pressure tests of components, and may be carried out on new equipment as a specification check, as a periodic requirement for such items as lubricators, or on repaired/refurbished equipment.

Following testing, the items should be clearly marked with a stainless steel band or label which tabulates the working pressure, test pressure, date of test and service (H2S or Normal).

Critical items of equipment should also be checked for wear, cracks and wall thickness and be appropriately colour coded.

6.6 Functional testing

Functional testing must be applied to all items which have moving parts, such as sliding sleeves and safety valves.

6.7 Gas lift valve charging and testing

It must be appreciated that the efficiency of a gas lift installation depends upon being able to predict the performance of the gas lift valve operation in the installation. If the operating pressure settings alter and become scrambled in the well, the installation cannot be expected to perform as designed with a subsequent loss in production.

For testing the setting pressure of tubing sensitive (fluid operated) gas lift valves, both casing and tubing pressures must be simulated on the test equipment.

6.8 Overhaul and repair

After overhaul and/or repair, each item must be inspected and tested as appropriate, to ensure that it again conforms to specification and can be re-used. It is for this reason that manufacturers' performance data, as well as maintenance and assembly tools, jigs and instructions should be readily available, and these should always be ordered with the original equipment.

6.9 Certification

It is the responsibility of the well services department to ensure that all items of surface and sub-surface well services equipment are inspected, tested and maintained in accordance with the appropriate certification requirements.

7. Safety

Many of the activities undertaken in a workshop, such as moving heavy items of equipment and pressure testing, are potentially hazardous to personnel and equipment. It is essential that these hazards are minimised as far as possible. This can be achieved by careful design of the workshop layout, by the establishment of safe working practices, and by the alertness and training of workshop personnel.

In the final analysis, the safety of personnel and equipment depends upon the skill and judgement of the workshop personnel themselves. It is the responsibility of the Workshop Supervisor to ensure that workshop personnel have received all necessary training and are competent to undertake any task assigned to them. Only fully trained personnel should be allowed to work without direct supervision.

8. Storage and preparation for shipment

All items of equipment should arrive in the field serviceable and ready for use. Damage during storage and transportation must be avoided. This can be achieved by adequate protection being applied immediately the item is finished in the workshop.

Finished items should be stored away from workshop activity and accessible for loading and transportation.

SSDs, SCSSVs, packers, travel joints and swivels, especially in the larger sizes, should be stored with their longitudinal axis in the vertical plane. Such an arrangement will ensure that elastomers in the form of "O"-rings. "T"-seals and "V"-packings are not permanently deformed by weight, thereby curtailing their sealing function.

The open ends of tubular sub-assemblies and other similar items must be capped or plugged, and ports must be taped over, to keep them clean from foreign objects and dirt.

Large tubular items should be stored off the floor and supported at several points along their length; it should not be possible for these items to knock against each other during transport. Items which external seals should be treated with special care, the seals must be protected, preferably by a purpose built, rigid container. Smaller items should be stored and transported in containers in which they will be protected by being clamped or padded. Lubricators and lubricator components are to be fitted with blank quick unions or protectors to prevent thread damage and ingress of dirt.

Particular mention should be made with respect to the storage of elastomers, due to their susceptibility to ultraviolet light and temperature. It is preferable, especially in tropical areas, to store all elastomers, completion equipment such as SSDs and packers which contain elastomers, in air-conditioned rooms/stores.

9. Servicing records

Detailed records of all work performed, technical data, inspection and test results in the workshop must be kept. It should be possible to locate any piece of equipment easily and quickly, and determine its current status. In many cases this may be a requirement by local authorities, such as for SSSVs.

10. Gauge room

An air-conditioned store room must be available.

When buying tubulars, reference should be made on purchase orders to relevant international standards, such as API Specification 5CT and API Standard 5B on specifications for casing, tubing and threads.

In the case of tubulars for example:

1.API SPEC 5CT, "Specification for casing and tubing". Covers seamless and welded casing and tubing, couplings, pup joints and connectors in all grades. Processes of manufacture, chemical and mechanical property requirements, methods of test and dimensions are included.

2.API STD 5B, "Specification for threading, gauging, and thread inspection for casing, tubing, and line pipe threads". Covers dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications and certifications, as well as instruments and methods for the inspection of threads of round-thread casing and tubing, buttress thread casing, and extreme-line casing, and drill pipe.

API Specification 5CT also includes suggestions for the minimum contents of a purchase order (with references to the appropriate sections of the Specification) together with a list of optional specifications which may be selected. Optional specifications are available for pipe coatings, drift requirements, hydrostatic test pressures, thread protectors, etc.

Where the lifting/handling facilities permit, longer tubing lengths should be specified to reduce the number of connections and reduce running time. However, consideration should be given to the workover/pulling hoist capabilities.

Standard sizes should be specified whenever possible. Standard drift sizes are given in API Specification 5CT Section 5, while sizes for alternate drifts are given in Section 6. Pipe which is drifted with the larger mandrels should then be marked as per Section 10 of the same document.

Drift mandrels for casing (API Specification 5CT), are a minimum 12 in (0.3048 m) in length, and those for tubing are a minimum 42 in (1.0668 m) in length.

Based on API nomenclature tubulars having a body OD less than 41/2 in (0.1143 m) are called tubing and larger sizes are called casing. In operations however, 51/2 in (0.1397 m) and 7 in (0.1778 m) OD pipe is often used as tubing and pipe having an OD of 41/2 in (0.1143 m) or less may be used as casing in slimhole drilling. Thus, drifting practices should be based on the application of the tubular rather than purely on size.

At the time of ordering it should be checked that all components of the well are dimensionally compatible with the selected pipe and couplings. It may be necessary to specify smaller dimensional tolerances than are given in API Specification 5CT in order to ensure compatibility and sealability, especially for premium connections. For example, API Specification 5CT cites pipe body outside diameter tolerances as +1.0%/-0.5%. Reduction of the pipe body tolerances to +0.75%/-0.5% will eliminate these problems and improves the collapse load bearing capacity.

It should also be ensured that, where necessary, these components are at least as strong as the weaker of the pipe or the connections. Such components include pup joints, cross-overs, hangers, packers, and flow control equipment. A minimum check on these components should include:

• through bore;
• body and coupling OD;
• tensile, collapse and burst rating;
• material specification;
• thread type;
• temperature rating.

Suppliers of accessories should be encouraged to purchase threaded tubulars for use in their products, direct from the mill which supplies the associated tubulars. Otherwise, the cost of cutting threads on the finished product is often excessive.

Note: It should be ensured that the connection thread is concentric with the pipe internal diameter. One way to achieve this is to specify that the machine tool chuck is placed on the internal diameter of the pipe body when cutting the thread.

Guidelines for storing, handling and transporting completion tubing

1 Storage

The design of pipe racks depends on local conditions (load capacity, degree of permanency, etc). Racks can be made with pipe supports (stringers) set on concrete or wooden bases. Drilltec aluminium racks should be considered for certain tubulars such as CRAs (Corrosion Resistant Alloys). Spacing should be around 2 m which allows 20 ft joints to be stored on two stringers and 40 ft joints on four stringers.

Tubing should be stacked with separators between layers. Separators in the layers should be vertically aligned to avoid bending of the pipes. Timber (with a wedge at both ends) of around 10 cm can be used as separators. Fresh timber should be avoided as the moisture squeezed out can cause corrosion and pitting of the tubing in contact with the separators.

For drainage in wet climates, it is recommended to separate the joints with a wedge or T. The racks should be tilted towards the pin-end and the pipe fitted with open-ended protectors.

For space requirements, the following points should be considered:

• height of stack;
• diameter of tubing (including coupling);
• range of tubing and total footage;
• size of pipe racks; 
• working space.

In accordance with API RP 5C1, the height of the stack should not exceed 10 ft (3 m) including the pipe rack. For small quantities, particularly small diameter tubing, it is impractical to build a stack to the maximum height. The height must be reduced and the width increased in proportion. (A rough guide is that the height of tubulars in a stack should not exceed the base width). Therefore when planning pipe racks, allowance must be made for small quantities which require more space than the API table indicates.

The length of each pipe rack should be sufficient to accommodate Range 3 tubulars.

A lane not less than 20 ft (6 m) wide should be allowed on either side of the racks for transport and handling operations, with a space of approximately 5 ft (1.5 m) between racks.

·The tubing should not be stacked directly on the ground, the first tier should be at least 50 cm from the ground.

·Metal-to-metal contact should be avoided, this includes supports and other joints of tubing. Plastic separators and chocks are preferred as the moisture within wood (which may have been treated with chemicals such as chlorine) will cause local corrosion, especially where CRA pipe is being stored.

·Thread protection should always be fitted to protect the threads from impact and corrosion damage, and the tubing racked with at least 5 cm (2 in) between the tubing ends to allow the threads to be cleaned/inspected.

·A maximum stacking height must be maintained, e.g. 5 tiers for 41/2" tubing.

1.1 Storage administration

Tubing and casing should be stored according to size and grade. Electronic tagging will aid in this respect and will facilitate the central filing of the steel mill certification and pipe inspection reports.

Outside storage of CRAs in coastal regions for more than four months is not recommended.

API coding specified in API 5CT relates to the 4 categories of tubing, listed below:

• Group 1: All tubing in grades H, J, K and N, e.g. H40, J55, K55 and N80.
• Group 2: All restricted yield strength tubing in grades C and L, e.g. C75, C75 13 Cr, C90, C95 and L80.
• Group 3: All high grade tubing in grade P, e.g. P105 and P110.
• Group 4: All special service tubing in grade Q and/or wall thicknesses agreed upon between the purchaser and manufacturer, e.g. Q125.

Groups 1, 3 and 4. Each length of tubing should be colour coded by a paint band or bands encircling the pipe at a distance no greater than 0.6 m (2 ft) from the tubing coupling or box, or on the collar itself.

• H-40 None
• J-55 One bright green band
• K-55 Two bright green bands
• N-80 One red band
• P-105/110 One white band
• Q-125 One orange band

Group 2. Each length of tubing is colour coded by one of the following methods:

• paint band or bands encircling the pipe as for the previous grades;
• paint band or bands encircling the centre of the coupling; 
• painting the entire surface of the coupling.

If the entire surface of the coupling is painted, it will be with the first stated colour, i.e L-80 will be painted red with brown bands.

2 Thread protectors

There are two types of thread protectors:

2.1 Threaded protector (for transit)

They are used from the mill to the well location, where they are taken off for removal of the storage compound. These are composed of a moulded polymer body reinforced with a cylindrical steel insert; some makes may consist of only polymer. Metal protectors should not be used.

Transit protectors can protect only individual tubing during movement. Protection is not guaranteed when joints are bundled together, since the impact on one protruding joint will be much greater.

Thread protectors with a threaded metal interface are not recommended, especially for CRA tubulars.

2.2 Non-threaded protector (for handling)

They are installed on the pin prior to lifting the tubulars to the drill floor. In most cases it is either clamp-on or an inflatable type.

Clamp-on style protectors designed for API connections can cause seal damage when used for premium connections. The operating mechanism can contribute to seal area damage if the protector is incorrectly installed.

The Klepo inflatable protector is a solid polyurethane circular ring inflated by the rig air supply once it has been installed over the pin end threads. This provides a uniform 360° grip and is independent of thread type. Once the joint is ready for stabbing it is deflated and removed.

2.3 Performance criteria

·Impact resistace / ·Protection against water penetration / ·Resilience to thread stripping / ·Resistance to vibrational loading / ·Chemical resistance / ·Weathering resistance

Thread profile basic functions:

-primary barrier to moisture, storage grease is considered an additional secondary barrier; / a locking fit between the protector and pipe; / a threaded profile along the length of the pipe threads; / the pitch, taper and diameter should correspond within reasonable limits to those of the pipe / the protector should protect the seal from the inside.

3 Preservation

The usual contaminants are the result of domestic and industrial combustion and when close to the sea, wind borne salt. The most expensive method of preservation is not necessarily the most suitable.

3.1 Pipe body

Unless otherwise requested, tubing is ordered in accordance with API Specification 5CT and therefore the pipe body will have a mill coating. The purpose of the mill coating is to protect the tubulars from rusting in transit. Since API is not specific in this respect, the type and quality of these coatings vary as does the length of time the coatings give protection in storage. If the tubulars are to remain in storage for a long period, the mill coating could be supplemented or completely cleaned and re-coated.

Whenever grit blasting is carried out to clean the tubing, extreme care should be taken to ensure that the proper thread protectors are fitted to prevent damage .

Where an internal surface coating is required, the use of coatings which give a thick film should be avoided because of potential problems running wireline tools.

Particular care is required to prevent the corrosion of notch-sensitive tubulars such as C95 and P110. If storage for more than three to four months is foreseen, unless adequately coated when delivered, these grades should be cleaned and coated internally and externally.

As already mentioned, thorough cleaning is essential for effective conservation and all scale, rust, dirt, oil and grease should be removed before any coating is applied. If any deposits on or in the tubulars have contained salts, such as from sea water spray during shipment, the surfaces should be washed with fresh water and then dried.

3.1.1 Pipe body storage compound

·Internal:

• Blacksmith CP 914
• Agma Synergen 718

External:

• Agma Synergen 501 
• Shell Ensis HP

Several external coatings have been identified as only acceptable if the tubulars are covered (e.g. with a tarpaulin). These are:

• Malacote 400;
• Oil Centre Research Inc. 911
• Shell Ensis MD.

Threaded connections storage compound

Recommended storage compounds for thread corrosion protection are given below. Whilst in storage, thread protectors should be removed from time to time (two monthly random stock inspection) to check that the thread compound is in good condition. If in doubt, washing, brushing and re-application of the compound should be carried out.

• Shell Rhodina Grease 2
• Geveko Mercasol 630
• Jet Marine Imperator 1078
• Kendex OCTG corrosion inhibitor
• TSC thread storage compound
• Cortec VC1-369
• Rust Vetco heavy /·RD5

The above storage compounds are not to be used as a running compound.

There are, however hybrid compounds available which can be used for both storage and running. These include:

• Kendex Enviro Seal
• Geveko Mercasol 633 SR Multimake White
• Cats Paw black 712 S
• Bestolife copperfree PTC
• Bestolife 2000 5% copper
• Shell Française SF 3646
• Showa Shell Type 3

4 Transport

Pipe should be externally and internally cleaned before dispatching to the rig site, preferably by water jet blasting.

Pipe should be drifted from the box end to pin end with a suitable 42" long (tubing size) API drift. Metal drifts should not be used. The threads should then be cleaned and inspected.

Extreme care should be taken when lifting pipe:

• when lifting by crane only slings or straps should be used (non-metallic on CRAs). Insertion of hooks into the pipe ends should not be allowed;
• when using a forklift the forks should preferably be padded to prevent damage;
• pipes should not be allowed to collide with each other.

4.1 Road

Always ensure that tubular goods are adequately secured, irrespective of how short the journey may be.

Forces are generated on the load when a vehicle brakes, accelerates, changes direction or crosses road undulations. These forces are frequently greater than the frictional restraint between load and platform which means that all loads must be secured by a restraining device. The device must be sufficient to withstand a force equal to not less than the total weight of the load forward and half of the weight of the load backwards and sideways.

The design and construction of anchorage points through which the securing device can be attached must allow twice the specified capacity acting in any direction. Anchorage points must be firmly attached to the chassis or to a metal cross member or outrigger and where practical with doubling plates.

Prior to moving off with the loaded vehicle all tensioning devices should be checked by the driver and after a few miles the lashings should again be checked, thereafter at regular intervals during the journey.

Onshore it is preferable for the tubulars to be handled separately rather than in bundles.

4.2 Water

The stowage and transportation of tubulars by marine craft will be the sole responsibility of the Master.

It is good operating practice to ensure that tubulars, where possible, be bundled in preparation for handling offshore. When bundled the slings are doubled wrapped and secured with a bulldog grip and a plastic tie-wrap. The bulldog stops the loops of the sling round the bundle from becoming loose during transit, the tie-wrap is an extra precaution to stop the bulldog from slipping.

The reason why the joints are bundled in this way is in case there is a snatch-lift (i.e. while the load is being unloaded from the vessel, the vessel heaves and dips due to wave action suddenly leaving the load supported by the crane) the load will be secure and joints will not become loose and fall.

It is important to ensure that the bundle is correctly balanced for each lift.

4.3 Low-temperature environments

Low ambient temperatures substantially reduce the size of the flaw necessary to cause failure. The following procedures, while being applicable in all circumstances, are particularly important for low temperature environments:

• Do not drop, bend, or scratch the pipe. If lengths of pipe have to be forcibly separated due to ice accumulation, take care not to scar the metal surface.
• Thread protectors should be removed without hammering or shock loading.
• Extra precautions should be taken when stabbing the pipe, since low temperatures reduce the impact resistance of the metal.
• Box and pin should be of equal temperature to ensure proper make-up. Use Arctic grade thread lubricant.

FRP are particularly sensitive to cold climates and require additional care.

5 Storage at wellsite

Tubulars should be handled and stored in the manner as discussed above.

Offshore, CRAs should be washed down with fresh water (not brine/sea water) to wash off salt which may have accumulated during the boat journey offshore. This process should be repeated regularly (i.e. every 7 days) until run.

The length and composition of sub-assemblies is usually dictated by the space and handling equipment considerations. They will ideally be made up and tested (both functionally and hydraulically) in a suitable base workshop.

Read more …

The article identifies the most common factors which can play a role in premature failures of packer seals:

1. Installation procedures

• Storage damage: ageing (heat, sunlight or radiation); distortion (poor support, heavy loads).
• Friction damage: non-uniform rolling or twisting, or abrasion by un-lubricated sliding.
• Cutting by sharp edges: Inadequate taper on corners, sharp edges on ports, seal grooves etc.
• Lack of lubrication.
• Presence of dirt.
• Use of incorrect installation tools.

2. Operational factors

• Inadequate duty definition: Composition of the fluids, normal working conditions or transient conditions.
• Seal peeling due to localised rolling as pressure changes.
• Extrusion due to expansion of the seal (swelling, thermal, explosive decompression) or due to compression.
• Too short decompression times leading to blistering.
• Wear and tearing due to insufficient lubrication.
• Wear damage due to pressure fluctuations.

3. Service life

During normal operation, the service life of a polymeric seal is limited by ageing and wear. The temperature, operating pressures, number of cycles (rotations, sliding, mechanical stress) and the environment have an influence on the total service life. Ageing can be a physical phenomenon such as a permanent deformation, or can be due to a reaction with chemicals in the environment. Wear can be caused by rubbing of the seal against another surface in dynamic applications, or by strong pressure fluctuations in static applications. The wear resistance increases usually with increasing hardness of the seal material. Corrosion of the metallic parts and lack of lubrication of the surface increase the wear rate.

4. Minimum and maximum temperature

The sealing ability of elastomers decreases strongly if the temperature is lower than the recommended temperatures, due to a loss in elasticity. The low temperature properties can play an important role in the selection process for elastomeric seals for sub-sea applications in cold oceans. At high temperatures accelerated ageing occurs. The maximum temperature for elastomers varies between 100 and 300°C. Elastomers which can be operated around 300°C tend to have poor overall strength and poor wear resistance. In the design of the seal, room must be reserved to allow expansion of the elastomer due to an increase in temperature (thermal expansion of seal materials is approximately one order of magnitude larger than that of steels).

5. Pressure

The pressure exerted on the seal can result in a permanent deformation of the seal (compression set).The compression set must be limited in order to guarantee leak free operation. Another problem which can arise at high pressures, is swelling (10-50%) of the elastomer volume by absorption of well fluids from the environment. Limited swelling is acceptable if the seal design has allowed for it.

6. Pressure differentials

The elastomer must have an excellent extrusion resistance if there is a large pressure differential over the seal. Extrusion is the most common cause of failure in high pressure seals at high temperatures. The extrusion resistance of a seal may be increased by increasing its hardness. Harder seals need higher interference and assembly forces for effective sealing. The sealed gap must be made as small as possible requiring narrow tolerances during manufacture.

7. Pressure cycles

Pressure cycles can lead to degradation of the elastomer by explosive decompression. The severity of the damage to the elastomer will depend on the composition of the gases present on the seal material and on how fast the pressure changes. The more homogeneous elastomeric materials (e.g. Viton) are more resistant to explosive decompression than elastomers (such as Kalrez and Aflas) which usually contain many small cavities. Decompression occurs predominantly in gas lift applications. If pressure cycles occur, a tight seal gland is desirable because it limits the seal inflation during decompression. This requirement conflicts with the necessity to have room for thermal expansion and swelling of the seal. In dynamic applications a tight seal gland may result in wear or binding of the elastomer.

8. Dynamic applications

In dynamic applications the friction of the seal with the rotating or reciprocating (sliding) shaft can cause wear or extrusion of the elastomer. With a sliding shaft, rolling of the seal can also occur, which can easily result in damage. A demanding situation is the combination of high pressures and a dynamic application. In order to improve the extrusion resistance of a seal its hardness is often increased. A higher hardness implies also that higher interference and assembly forces are needed which result in higher friction forces. In dynamic applications seal swell should be limited to 10-20%, as swell will result in an increase in the friction forces and in wear of the elastomer. An important property for dynamic applications is a high resilience, i.e. the ability to stay in contact with a moving surface.

9. Seal seat design

The seal design must allow for (10-60%) swelling of the elastomer in oil and gas. If not enough room is available the extrusion of the seal will occur. Another important parameter is the size of the extrusion gap. At high pressures only very small extrusion gaps are allowed resulting in a requirement for tight tolerances. In a number of cases anti-extrusion rings can be applied. The design of the seat should also take into account the installation requirements of the seal. During installation elastic elongation (stretch) should not result in permanent deformation and the elastomer should not be damaged by sharp corners. It is worthwhile to note that gland-seal designs are inherently safe, as the seal is not stretched during installation, which is the case in a piston seal design. On the other hand, gland seal designs are more difficult to manufacture and are difficult to access for cleaning and for seal replacement.

10. Compatibility with hydrocarbons, CO2 and H2S

The penetration of hydrocarbons, CO2 and H2S into the elastomer results in swelling. Swelling by hydrocarbons increases with pressure, temperature and aromatic content. The reversible volume increase is accompanied by a gradual softening of the material. Swelling by gases such as H2S, CO2 and O2 increases with pressure and decreases slightly with temperature. Pressure changes after swelling of the seal can result in decompression damage to the seal. H2S reacts with certain polymers, resulting in cross-linking and therefore irreversible hardening of the seal material. Deterioration of elastomers in seal tests (and possibly also in service) is generally less than in immersion tests, probably due to the protection offered by the seal cavity to chemical attack.

11. Compatibility with well treatment chemicals and corrosion inhibitors

Corrosion inhibitors (containing amines) and treating completion fluids are very aggressive against elastomers. Due to the complex composition of the corrosion inhibitors and well treatment chemicals it is advised to determine the resistance of the elastomer by testing.

The following provides information based on past experience of the retrievability of packers, which provides general trends and guidelines for the execution of such activities. However, every well is different and as such hard and fast rules are not possible to giive. (KW: packer, retrievability, completion, production, well engineering, construction)

Read more …

The following 5 Packer setting mechanisms are discussed in this article:

1. Compression set anchor packer
2. Mechanically set compression packers
3. Mechanically set tension packer
4. Hydraulic set tension/compression packer
5. Action of hydraulic hold-down

   Read more …

The following installation considerations apply to all threaded connections if mishaps are to be avoided:

• drift check and inspect connections before running;
• properly apply correct thread dope;
• backout and re-inspect connections that are stabbed in misaligned position;
• avoid high makeup speeds and use correct torque;
• use pup joint, couplings and cross-overs of the same tubular material, especially in CRA applications;
• additional makeup turns increase 8-round connection leak resistance in tension;
• additional torque reduces tendency of tubing to back-off when running Progressive Cavity Pumps (PCPs), etc. but do not exceed the maximum manufacturers recommended torque.

To ensure that the tubulars are run efficiently to the correct depth and in the desired condition, use of the following equipment and techniques should be considered in the design phase:

1 Hoisting capacity

The designer should be aware of the hoist capacity of the rig/hoist/snubbing unit which is to drill/workover the well. Where deep, heavy strings are required, it may be necessary to taper the string. Alternatively, the drilling/workover sequence may be re-arranged to allow the use of a larger rig for a particular well.

2 Handling

Handling of tubulars between the pipe deck and drillfloor should be carried out in accordance with EP-95000. Many Opcos have developed their own tubular handling and running manuals. Additionally rigs may now incorporate automated tubular handelling devices, such as the Verco International Pipemite.

Particular care should be taken when handling assemblies with pup joints, to ensure that the lifting point is above the centre of gravity. This ensures that the load is stable when lifted.

FRP tubulars are easily handled, but prone to damage, especially in cold climates, because they are light weight and very flexible. This type of pipe should be well supported during handling and should not be allowed to deflect to the point that composite material is over stressed and damaged.

3 Single joint weight compensator

Positioning of the pin in the box during make-up is critical. If no weight is transferred to the box, make-up cannot take place. If too much weight is transferred, stabbing and alignment becomes difficult and galling may occur due to high contact loads. It is extremely difficult to achieve accurate weight transfer with the standard rig hoisting system. The same problems also apply to connection break-out.

Although the susceptibility of connections to stabbing damage and galling can be minimised in the connection design process, controlled and accurate weight transfer is the key to successful make-up.

By the installation of a compensating device between the rig's travelling block and the single joint elevator, the weight of the pipe is neutralised and controlled downward penetration of the pipe is possible during make-up. This is highly recommended for both make-up and break-out of premium connections and/or corrosion resistant alloy (CRA) tubulars.

Service companies can supply single joint compensators in different weight ranges to cover all tubular sizes.

4 Drifting

Drifting should be performed on the pipe rack using a 42" (107 cm) long API non-metalic drift. Drifting from box to pin end, compressed (rig) air will blow the drift through the pipe in the horizontal position. It is not good practice to drift the pipe when secured in the rig V-door.

Additionally it is recommended that on completion of running the tubing, prior to running a wireline plug for pressure testing (if planned), a wireline drift using a gauge cutter should be made:

·tubulars 2 7/8" OD, drift diameter = tubing ID less 3/32";

·tubulars 3 1/2" OD, drift diameter = tubing ID less 1/8".

5 Stabbing

Stabbing guides are available to protect the threads and seals from standing up on the shoulder of the box end. The tubing joint needs to be held vertically over the stabbing guide and lowered in a controlled manner to maintain the alignment and guide the pin end into the thread engagement of the box.

• ·the pipe should not be rocked;
• ·pipe should be rotated with a strap wrench to initially engage threads.

6 Multi-size rig tongs

Automatic rig tongs are available, such as the Weatherford Torque Wrenching Machine, which can make up and break out drill pipe, drill collars, casing and tubing in one machine. The size range is 2 3/8in (0.0603 m) to 21 in (0.5334 m), and torques of up to 140,000 ft.lbs (189,805 Nm) are possible. Associated computer equipment monitors and records each make-up, ref. Section 3.4.8.

Specialist hydraulic power tongs with an integral back up tong should be used; pipe wrenches and standard rig tongs are not recommended.

7 Non-marking jaws

In corrosive operating environments where defects or stress concentrations in the tubular may have catastrophic consequences, the use of non-marking jaws should be considered, not only on the rig floor (tongs, slips, elevators) but also in the threading plant.

Such jaws, based on elastomers, are available from Weatherford and other service companies.

Frank's International and Weatherford can supply power tongs which grip the entire circumference of the pipe by means of fluid pressure applied to a non-metallic gripping surface. As a result, the tubular surface is not penetrated, and stress concentrations are avoided.

Conventional spiders/elevators are another potential problem with CRA tubulars. These are fitted with slip bodies and die inserts which penetrate the pipe surface when the system is activated, as illustrated in Fig. 2369. The force with which the dies are pressed against the pipe surface is increased by the weight of the string being held by the spider or elevator, due to a wedging action.

New systems, such as the Weatherford Micro-Grip system are equipped with thousands of fine teath formed into gripping bars which are imbedded in a carrier bound by an elastomer material that compresses with a radial force. The load is therefore distributed equally onto a large number of small peaks.

Care should be taken to check the tubing after make up for marking on the tubing by the tongs or slips. Should excessive marking be experienced it may be necessary to replace the tubing joint and change out the dies in the equipment.

8 Connection make-up torque

Proper torque values must be applied to obtain an optimum distribution throughout each thread connection and to ensure a pressure tight seal. Make-up to below the recommended minimum torque can result in leaks and/or joint failure/backoff.

Over-torquing may damage the threads or seals and may result in crimping the pipe inwards or belling outwards depending on the seal type.

The make-up torque for a connection should be recommended by the thread manufacturer, the value of which is dependant on the connection type, grade of material, size and weight of tubing.

It should also be noted that make-up torque will vary with different thread compounds and may also vary for different manufacturing batches of the same compound.

The correct make-up of any threaded connection cannot, however, be judged on torque alone. Correct make-up torque can be reached under a variety of unacceptable circumstances such as crossed, dirty, or galled threads. Surface finish variations may also influence the required torque. It is important that adequate pin penetration into the box is achieved to assure design stress levels are achieved in the connection. As a result, torque-turn data are published by the connection manufacturers and can be compared with that measured in the field using portable equipment (e.g. Weatherford JAM system). Torque-time plots are not suitable as they only show how the tong operates. This data is usually based on the use of an API 5A2 formulated compound. The use of a thread compound other than this requires the use of a correction factor (refer to Section 3.3.5.2) to accommodate the differences in friction coefficient. Critical on-site analysis of torque-turn graphs is, at present, seen as the best practical means of identifying potentially leaking connections before they are run into the hole (refer to connection leak testing, Section 3.4.9).

Even with premium seal connections incorporating a torque shoulder, in which final torque is a reasonable indicator of adequate seal pressure, torque-turn measuring equipment is recommended because of the accuracy of the torque gauge.

Soft-torque tongs (from Camco/Bilco or Frank's International) and/or Weatherford's A-Q-Tork system are recommended to prevent overtorque due to the inertia of the rotating pipe/tong mass.

High make-up speeds can cause damage due to a greater tendency to over torque, which produces thread and shoulder damage. It is recommended that 25 rpm or less is applied, especially just prior to final torque. (For CRA tubulars a make-up speed of 15 rpm is recommended).

Most FRP downhole tubulars use 8-round long thread connections and teflon based thread compounds. The make up torque is significantly lower than for steel tubulars and the make up is often performed with strap wrenches. However, without torque control, the potential exists for leaking connections and parted strings. It is particularly important to use the torque values provided by the manufacturer.

9 Connection leak testing

The requirement for leak testing while running or after the tubing has been landed depends on the type of completion, production conditions, location, etc. During the running of tubing two methods are used:

·External testing: This is achieved by setting two packing elements around the pipe above and below the connection, as illustrated in Figure 3.8. Leakage is detected by a drop in pressure of the water pumped into the void between the seals.

·Internal testing: This method tests the connection by an internal test tool straddling the connection. Two methods may be employed:

1. Hydrotesting: A tool activated by water pressure which expands opposing cup packers as illustrated in Fig. 2371. Leakage is detected by a drop in test pressure.
2. Gas testing: A wrap around device containing a helium sensing prope is installed externally onto the connection, refer to Fig. 2372. A pressurised nitrogen/helium gas mixture is applied internally to the tubing and leakage is detected by the presence of helium at the external sensing prope. Safety aspects must not be overlooked because of the high internal gas pressures, ensure gas can escape should the connection leak severely and not allow the surround to be blown off. Special safety precautions should be taken on the rig floor.

Evidence to date concludes that gas-based leak detection tools, which use a spectrometer to detect the leak, work better than the hydrostatic pressure leak detection tools (especially for gas well applications).

The standard system works with a gas mixture of 99% Nitrogen and 1% Helium. It requires a considerable amount of gas and strict safety measures. A more sensitive system uses a small volume of pure Helium gas. Water is used to pre-pressure up the system, after which Helium is used to attain the required test pressure. The advantage of this system over the other is that as less gas is required, it is safer and more sensitive. A pressure test can be performed on the connection from both sides, i.e. from the inside to the outside, or from the outside to the inside.

Field leak detection equipment may not be capable of detecting all leaking connections within a reasonable period of time, since it may take a considerable amount of time (up to 5 minutes) for the gas to percolate through the running compound trapped between the threads. The response time can be improved by limiting the quantity of thread compound applied to the connections but this increases the risk of galling and may result in high shouldering torques, hence is not recommended.

The use of ultrasonic measurements of contact stresses to assess the sealing integrity of connections in the field is being investigated. A field trial on a prototype tool was successful, although further work is necessary. The tool was developed to be able to check Finite Element Analysis stress predictions. It is based on the fact that the amplitude of an ultrasonic beam reflected from an interface is dependent on the contact pressure at that interface.

In many instances where tubing inspections and preparations are rigidly controlled and where adequate, experienced and specialist supervision is available during the well completion with torque-turn graphic interpretation, time consuming testing procedures have been forgone. Testing is limited to being carried out against a wireline/coiled tubing retrievable plug at predetermined phases (e.g. every 20 joints) of the well completion process. As a minimum the complete completion string should be tested on reaching the required setting or packer latching depth.

10 Polymeric seals

Connections that incorporate polymeric seals will require a high degree of on-site supervision of the installation procedures to ensure that the seal is present, clean and undamaged.

11 Mill-end leakages

The major cause of mill-end leakage appears to be improper make up at the mill as indicated by the movement of the mill-end during field connection make-up. The movement causes an unfavourable redistribution of the thread compound solids which were originally plated on the threads when the mill installed the couplings.

API Specification 5CT recognises the leakage problem encountered with mill-installed couplings, and states that cleaning and inspecting threads and applying fresh thread compound before using the pipe results in less chance of thread leakage. These standards make provision for ordering API tubular goods with couplings screwed on hand tight or shipped separately from the pipe. However, it is recommended that tubing be ordered with mill-installed couplings; but if any movement of the coupling is observed during field make-up, the connection should be backed out, cleaned, re-doped and re-made.

It is preferable, particularly with CRA tubulars (with coupled connections) that the applied make-up torque and torque-turn recording is provided with each mill installed coupling.

12 Running speeds

Use should be made of swab/surge calculations to determine the maximum allowable running/pulling speeds. Note that swab and surge pressures are exerted upon the formation irrespective of the location of the tubulars being run.

When running the tubing, especially in a deviated/horizontal well, any restriction to the downward movement withnessed by a reduction in the hanging weight should be investigated to prevent buckling of the tubing.

13 Tubing spacing

The tubing may be set in compression or tension depending on the completion design.

Care should be exercised in the calculation of the tubing length due to the stretch of the tubing for accurate placement of tubing and accessories. If the extremities of blast joints and/or position of packers relative to perforations are within the extremities of the following table, consideration should be given to running gamma-ray casing or magnetised casing collar locators.

Depth / Shallower / Deeper

8,000 / 2.5 / 9.5

10,000 / 4 / 13

12,000 / 5 / 17

Note: all figures in feet.

FRP tubulars require higher safety factors than metal tubulars due to material creep which causes an increase in strain with time, which introduces "design life" concepts unique to FRP tubulars. FRP creep occurs at any temperature, but is more pronounced at temperatures greater than 75°F (24°C). They are quite flexible and prone to buckling and should always be run in tension (do not use in conjunction with compression set packers and minimise compressive loads).

14 General considerations on running completion

Some general points to remember when running the completion string include:

·Ensure that elevators, slips, and power tubing tongs are in proper working order, and correct dies are fitted. Do not use pipe wrenches for manual make up of joints. Apply pipe thread lubricant sparingly to pin and box thread, and sealing areas. Ensure that the correct torque is applied, modifying the manufacturers' recommended figure, if necessary, to suit the thread lubricant used.

• ·Drift each joint of tubing to ensure that no gloves, rags or other foreign bodies have found their way inside.
• ·Record the serial number of each item as it is made-up in the string - this includes the numbers marked on the tubing joints on receipt.
• ·Confirm the operating envelopes of the equipped are appropriate for the expected working parameters.
• ·Supervisors keeping tally should cross-check with each other from time to time to ensure that the string is being made up according to the programme.
• ·Run seal assemblies very slowly into/through packer bores.
• ·The practice of running a tubing string with a plug installed in a landing nipple situated close to the bottom of the string should be avoided. Problems with debris accumulation on top of plugs are very frequent when applying this technique making retrieval difficult. (Note the availability of equipment, such as pump out plugs, to overcome this problem).
• ·Check hanging weight up and hanging weight down methodically and accurately when required to do so.
• ·After tagging the packer with its seal assembly, ensure that any pressure build-up in the tubing can be bled-off when running the seal assembly through the packer to avoid seal damage.
• ·If required to make reference marks when setting down/spacing out, do so accurately, taking care not to damage any special surface finish.
• ·Check the completion fluid for correct composition and maintain the required levels in the tubing and annulus.
• ·When carrying out pressure tests, build-up pressure slowly, in stages to the maximum figures, maintain pressure for the recommended time, and record on a suitable pressure recorder.
• ·Note that test pressures and times may be limited if the well is perforated below the packer to be tested, since the test pressure may also act on the formation.
• ·After spacing out, drift the complete string, using suitable wireline drifts.

The objective of all sand exclusion techniques is to arrest the movement of formation sand into the well. Sand production can cause erosion of well equipment, well restrictions, and sand deposits in flowlines and other surface installations.

Read more …

Perforation prepacking refers to the methods that can be used to pack the perforation tunnels with gravel prior to filling the screen/casing annulus. The main objective of prepacking is to maximise the quantity of high permeability gravel placed in the perforation tunnels (or in cavities behind the casing) which is one of the key factors controlling the productivity of an IGP completion. Field experience indicates that in many cases standard gravel packing procedures do not allow proper packing of the perforations.

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It is advised that onshore meetings will be held between equipment vendor, Company, wireline contractor and drilling contractor at least 6 weeks prior to the start of operations.

Company Representatives

The Company Representatives directly involved during completion operations are:

-           Senior Drilling Supervisor/ Drilling Supervisor

-           Well Site Drilling Engineer

-           Platform Production Supervisor

-           Completion Supervisor

A close liaison and an active co-ordination is necessary amongst the Company Representatives, with the Senior Drilling Supervisor (SDS) having the ultimate responsibility for the execution of all operations.

Task And Equipment Responsibilities

A table specifying the areas of responsibilities for Company personnel is given below. The following definitions are used for the table:

Prime (P): The designated individual is responsible for ensuring that the required activity is carried out in accordance with the programme, and with established practices and procedures.

Check (C): Assistance with, and inspection of ongoing and completed activities to ensure compliance with the programme, and with established practices and procedures.

Some tasks may be delegated by the Senior Drilling Supervisor to the Drilling Supervisor and/or the Well Site Drilling Engineer, in which case a further definition can be used.

*   Material Department will order tubing and pupjoints and take full responsibility for all completion items.

Management And Reporting

The Senior Drilling Supervisor is responsible for communicating all requests and instructions to the Drilling Contractor personnel, but this may be delegated to other Company Personnel involved in the completion operations if deemed necessary. The Senior Drilling Supervisor shall be consulted on all instructions given  to the Contractors.

The Completion Supervisor is responsible for giving instructions to the various completion services/equipment contractors after consultation with the Senior Drilling Supervisor who will check these instructions with regards to safety and well control.

The Senior Drilling Supervisor is responsible for all reporting to the base.

The Completion Supervisor may instruct the Platform Production Supervisor for X-mas tree valve operations during wireline operations after consultation with the Senior Drilling Supervisor.

A representative from each of the contractors shall report to the Senior Drilling Supervisor in the daily Morning Meeting.

The Completion Supervisor is responsible for writing a final Well Completion Status Report stating all downhole equipment such as but not limited to:

-   ID/OD's for equipment, depths, manufacturer and identification number of equipment- and etc. shall be specified.

This report will also contain operational issues, high lights, problem areas, recommendations for future completions, etc.

Pre shift and pre job meetings shall be held between (as a minimum) drilling contractor crew, wireline contractor crew, tubing tong operator, completion equipment representative (if on board), completion supervisor.

Certification

All completion and downhole equipment technical specifications and data books will be held on the platform by the Completion Supervisor.

Perforating is a service provided by specialist companies, however, it is common for Production Operations to be involved in the operation to facilitate well production after perforation in completed wells, or as the responsible party during a recompletion activity. Aspects of well completion design addresses a number of the issues associated with the selection of the specific technique, i.e. wireline run, through tubing, tubing conveyed (TCP),This article provides a brief summary of issues needing consideration during the perforating operation.

1 Perforating through tubing

Perforating through tubing is an old technique. The use of a seal around the cable at surface allows the gun to be run into, and pulled out of the hole with pressure at the surface. This allows the well to be perforated without the presence of excess hydrostatic pressure from heavy drilling or workover fluids in the borehole. The length of guns that can be run together is limited by the height of the surface lubricator required to accommodate the guns, positioning device and collar locator, and the weights that must be run to counter the well pressure.

Three main types of through tubing gun are in use:

• ·those using a fully retrievable carrier;
• ·those using a retrievable carrier strip to support charges that are contained in expendable cases;
• ·those in which all parts of the gun assembly remain as debris in the well.

The most powerful guns are the expendable and semi expendable capsule types. Their advantages must be weighed against the problems that can result from the presence of large quantities of debris in the well and the possibility of casing damage that can result from the more powerful charges and the absence of a carrier to contain the explosion. Hollow carrier guns can be used to perforate longer intervals on each run than capsule guns since the weight of the carrier itself reduces the need for additional weights. In spite of this the maximum length that can be run at one time is limited by the surface pressure equipment to about 10 m.

1.1 Retrievable hollow carrier guns

For through-tubing applications hollow carrier guns are available in sizes from 30 mm (13/16") to 73 mm (27/8"), with the size to be used determined by the minimum internal diameter of the completion string. The maximum shot density with these guns is 19 shots per meter (6 shots per foot). The guns can be configured to give almost any perforation phasing. The reduction in geometrical skin due to phasing is likely to be more than offset by the increased skin due to the poor penetration of the small charges when fired across the wellbore. The guns are therefore normally run with zero phasing, with the gun mechanically or magnetically positioned to minimise the standoff between the gun and the casing. Hollow carrier guns minimise casing damage as the carrier contains the force of the explosion and the high velocity fragments of the shaped charge cases. A cross section of a hollow carrier gun is shown in Fig. 2377.

1.2 Expendable and semi-expendable guns

Expendable and semi-expendable gun performance is generally superior to hollow carrier guns of a similar size. These guns are made up of individual shaped charges, each of which is contained in a separate pressure vessel, supported by wires or carrier strips. When the gun is fired, the pressure vessels, which may be ceramic, aluminium, or steel, are reduced to small fragments which remain in the well. The supporting wires or strips are recovered with semi-expendable guns, but with expendable capsule guns these too are destroyed and remain in the well. The high density debris should fall to the bottom of the well but may be carried up the well by the initial surge flow. In highly deviated wells friction may prevent the debris descending into the well, resulting in steel or other fragmented material being carried to the surface when the well is produced. Damage to chokes, sub-surface safety valves and surface production equipment may result unless provision is made for this debris. The debris will also include some low density polymer material, much of which will return to surface with flow. Fragments of material from the pressure vessel and shaped charge case are driven by the force of the explosion and impact on the casing causing significant damage, which may lead to accelerated corrosion. The size of this type of gun is limited due to the excessive casing damage which would result from large sizes.

1.3 Pivot guns

The Pivot Gun has a performance comparable to casing guns and can pass restrictions with diameters as small as 45 mm (17/8") by using large charges that are assembled in the gun parallel to its axis. When the gun is on depth, the charges are rotated 90° and then fired.

The increased performance of this fully expendable 43 mm (111/16") gun makes it applicable for certain through tubing applications where the inside diameter of the production tubing is considerably less than that of the production casing and where effective shot perforation is an important design criterion.

2. Tubing conveyed perforating (TCP)

Tubing Conveyed Perforating (TCP) allows the power and low debris characteristics of casing guns to be used in conjunction with high wellbore underbalance pressures. Highly deviated or horizontal wells in which conventional wireline techniques cannot be used can be readily perforated with TCP guns, which can be pushed along the hole to the required depth.

Tubing conveyed guns can be run using almost any tubular string, such as drill pipe, production tubing, or coiled tubing. The full benefit of their capabilities can best be achieved by running the guns as part of a completion string, avoiding the need for additional trips into the well. This also allows the Christmas tree and production equipment to be assembled and tested prior to perforating. Perforating can be conducted under any desired conditions of underbalance, and the well can immediately be produced to clean up the perforations. The gun may be fired mechanically, electrically, or hydraulically, or by a combination of these methods. The TCP guns cannot be removed from the well until the completion is retrieved (unless conveyed on coiled tubing or pulled with a snubbing unit), and may remain in the well until a workover is required. The consequences of a misfire are considerably more serious than with wireline guns as the completion or drillstring must be removed from the well if the gun is to be re-run. The reliability of the equipment used for tubing conveyed perforating is therefore of great importance.

The maximum length of gun that can be run is virtually unlimited, depending on the operating parameters of the running string. The maximum gun diameter that can be used is limited only by the inside diameter of the production casing. The increase in gun diameter compared with through tubing guns permits the use of more powerful charges at higher shot densities, improving inflow performance.

3. Perforation cleaning

The results of perforating a well are strongly influenced by the conditions in the well at the time the perforations are made, and the degree of cleaning that can subsequently be achieved.

The formation in the vicinity of the borehole is likely to be damaged by the conventional drilling process, and the perforations themselves are susceptible to damage by invasion of contaminants from the wellbore. Perforating with an overbalanced, mud filled wellbore is likely to increase the degree of damage in the formation in the immediate vicinity of the perforations, causing a further reduction in permeability. The perforation tunnel itself will contain pulverised rock, explosion products, and metallic liner debris which will remain in the tunnel if the wellbore pressure is higher than the formation pressure.

Perforation clean up is a result of both transient and steady state flow. To ensure proper clean up the post shot flow can be extended (indefinitely) by running TCP guns as an integral part of the completion string. However, when "shoot and pull" techniques are employed (e.g. coiled tubing run guns) for underbalance perforating it is important to ensure that adequate flow velocities (and produced volumes) are attained in order to produce debris into the tubing above the flow control valve, otherwise losses will result in perforations becoming plugged by gun and formation debris.

All techniques for lowering the wellbore pressure involve filling the well with a fluid or combination of fluids whose hydrostatic head is lower by a specified amount than the reservoir pore pressure. The means by which this is achieved will depend on the well and completion design, which may allow the use of a sliding side door or side pocket mandrel to provide a means of circulating a low density fluid or gas. For the high drawdown pressures, required for low permeability formations, the well may need to be partially or completely gas filled. Commonly a coiled tubing unit is used to replace part of the tubing contents with a low density fluid such as nitrogen.

If the well is being perforated for the first time, the underbalance can be established by running the tubing into the well empty or partially empty with a plug or valve preventing the entry of well fluid. However, this will preclude internal pressure testing of the completion assembly and may restrict the choice of other completion accessories.

When considering through tubing perforating techniques, drawdown can also be achieved by perforating so called 'trigger' intervals. This principally applies to gas wells, and involves firstly perforating (through tubing) a trigger interval to allow the well to be evacuated to gas. This enables subsequent perforation runs to be carried out underbalance in a gas filled wellbore. This method can also be used to perforate zones exhibiting significant permeability contrasts. Low permeability (trigger) intervals are perforated first to ensure effective clean-up, followed by the more prolific higher permeability zones.

Underbalanced perforating implies that the hydrostatic head of the well fluid prior to perforating is insufficient to control the flow of fluid from the formation into the well, and should therefore only be conducted with surface pressure control equipment, even if the well is not expected to produce fluid to surface. The underbalanced perforation of reservoirs containing H2S may require additional precautions to ensure that the completion is adequately internally pressure tested prior to perforating.

4.  Operational considerations

4.1 Transport of perforating equipment

The transport of explosives is governed by a large number of national and international regulations, to which certain exemptions have been obtained by the perforating companies. These exemptions apply only to limited quantities of explosives contained in their original packing material. The regulations apply to the transport of the explosives from the perforating company base to the wellsite, and to the storage of the explosives on the well site, both of which may be the responsibility of the operating company. The rules governing the transport of explosives to the wellsite by air apply to both helicopter and fixed wing transportation, and in many cases preclude the carriage of passengers on an aircraft carrying explosives. Explosives should be transported in their original packing, which is designed to minimise the risk of an explosion occurring in the event of a fire.

4.2 Storage and handling of explosives

It is extremely important to transport and store explosives correctly. Primary explosives must never be allowed in close proximity to secondary explosives until immediately before they are used. Primary explosive devices invariably contain a quantity of explosive sufficiently small that if unintentional detonation occurs the resulting explosion can be contained by the packaging used for storage and transport. In the event of primary explosive devices being exposed to high temperature or a fire, detonation will occur. If secondary explosive devices are stored or transported with primary explosives the detonation of the primary explosive will cause the secondary explosives to detonate, with possibly catastrophic results.

4.3 Elimination of stray voltages

The detonators used in wireline perforating equipment consist of a filament which is heated by an electrical current of 0.2-0.4 ampere, igniting a chemical mix which produces sufficient heat to cause high order detonation of a primary explosive pellet. The two wires connected to the filament each contain a 25 ohm resistor requiring a minimum of 10 volts to fire the detonator. The resistors are contained in the housing of standard detonators, but must be attached externally to high temperature detonators in the field. A potential difference of sufficient magnitude to fire a detonator may be caused by electrical welding, radio transmitters, cathodic protection, wiring faults and many other sources, and could cause the unintentional initiation of a detonator unless special precautions are taken.

To reduce the risk of unintentional detonation, operations involving standard electrically initiated detonators should not be carried out within:

• ·50 m: of public roads, waterways and railways;
• ·150 m: of high voltage lines or the overhead wires of tramways or railways;
• ·2500 m: from fixed transmitting installations whilst they are in operation.

If operations are anticipated in a location close to a fixed transmitter, overhead power cables, or electric tramways or railways the service company should be advised well in advance to enable the appropriate precautions to be taken.

Prior to starting any operations involving electrically initiated detonators the wellsite supervisor and service company engineer must ensure that:

• ·all electrical welding has been stopped;
• ·electrical measurement and control apparatus on the well or flowline have been switched off;
• ·electrical trace heating systems have been switched off;
• ·cathodic protection systems have been switched off;
• ·helicopter operations have been scheduled to take account of the periodic need for radio silence;
• ·all motorised equipment operating in the area used for work with explosives should be shut down unless required in conjunction with the work being carried out.

The service company engineer must ensure that the casing, derrick or crane, and logging unit are grounded to each other and any potential differences eliminated. After the grounding connections have been made the voltages between the casing, derrick or crane, and truck must be measured with a meter modified for this purpose. If it is not possible to reduce the residual voltage to below 250 mV the immediate superiors of both the wellsite supervisor and the service company engineer must be informed. Further work may not be carried out until permission from both of these persons has been obtained.

When requested by the service company engineer all electrical circuits and systems not required for the safe conduct of operations should be disabled by removal of the fuses or blocking the operating switches. Signs must be posted to indicate when this has been done; any circuit disabled in this way must not be switched on without permission from the service company engineer.

The circuits to be disabled will depend on the location type:

• ·on land locations all generators and electrical systems within the area where work with explosives is taking place;
• ·on offshore installations any generator not required during the operations with explosives.

The service company engineer will notify the company supervisor and the radio operator prior to the start of operations of the time at which radio silence will be required. At this time all radio transmitters within a radius of 500 m, including those on standby or supply boats, must be switched off and all portable transmitting equipment collected. The service company engineer must confirm with the radio operator that radio silence has been established prior to commencing any operation involving electrically initiated explosive devices. Radio silence will remain in force until notification has been given by the service engineer and company supervisor to the radio operator that it is no longer required.

On remote drilling and production locations the requirements for radio silence and electrical shut down can easily be met, and it is unlikely that other activities are taking place whose priorities seriously conflict with those of perforating safety. However, on large production facilities or where wells are in close proximity to commercial or military radio transmitters or power cables the criteria for perforating safely may be difficult or prohibitively expensive to achieve with conventional electrically initiated detonators. Radio silence is typically required for less than one hour per perforating run, however circumstances such as the gun or cable becoming stuck while near the surface may require several days to resolve, during which time the shut down must be maintained. The costs of deferred production or diversion of a railway line during this period may be considerable. When SAFE or EWB detonators are used, no special precautions to prevent stray voltage are needed.

4.4 Removing a gun from the hole

All procedures applicable to the arming and running of guns apply equally to their removal from the well. This requires that radio silence and electrical shutdowns are observed in the same manner as when the gun is armed and run, even if the gun is believed to have fired normally. This will require the presence of a perforating company engineer on the wellsite if a completion from which a TCP gun is suspended is retrieved from the well, or if a TCP or wireline gun is fished from the well.

When a hollow carrier wireline gun is removed from the well it will contain a large quantity of steel debris from the charge cases. Frequently, particularly when perforating in mud filled holes, the mud and debris will seal the perforation holes in the carrier which, when the gun is removed from the hole, will then remain filled with high pressure fluid. A bent rod should always be used to clear one or more perforation holes in the carrier to ensure that all pressure is released before attempting to disconnect the gun from the cable or pipe on which it was run.

4.5 Operational safety

Operations involving explosives should normally be conducted during daylight hours.

Operations involving explosives should not be conducted if any of the following conditions exist:

·any part of the working area is obscured by fog or smoke;

·an electrical storm or cumulo-nimbus clouds can be seen;

·if strong winds prevent the operations being conducted safely, due either to induced static electrical potentials or mechanical wind loads. Operations should not be conducted with wind strengths greater than force 8.

Should such conditions arise while operations are in progress, explosives should be replaced in their storage or transport containers. Explosives which are already in the well may be fired at the programmed depth, but the gun must not be pulled to surface and removed from the well until conditions have improved.

4.6 Safety guidelines for perforating operations

All locations

• ·Work with explosives should be performed under the "permit to work" system.
• ·Working areas around the Xmas tree and separators should be kept clear. Unobstructed access to these areas should be available at all times.
• ·Adequate kill fluid (150% of production casing capacity) of the correct gradient should be available. A suitable kill pump should be on location.
• ·All testing and kill equipment must be satisfactorily pressure-tested, at a pressure exceeding the maximum that may be expected during the operation.
• ·On new wells the Xmas tree should be pressure tested against a plug in the tubing or hanger nipple. Each valve of the Xmas tree should be individually tested.
• ·Gas explosion meters, a H2S detector and portable breathing apparatus sets should be available. Any gas produced should be tested for the presence of H2S either by the production supervisor or the petroleum engineer on site.
• ·For through tubing operations, before the first gun is run in the hole, and any subsequent runs that are preceded by a period of flow, a wireline dummy run must be made to check that the tubing and casing are free of obstructions. The dummy should have the same OD as the perforating gun to be run, and be at least 1.2 m long; ideally a fired gun of the same type as will be used for perforating should be used.

Immediately before starting perforating operations the nominated supervisor should hold a safety meeting at the site with all the personnel involved which should cover the following subjects:

• -permits required;
• -possible dangers;
• -precautions required for working with explosives;
• -programme to be followed, and reporting and alarm procedures;
• -organisation on site;
• -layout of the location, fire extinguishers and escape routes;
• -surface measurements to be made;
• -personal protection requirements;
• -H2S procedures;
• -emergency kill procedure;
• -expected pressures;
• -a current diagram of the well status;
• -individual responsibilities and reporting procedures on location.

Offshore

• ·Provision should be made for two blow-off lines, with one on each side of the rig or platform.
• ·A "Muster and Abandon Rig Drill should be held prior to commencing perforation operations.
• ·Before commencing perforating operations, the fire-fighting water system should be under pressure.
• ·A standby boat should be present during perforating operations.

This article describes the reports required to be submitted by the contractor to the Company Completion Supervisor.

Well Completion Equipment Report

Contractor shall submit to the Company Completion Supervisor, detailed assembly drawings of all sub assemblies clearly identifying the make up lengths required for space out calculations prior to mobilisation.

Contractor shall submit a detailed well completion diagram showing all relevant lengths, depths and individual tool dimensions to the Company Completion Supervisor, as soon as possible following each well completion.

Well Completion Daily Report

During offshore operations, the Contractor representative shall plan, monitor, and report to the Company Completion Supervisor, the operational progress of the work on a daily basis complete with suitable schedule diagrams and reporting formats. They shall submit a Daily Performance Report to the Company Completion Supervisor detailing the current job status and shall include all relevant information.

Company provided formats for reports shall be utilised, where available.

Well Completion Work Report.

Contractor shall provide a work report to the Company Completion Supervisor,  upon completion of the work. This work report shall take the form of a post job evaluation and shall include an accurate time breakdown and detailed sequence of events for the entire completion period.

Contractor shall submit as part of the Work Report, an equipment performance summary detailing equipment downtime, if any, reasons for downtime and corrective action taken.

The Work Report shall be submitted as soon as possible following the completion of the work.

Proper preparation of tubing before running serves two purposes. Firstly to ensure that the pipe body and threads are adequately protected from possible damage when being moved to the drill floor. Secondly, that handling of the tubing on the drill floor is kept to a minimum.

Read more …

Whatever type of packer is installed, the manufacturer's instruction for setting and the completion programme on setting depth and running must be followed if satisfactory results are to be obtained. There are too many variations in packer design and setting to go into detail, but some points to remember when installing packers are:

Read more …

All inspection and testing shall be performed by contractor's personnel and witnessed by Company's completion supervisor.

The drilling programme shall contain all the necessary information, including contingency measures, to enable the operation to be carried out in the most effective way. If for any reason the programme can not be followed, and the contingency has not been foreseen, Company Base Organisation shall be notified and advice sought.

Receiving Inspection

1) When new completion equipment arrives at the Contractor's Base, the Contractor shall perform an extensive series of mandatory inspections. These include initial visual inspection followed by full function and pressure testing of all relevant equipment.

2) The relevant procedures, applicable standards and specifications used by Camco and Otis, for all completion equipment supplied by them, is detailed in their respective Quality Assurance Manuals.

3) Completion equipment shall be assembled.

4) Tubing arriving at Companies Base shall be packed in designated boxes with appropiate escription on the tubing. Prior to shipment offshore the tubing shall be flushed and when necessary, cleaned inside and outside with steam. The tubing will be again packed in designated boxes for shipment offshore.

Procedure For Well Site Preparation - Inspection and Testing

1) As the tubing arrives on board it shall be measured independently by both the drilling contractor and the company representative using different measuring tapes (measurement should be made with the protectors removed). It is the duty of the WSDE to check that the measurements are being done and from the correct position on the thread. After each layer of tubing has been received on board the figures should be compared and checked for any discrepancies. At least 3 evenly spaced wooden strips should separate each layer.

2) Each joint of tubing shall be clearly marked with paint as it arrives on board. If there is any other tubing already on board it should be ensured that there is no duplication of numbers. New tubing arriving on board should be racked on a different part of the deck to any tubing already on board or at least clearly identified.

3) If tubing of two different OD's or thread connections is received on board  ensure that a different colour paint is used for the numbering of each tubing size and that numbers are not duplicated.

4) Tubing accessories required for the completion shall be laid out on deck and the contractor (under the supervision of the WSDE) will number and measure all items. Although it may be normally assumed that certain items are of a standard length, the length of each individual item shall be checked and noted.

5) The WSDE shall check the weight / grade / size and thread of the tubing on  board, which should be vendor painted onto the joints, against what the programme calls for.

6) After measuring the tubing each joint should be flushed with water.

7) Check that each joint is clean and scale free (those with scale deposits shall be returned to  materials department).

8) Check the threads for damage and scale.

9) Drift the tubing with API drift. Drifts shall be at least 42" long.

10) Apply HP Modified Thread Compound in the case of 13% Cr tubing and Cats Paw Black on all other premium connections to the threads and then replace the pin and box protectors.

Completion Running - Inspection and Testing

General

1) Ensure that all rig pumping lines are thoroughly flushed with filtered brine to prevent having dirt on top of wireline plugs and thus unable to retrieve them. Ensure all pits are clean as well.

2) Ensure that elevator, slips and power tubing tongs are in proper working order, and that the correct dies are fitted. If deemed necessary a stabbing operator shall be used.

3) Do not use pipe wrenches for manual make up of tubing joints.

4) Using a small clean paintbrush or pipe dope applicator, apply pipe thread lubricant sparingly to both pin and box thread, and sealing shoulders.

5) Ensure that the power tongs are set to cut out at the COMPANY recommended torque. If available a unit to control the initial make-up speed is recommended.

6) Record all torque values when running in the hole with the tubing.

7) Drift each joint as it is picked up to the drill floor. Connections shall be protected with protectors with transporting to the rig floor.

8) The responsible person (driller or completion supervisor) shall record the serial number of each item as it is made up to the string, this includes tubing joints according the   completion equipment running list.

9) Supervisors keeping a tubing tally should cross check with each other regularly to ensure that the string is made up according to the programme.

10) After the packer sub assembly is made up to the string, the slips and packing elements should be inspected.

11) When carrying out pressure tests, build up pressure slowly, in stages to the maximum required and maintain for the recommended time.

12) All pressure tests shall be recorded on a suitable chart recorder and maintained in the well file.

13) After spacing out, drift the complete string using suitable wireline drifts as specified in the completion installation programme.

Tailpipe X-Over Assembly Inspection

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

Bottom Landing Nipple / Perforated Joint Assembly Inspection

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

3) Complete the equipment check list.

Middle Landing Nipple / Packer Assembly Inspection

1) Inspect interior and exterior of each component, especially the packer slips, elements and threads. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

3) Ensure that brass shear screws are installed.

4) Complete the equipment check list.

Expansion Joint Assembly Inspection

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

3) Confirm compatibility between the completion programme and the shear value of the hydraulic release mechanism.

4) Complete the equipment check list.

Top Landing Nipple Assembly Inspection

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

3) Complete the equipment check list.

Side Pocket Mandrel Assembly Inspection

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

3) Ensure that dummy / dummies are installed.

4) Complete the equipment check list.

X-Over Assembly Inspection

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers, dimensions, etc. correspond to the equipment check list.

Otis TRSSV and ASV Inspection

1) Ref. to detailed procedures in Contractor manual

Subsurface safety valves (SSSVs) are installed in the wellbore of hydrocarbon producing wells to shut off the production flow to the surface in case of an emergency. The importance of the correct installation of these valves to ensure well production flow is shut in during an emergency can not be over emphasised.

Improvements in valve design and reliability are of no avail if the valves are not correctly locked in the landing nipples (wire line run) and correctly function tested once installed. This article reviews the installation and testing procedures in order to prevent failure of the SSSV to operate as required. Reference should also be made to AP1 RP 14 B, Recommended practice for design, installation and operation of SSSV systems.

1.  Workshop testing/assembly

Following complete redressing and servicing of surface controlled sub-surface safety valves (SCSSVs) in dedicated workshops, the following test/checks should be carried out:

1. Cycle the valve 4 or 5 times by alternately pressurising and depressurising the valve through the hydraulic inlet port. Observe the closure time and compare the opening pressure with the manufacturer's specifications.
2. Pressurise the control line port to the maximum test pressure.
3. Check in each case that the valve moves to the fully open position when it is operated into the open position.

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this article presents the main operational and safety precautions to be taken when installing a xmas tree.

1. General Precautions

There are many methods of landing the tubing and leading control line(s) from the wellhead. Full instructions for this operation will be contained in the programme or in written standard procedures, however precautions to be taken include:

1. check all sealing or matting surfaces for damage before bringing them together;
2. check all sealing elements (metal ring gaskets, etc.) for damage and ensure freedom of movement in grooves or recesses;
3. check that the tubing hanger nipple is central and vertical;
4. use flange protectors (seal pads) where recommended;
5. before the BOP stack is removed, ensure that a two-way check valve or plug is installed in the hangar and pressure tested.

After the tubing has been landed, the control line(s) packed off and satisfactory pressure tests carried put, the Xmas tree is installed. Specific procedures will be governed by the type of Xmas tree and connections, however, the following general points apply:

• ·If an adapter flange is included in the assembly, it should be installed but only hand tight. The Xmas tree should be lowered into position and the adapter flange rotated as necessary to enable the Xmas tree to be orientated to correspond with the flowline hook-up. When the tree is aligned the bolts/clamps should be tightened.
• ·Plastic injection and pressure testing should be carried out carefully and methodically, adhering to the torque and test pressures stipulated in the programme or standard procedures. Injection of the plastic is considerably eased if it is slightly warmed using hot water, but it must not be melted. When the test pressures have been successfully completed, the injection screws should be backed out, the ports filled with plastic packing and the screws and plugs refitted in the injection ports. Following testing, the test pressure should be bled off from the test port, the test apparatus removed and the check valves and plugs refitted.
• Excessively high pressure can be generated when energising sealing elements: causing deformation of wellhead equipment and/or possible injury to personnel.
• ·Install the necessary control line, flow wing and kill wing valves and chokes, in accordance with the engineering drawings.
• ·The Xmas tree should now be API pressure tested against the two-way check valve or plug in the tubing hanger. The test should be carried out in two stages:

1.with flow and kill wing valves closed and choke open;

2.with valve downstream of choke and kill wing valve closed and flow wing valve and choke open.

• ·When the test has been completed without evidence of leakage past the seals, the two-way check valve/plug should be recovered from the tubing hanger.

2 Tubing back pressure valve

Safety critical activities occur during the completion between BOP stack removal and christmas tree installation, or at the beginning of repair work between christmas tree removal and BOP stack installation. Since, in these situations, the completion or workover fluid will usually have the minimum allowable density necessary to balance the formation pressure, this is not considered a sufficient safeguard against blowout. Normal practice is to install a downhole plug, preferably set in a packer tailpipe. A second barrier is provided by a tubing back pressure valve (BPV) fitted in the top of the tubing hanger (left handed square thread) or hanger nipple (landing nipple profile). The valve is provided either with a matching thread or with locking dogs, respectively, in addition to its seal. The valve is installed either by screwing it into the hanger using an extension rod or is set in the hanger by wireline methods. The BPV allows circulation down the tubing but automatically closes against well pressure.

2.1 Valve installation/removal

Installation or removal of the threaded valves through a Xmas tree is accomplished using a special lubricator. This consists of a rod which works through a yoke housing two stuffing boxes and to which the installation/removal tool is attached. By closing the vent valve and opening the equalising valve, well pressure acts on both the top and bottom of the rod. It can then be moved up or down, and/or rotated, by means of a friction wrench.

The wire line type BPV can be installed or retrieved by normal wire line methods.

To pressure test the tree and/or tubing hanger seals, a two way check valve must be landed in the hanger. In this instance, circulation down the tubing is impossible.

In new well applications it is not recommended to use threaded profiles for the BPV. This is a result of threaded profiles being more prone to damage/corrosion.

A packer is defined as a sub-surface tool used to provide a seal between the tubing and casing (or wall) of a well, thus preventing the vertical movement of fluids past this sealing point. Packers are sometimes referred to as production packers but this term is generally used with reference to a particular class.

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This procedure identifies the assembly and test method for all completion sub assemblies.

All assembly and testing shall be performed by persons, who have, as a minimum, undergone indoctrination and been qualified as Functional Test Operator. Assistant(s) shall have undergone indoctrination of new assembly / disassembly personnel.

Two persons shall always be present during testing.

Prior to commencement, an authorised Company representative shall approve the description of each sub assembly in writing. The workshop supervisor shall check equipment lists against the written approval with sub assembly description. This approval shall be retained by the contractor.

Prior to assembly, the workshop personnel shall obtain approved equipment check list and test procedure from the workshop supervisor. Only properly approved equipment check list may be used.

General Completion Assembly Procedure

The general procedure listed below shall apply to all assembly preparation: 

1) The length and composition of sub assemblies are largely dictated by available space and handling considerations. All sub assemblies shall be made up and tested onshore at the Cantractor Base(s) for the completion sub assemblies, TRSCSSV and ASV sub assemblies.

2) Every sub assembly shall have a backup available on site eliminating the need for making up sub assemblies offshore.

3) Every sub assembly, complete with suitable thread protectors, shall be transported to the site with the applicable tubing pup joint connection box up, and the applicable tubing pup joint connection pin down. For handling and make up purposes, the pup joints shall be approximately 2 metres long.

Procedure For Completion Testing and Assembling

1) All pressure tests shall be recorded on a chart recorder which will then be attached to the equipment check list to be retained indefinitely by Company.

Test fluid: Soluble oil / water

Duration of test: 15 minutes at 35 bar and 15 minutes at 345 bar

2) All assemblies shall be tested to 345 bar unless otherwise specified.

3) After the pressure test, each assembly shall be drifted with the appropriate API spec. drift. All drift diameters shall be recorded on the equipment check lists. For assemblies with a No Go nipple, a special drift shall be used. All drifts shall be inserted from both above and below the assembly to ensure that no deformation has taken place during make up.

4) All assemblies shall be made up using the Jam system or equivalent. All make up torque-turn and pressure test charts shall be attached to the equipment check lists. The correct torque values shall be verified by the tubing make up company.

5) The torque values shall be as follows:

7" 29# Vam AG (13%Cr) Grade L-80: 12380-13750 - 15120 ft/lbs.

7" 29# New Vam (9Cr 1Mo) Grade L-80:  8460  - 9400 - 10340 ft/lbs.

5 1/2" 23# Vam AG (13%Cr) Grade L-80: 9700  -10000 - 10300 ft/lbs.

5 1/2" 23# New Vam (9Cr 1Mo) Grade L-80: 7170  - 7960-  8750 ft/lbs.

6) The above values are specified and approved by Company.

Be aware that torque values used by Company can differ from manufacturers recommended. Torque values for tubing shall be as per COMPANY recommendation.

7) For non standard or not often used equipment, the actual functioning of equipment and wireline operating tools shall be performed before equipment leaves the contractors site.

Detalied Procedures for preparation of the different sub assemblies are given below.

Tailpipe X-Over Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Apply thread lubricant to box end and by hand make up the connection.

5) Make up all connections to the specified torque value.

6) Drift assembly from above and below.

7) Apply storage grease  and install thread protectors.

8) Complete the equipment check list.

Bottom Landing Nipple / Perforated Joint Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Drift the Landing nipple with a special Camco no go drift ( manufactured to tolerances corresponding to the appropriate lock mandrel ).

5) Apply thread lubricant to box end and by hand make up the connection.

6) Make up all connections to the specified torque value.

7) Drift assembly from above and below.

8) Apply storage grease  and install thread protectors.

9) Complete the equipment check list.

Bottom Landing Nipple and Packer Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Apply thread lubricant to box end and by hand make up the connection.

5) Make up all connections to the specified torque value.

6) Install steel test pins in the ratchet retainer.

7) Pressure test assembly to 138 bar as per programme.

8) Drift assembly from above and below.

9) Apply storage grease  and install thread protectors.

10) Complete the equipment check list and pressure test chart.

Expansion Joint Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Apply thread lubricant to box end and by hand make up the connection.

5) Make up all connections to the specified torque value.

6) Pressure test assembly to 345 bar as per programme.

7) Drift assembly from above and below.

8) Apply storage grease  and install thread protectors.

9) Complete the equipment check list and pressure test chart.

Top Landing Nipple Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Apply thread lubricant to box end and by hand make up the connection.

5) Make up all connections to the specified torque value.

6) Pressure test assembly to 345 bar as per programme.

7) Drift the Landing nipple with a special Camco no go drift ( manufactured to tolerances corresponding to the appropriate lock mandrel ).

8) Drift assembly from above and below.

9) Apply storage grease  and install thread protectors.

10) Complete the equipment check list and pressure test chart.

Side Pocket Mandrel Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Install dummy/dummies in the side pocket. Note. Install the lower pup joint and protect the upper threads prior to installing the dummy/dummies.

5) Apply thread lubricant to box end and by hand make up the connection.

6) Make up all connections to the specified torque value.

7) Pressure test assembly to 345 bar as per programme.

8) Drift assembly from above and below.

9) Apply storage grease  and install thread protectors.

10) Complete the equipment check list and pressure test chart.

11) The relevant procedures used by Otis for all TRSCSSV and ASV sub assembly make up and testing are detailed in the Contractor Service Manual.

X-Over Assembly

1) Inspect interior and exterior of each component. Ensure that all threads are clean and free from damage.

2) Ensure that any / all part numbers correspond to the equipment check list.

3) Drift each component with the correct API drift.

4) Apply thread lubricant to box end and by hand make up the connection.

5) Make up all connections to the specified torque value.

6) Drift assembly from above and below.

7) Apply storage grease and install thread protectors.

8) Complete the equipment check list.

TRSSV and ASV

1) Ref. to detailed procedures in Contractor manual