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.

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

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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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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 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).

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.

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 …

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.