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.

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 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.

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.

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.

  Read more …

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 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.

Read more …

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 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

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.

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

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 …

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.

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.

Read more …

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.

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.

Read more …