PTRT 2331- Well Completion and Servicing

Chapter 3:Equipment of naturally flowing wells

3.1. General configuration of flowing well equipment3.2. The production wellhead3.3. The production string or tubing3.4. Packers3.5. Downhole equipment3.6. Subsurface safety valves3.7. Running procedure

In well architecture there is a wide range of equipment available to get the effluent from the reservoir up to the surface where it will be treated. In searching for the best compromise between reservoir versus production requirements and constraints, the choices are governed by four main principles: access to the reservoir for measurements efficient transfer of the effluents from the bottom to the surface control of the effluents on the surface safety of all facilities.The various equipment components are of course selected depending on the data collected, the configurations determined (connection between the borehole and the pay zone, single- or multiple-zone completion, etc.) and any artificial lift due to be performed. The solution that is eventually chosen may be different from what was originally planned from a technical standpoint because the selected equipment: is not available on the market or can not be obtained in the specified time limit is excessively expensive is different from the equipment traditionally used by the company can be replaced (more or less satisfactorily) by leftover equipment in company

stocks

General configuration

Naturally flowing wells usually include: Upper accessories (production wellhead with the Christmas tree and the

tubing head) Tubing (pipe to carry the effluents from the bottom of the well up to the

surface. Choosing the right pipe steel and through diameter contributes to the safety of the facilities and ensures that the effluents will reach the surface as efficiently as possible)

Packers (which is used first and foremost to isolate the casing from the pressure in the well and from physical contact with the effluents which are sometimes highly corrosive)

Down hole accessories (these components are incorporated into the tubing. They allow circulation between the tubing and the annulus, or are used for installing equipment or to make it easier to use measurement and maintenance tools); it is better to limit number of accessories to the ones that are strictly necessary

Extra subsurface safety valves (for high risk wells such as offshore, subsea, gas producers; It is designed to offset any failure of the Christmas tree safety valves or of the wellhead itself)

The upper completion refers to all components from the bottom of production tubing upwards. Proper design of this "completion string" is essential to ensure the well can flow properly given the reservoir conditions and to permit any operations as are deemed necessary for enhancing production and safety.Wellhead: the top of the well where casing strings are suspended and the BOP or Christmas tree is connectedChristmas Tree: the main assembly of valves that controls flow from the well to the process plant (or the other way round for injection wells) and allows access for chemical squeezes and well interventionsTubing head/hanger: sits on top of the wellhead and serves as the main support for the production tubing. Production tubing: the main conduit for transporting oil from the reservoir to the surface; It runs from the tubing hanger down to just above the top of the production zone.Wireline entry guide: often installed at the end of the tubing, or "the shoe“; it makes pulling out wireline tools easier by offering a guiding surface for the toolstring to re-enter the tubing without getting caught on the side of the shoe

Upper Completion Components

Production Wellhead

Wellhead is the topmost point of a well. A production wellhead includes the Christmas tree and the tubing head.The tubing/casing head or tubing head spool, which seats on top of the wellhead, accommodates the device designed to hang the tubing(s) and casings. The Christmas tree comprises a series of valves, a choke and connections. It provides a means of controlling the effluents, ensuring the safety of the facilities and giving measurement tools and instruments access to the well

Wellheads serve a number of functions while a well is being drilled, once it is completed and operational, and when it is shut down, either temporarily or permanently. The wellhead is installed early on in the process so that it can serve as a point of attachment for a blowout preventer, a piece of equipment which prevents catastrophic failure of a well, and once a well is completed, equipment for regulating well operations can be attached at the wellhead.

The choice of the type of wellhead and the functions it has to fulfill are related to the following requirements and needs:• Provide a means of casing suspension• Casings can contain different well fluids; a wellhead serves to keep these

casings separated from each other to avoid mixing of fluids.• Provides a means of tubing suspension• Provides a means of pressure sealing and isolation between casing at surface

when many casing strings are used • Provides pressure monitoring and pumping access to annuli between the

different casing/tubing strings • Provides a means of controlling well flow rate (choking)• Provides a means of attaching a blowout preventer• Provides a means of attaching a Christmas tree for onshore production• Provides a reliable means of well access• Provides a means of attaching a well pump

Functions

A casing head is a mechanical assembly used for hanging a casing string. The tubing must be hung and secured on the surface, and it needs a stack of valves and other accessories on top of it to meet safety and fluid flow requirements. Depending on casing programs, several casing heads can be installed during well construction. A well completed with three casing strings has two casing heads. The uppermost casing head supports the production casing while the lowermost casing head sits on the surface casing, threaded to the top of the surface casing.

Tubing/Casing Head

Several valves and plugs are normally fitted to give access to the casing. This permits the casing to be opened, closed, bled down and in some cases, allow the flowing well to be produced through the casing as well as the tubing. The valve can be used to determine leaks in casing, tubing or packer, and is also used for lift gas injection into the casing. Most flowing wells are produced through a string of tubing run inside the production casing string. At the surface, the tubing is supported by the tubing head which is used for hanging tubing string on the production casing head.

Many times, the words Christmas Tree and Wellhead are used interchangeably; however, a wellhead and Christmas tree are entirely separate pieces of equipment. A wellhead must be present in order to utilize a Christmas tree and is used without a Christmas tree during drilling operations. Producing surface wells that require pumps (pump jacks, nodding donkeys, etc.) frequently do not utilize any tree due to no pressure containment requirement.

Christmas Tree

• The primary function of a tree is to control the flow of fluid, usually oil or gas, out of a well.

• To control the injection of gas or water into a non-producing well in order to enhance production rates of oil from other wells

• As chemical injection point: on producing wells, chemicals or alcohols or oil distillates may be injected to preclude production problems (e.g. blockages)

• As well intervention means• As pressure relief means (BOP)• As monitoring point: pressure, temperature, corrosion, erosion, sand

detection, flow rate, flow composition, valve and choke position feedback)• As connection points for devices such as down hole pressure and temperature

transducers (DHPT)

Functions

Christmas trees are used on both surface and subsea wells.

Christmas tree is equipped with set of valves and serves for pressure control.

The Christmas tree is installed above the tubing head. An adaptor is a piece of equipment used to join the two. The Christmas tree may have one flow outlet (a tee) or two flow outlets (cross). The master valve is installed below the tee or cross. To replace a master valve, the tubing must be plugged. The Christmas tree from bottom to top includes:- One or two master valve- Tee or cross- A swab valve- A tree capIt is completed by one or two wing valve and a choke.

Ch

rist

mas

Tre

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Production Wellhead

The set up shown allows:

Valves The valves used on Christmas tree are of the gate-type During normal production, the lower master valve is kept

open; the upper one is used to place the well in safe condition, it is closed automatically by means of a hydraulic or pneumatic control system

The wing valve, often manual, can be motorized so that it can be remote-controlled

Surface choke is a piece of equipment used to control the flow rate; it is a restriction in the flow line. In most flowing wells, the oil production rate is altered by adjusting the choke size. The choke causes back-pressure in the line. The back-pressure increases the bottom-hole flowing pressure. Increasing the bottom-hole flowing pressure decreases the pressure drop from the reservoir to the wellbore (pressure drawdown). Thus increasing the back-pressure in the wellbore, decreases the flow rate from the reservoir.In some wells, chokes are installed in the lower section of tubing strings. This choke arrangement reduces well-head pressure and enhances oil production rate as a result of gas expansion in the tubing string.For gas wells, the use of down hole chokes minimizes the gas hydrate problem in the well stream.A major disadvantage of using down-hole chokes is that replacing a choke is very costly.A swab valve is used to gain access to the well for wireline operations, intervention and other work over procedures.

Surface Choke

Opening or Closing a Well

Well is closed by acting on the wing valve , then on the upper master valve.Certain procedures must be followed to open or close a well

Before opening

- Check all the surface equipment such as safety valves, fittings, and so on.- The burner of a line heater must be lit before the well is opened. This is

necessary because the pressure drop across a choke cools the fluid and may cause gas hydrates or paraffin to deposit out. A gas burner keeps the involved fluid hot.

- Fluid from the well is carried through a coil of piping. The choke is also installed in the heater. Well fluid is heated both before and after it flows through the choke. The upstream heating helps melt any solids that may be present in the producing fluid. While the downstream heating helps prevents hydrates and paraffin from forming at the choke.

- Surface vessels should be open and clear before the well is allowed to flow.

When opening

All the valves that are in the master valve and other downstream valve are closed.

Then follow the following procedure to open a well.

1. The operator barely opens the master valve (just a crack), and escaping fluid

makes a hissing sound. When the fluid no longer hisses through the valve, the

pressure has been equalized, and then the master valve is opened wide.

2. If there are no oil leaks, the operator cracks the next downstream valve that is

closed. Usually, this will be either the second (back-up) master valve or a wing

valve. Again, when the hissing sound stops, the valve is then open wide.

3. The operator also opens the other downstream valves the same way.

4. To read the tubing pressure gauge, the operator must open the needle valve at

the top of the Christmas tree. After reading and recording the pressure, the

operator may close the needle valve in order to protect the gauge.

The procedure for shutting-in a well is the opposite of the procedure for opening

a well.

Production Tubing

Tubing is the pipe through which oil and gas are brought from the producing

formation to the field surface facilities for processing. Most oil wells produce

reservoir fluids through tubing strings. This is mainly because tubing strings

provide good sealing performance and allow the use of gas expansion to lift oil.

Gas wells produce gas through tubing strings to reduce liquid loading problems.

Tubing must be adequately strong to resist loads and deformations associated

with production and work overs. The Tubing must be sized to support the

expected rates of production of oil and gas.

Tubing that is too small restricts production and subsequent economic

performance of the well. While tubing that is too large may have an economic

impart beyond the cost of the tubing string itself, because the tubing size will

influence the overall casing design of the well.

Properties of Tubing

The API has formed standards for oil/gas tubing/casing that are accepted in most countries by oil and service companies. Tubing is classified according to five properties:1. The manner of manufacture2. The steel grade3. Type of joints4. Length range5. The wall thickness (unit weight)

Tubing is manufactured of mild (0.3 carbon) steel, normalized with small amounts of manganese. Strength can also be increased with quenching and tempering.

API Steel Grades

The API defines “tubing size” using nominal diameter and weight (per foot). The nominal diameter is the outside diameter of the pipe body and is expressed in inches and fractions of an inch. The weight of tubing determines the tubing outer diameter; steel grades of tubing are designated to H-40, J-55, C-75, L-75, L-80, N-80, C-90, C-95, P-105/110, and Q-125. The digits represent the minimum yield strength in 1000psi.

Non API Steel Grades

These steel grades are often used in special applications requiring high strength or resistance to hydrogen sulfide cracking.

Pipe Length

Due to the type of machining, each pipe naturally has a specific length and is classified into two length ranges:- Range 1: from 20ft to 24ft (6.10m to 7.32m)- Range 2: from 28ft to 32ft ( 8.53 to 9.75m)The range for site must be chosen with care and must be compatible with the hoisting and storage capacity of the mast of the rig used. When the equipment is run in during completion/ work over operations.

To design a reliable casing string, it is necessary to know the strength of pipe under different load conditions. The most important mechanical properties of casing and tubing are: Burst strength, Collapse resistance, Tensile strength

The yield strength, for these purposes, is defined as the tensile stress required to produce a total elongation of 0.5% of the length. There are also proprietary steel grades widely used in the industry, which do not conform to API specifications. These steel grades are often used in special applications requiring high strength or resistance to hydrogen sulfide cracking.

Pipe Strength

For design purposes, burst stress (pressure) can be estimated from

Burst pressure, a calculation to determine an approximate guideline for the conditions under which a tube might break open due to pressure from within, is clearly an important factor to consider when designing

PiPo

Burst or collapse is due to a differential pressure P between the outside pressure Po and the inside pressure Pi of tube

Pi > Po

Burst Pressure

x = outer pipe radius = OD/2; y = inner pipe radius = ID/2; T = tensile strengtht = nominal wall thickness = x - y

PB = Pi – Po

𝑃𝐵 =𝑇(𝑥2 − 𝑦2)

(𝑥2 + 𝑦2)

Pipe Burst and Collapse Strength

Collapse Pressure

collapse

Pc = Po - Pi

Collapse stress (pressure) is the opposite of burst stress

Po > Pi

𝑃𝑐 =𝑌(𝑥2 − 𝑦2)

2𝑥2

x = outer pipe radius = OD/2; y = inner pipe radius = ID/2; Y = minimum yield strength t = nominal wall thickness = x - y

A 30 in. outside nominal diameter and 0. 3125 in. thick API standard C-90 steel pipe is to be used for the conductor casing of a well. If the inside pressure in the pipe is 3000 psi, 1. calculatea. The minimum outside pressure to avoid bursting of the pipeb. The maximum outside pressure to avoid collapse2. What would happen to the pipe in each of the following outside pressures:a. 300 psi b. 1000 psi c. 5000 psi

Example

Collapse Pressure

Pc = Po - Pi𝑃𝑐 =𝑌(𝑥2 − 𝑦2)

2𝑥2

Burst Pressure

PB = Pi – Po

Po = Pi – PB = 895 psi

Po = Pi + Pc = 4855 psi

Pi3000

T 100000Y 90000x 15t 0.3125y 14.6875

= 2105 psi

= 1855 psi

Solution

𝑃𝐵 =𝑇(𝑥2 − 𝑦2)

(𝑥2 + 𝑦2)

From the API standard steel grade Table (slide 18), for C-90:Yield Strength, Y = 90,000 psi, Tensile Strength, T = 100,000 psi

x = outer pipe radius = OD/2 = 15 in

t = nominal wall thickness = 0.3125 in

y = inner pipe radius = x – t = 14.6875 in

2. Therefore safe working outside pipe pressure of pipe is 895 to 4855 psia. At 300 psi, pipe will burstb. At 1000 psi, pipe is stablec. At 5000 psi, pipe will collapse

Connection ThreadsThere are two ways to screw pipe together:- By using a coupling, which is most common connection- Or by means of an integral joint, which is most common type of connection used on small diameter pipe.Depending on the type of connection, the seal is separate from the thread or integrated in it.Threads are used as mechanical means to hold the neighboring joints together during axial tension or compression. The threads are not intended to be leak resistant when made up. For more information on tubing threads dimensions, check the API specification 5C2, performance properties of casing, tubing and drill pipe.Special connections are used to achieve gas-tight sealing reliability and 100% connection efficiency under more severe well conditions. Joint efficiency is defined as a ratio of joint tensile strength to pipe body tensile strength.

threaded & coupled

Connection types

A versatile, integral two-step connection for standard weights of tubing. Metal-to-metal seals provide pressure integrity greater than the burst and collapse ratings of the tubing body

designed for all types of workstring and production tubing applications. The connection features a metal-to-metal, gas tight seal, dual torque shoulders and a tapered 5-pitch, "hooked" thread form.

a threaded and coupled non-upset premium connection designed to provide internal and external pressure integrity under extreme loads

Integral connection

Most casing failures occur at connections. These failures can be attributed to: Improper design or exposure to loads exceeding the rated capacity Failure to comply with makeup requirements Failure to meet manufacturing tolerances Damage during storage and handling Damage during production operations (corrosion, wear, etc.)

Connection failure can be classified broadly as: Leakage Structural failure Galling during makeup Yielding because of internal pressure (burst) Fracture under tensile load Failure due to excessive torque during makeup or subsequent operations

Connection failures

Avoiding connection failure is not only dependent upon selection of the correct connection, but is strongly influenced by other factors such as manufacturing tolerances, storage , transportation, running procedures, etc.

Galling in fasteners can occur naturally but there are many factors that only increase the risk of galling. Dirty Threads Damaged Threads Installing Under Load Installing Too Quickly Installing in Poor Environmental Conditions Not Applying LubricantsGalling is a natural occurring process that cannot be completely mitigated, but there are a few ways to minimize the chance of thread galling Add fastener lubrication Reduce installation speed Take load off assembly before tightening Use a torque wrench to avoid over-torque Use two different grades of the material Ensure fastener threads are not damaged prior to installation Ensure there is no debris in fastener threading prior to installation Use coarse threading where possible Keep fasteners in a controlled environment

Thread galling occurs during installation when pressure and friction cause connector threads to seize. Once a fastener has seized up from galling it is typically impossible to remove without splitting the connector

PackersThe packer forms the basis of the cased-hole completion design. The packer is a sealing device that isolates and contains produced fluids and pressures within the wellbore in order to protect the casing and other formations above or below the producing zone.

In addition to providing a seal between the tubing and casing, other benefits include:1. Prevents down hole movement of the tubing string.2. Support some of the weight of the tubing3. Often used to improve well flow and production rate.4. Protect the annular casing from corrosion from produced fluids and high

pressures.5. Provide a means of separation of multiple producing zones6. Limit pressure in the annulus to protect casing and cement from excessive

compressional stress.7. Hold well-servicing fluid (kill fluids, packer fluids) in the casing annulus.

Uses of Packers

Packer FluidsPacker (or annular) fluids serve mainly to protect the casing. They must be heavy enough to shut off the pressure of the formation being produced, and should not stiffen or settle out of suspension over long periods of time, and must be non-corrosive. They provide hydrostatic pressure support to balance formation pressure; their use can

reduce or eliminate differential pressure across the packer, extending packer life and reliability. This pressure also functions to provide support for production tubing and casing which prevents collapse of tubulars, extending the life of the well.

They limit corrosion of production tubing and production casing. They help control well if there is a leak in production tubing or when the packer no

longer provides a seal One challenge in deepwater production design is uncontrolled heat transfer from

production tubing to outer annuli and the loss of heat energy from produced fluids. These conditions can result in damage to outer annuli integrity and can reduce well productivity. Under uncontrolled conditions, damage to the formation can occur. insulating packer fluids provide control over heat flow from production tubing to the outer annuli, reducing annular pressure buildup and maintaining flowing well temperatures.

Before selecting either tool, it is important to consider the performance and features of each design, as well as the application in which it will be used. In some instances, the permanent packer is the only option, as may be the case in high pressure / high temperature (HP/HT) application. However, the operator must decide which features offer the best return over the life of the well.

Choosing Packer

1. Packer resistance to mechanical and hydraulic stresses in the well.2. Allowable differential pressure3. Allowable compression and tension at the tubing-packer connection and casing

contact.4. Setting and retrieval procedures5. Available accessories6. Consequences and various costs in the initial completion and work over operations7. Packer’s reputation and the user’s experience with it

Factors that affect choosing a packer

When choosing a packer for a cased-hole completion, the differential pressure and temperature requirements of the application must be considered. The well depth, deployment and setting method desired and final tubing landing conditions are also factors that come into play. The various operational modes (flowing, shut-in, injection and stimulation) that are anticipated over the life of the well are critical and must be considered carefully in the design phase.The changes in the operational modes that influence changes in temperature, differential pressure and axial loads all have direct impact on the packer. Understanding the uses and constraints of the different types of packers will help clarify the factors to consider when making a selection.

Further considerations are as follows when a packer is being chosen: the inside diameter of the casing the packer's inside through diameter elastomers' resistance to fluids metallurgy (corrosion problems)

Packer Components

1. Slip: is a wedge shaped device with wickers or teeth on its face which penetrate and grip the casing wall when the packer is set.

2. Cone: is beveled to match the back of the slip and forms a ramp that drives the slip outward and into the casing wall when setting force is applied to the packer.

3. Packing-element system (seal)4. Body or mandrel

Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing.

PackingElement

Mandrel

Cone

Slip

Setting mechanism: packers are set by steel slips which, when pushed along the cone-shaped ramp, grip the casing

Seal: it is provided by rubber rings squeezed out against the casing

Packer is classified by Means of retrieval: it is the first criterion used to classify packers; packers

can be retrieved by: drilling out or milling for permanent production packers actuating shear pins or rings by pulling on the tubing to release the

anchor slips; this is for retrievable packers mechanically releasing without actuating shear pins or rings (temporary

mechanical packers) that are mainly used for well testing or workover Tubing-Packer connection Rigid (tubing is fixed onto the packer) Semi free: the tubing enters the packer by means of a pipe with sealing

elements; the system allows the tubing to move up and down

Packer Classification

Production packers can be classified into two groups:- Retrievable - Permanent

They can be removed from the wellbore only by milling. It is fairly simple and generally offers higher performance in both temperature and pressure ratings than does the retrievable packer.In most instances, it has a smaller outside diameter (OD), offering greater running clearance inside the casing string than retrievable packers. The smaller OD and the compact design of the permanent packer help the tool negotiate through tight spots and deviations in the wellbore. The permanent packer also offers the largest inside diameter (ID) to make it compatible with larger-diameter tubing strings and monobore completion (Monobore describes a completion in which the ID of the completion string is of the size from top to bottom).

Permanent Packers

Permanent seal bore packer

Permanent (and retrievable) seal bore packers are designed to be set on electric wireline or hydraulically on the tubing string. Wireline setting affords speed and accuracy; however, the one-trip hydraulic-set versions offer the advantage of single-trip installations and allow the packer to be set with the wellhead flanged up.

Advantages and drawbacks of permanent packers

Permanent packer is simple in design and does not include complicated mechanisms.

It is highly reliable and can withstand considerable mechanical strains as well as high differential pressures.

It also has a range that offers the largest inside through diameter to fluid flow for a given casing diameter.

It is flexible as to the possible tubing-packer connections and can be left in the well during workover operations to change production equipment.

The biggest drawback is that it can only be removed by milling or drilling. This means that a drill string-type assembly must be used after the production wellhead has been removed and the tubing pulled out.

The production tubing sealing elements eventually adhere to the packer's inner mandrel if the tubing does not move for a long period. In contrast, overly frequent movement causes premature erosion of the sealing elements.

In any case, this type of packer has no equal in deep wells and is also often used in gas producing wells.

These packers are designed to be unseated and pulled out of the well simply without having to be milled out. Therefore they all have an incorporated mechanism so they can be unseated. They are hydraulically or mechanically set and all are connected to the tubing permanently. The retrievable packer can be very basic for low pressure/ low temperature (LP/LT) applications or very complex in high pressure/ high temperature (HP/HT) applications. Because of this design complexity in high-end tools, a retrievable packer offering performance levels similar to those of a permanent packer will invariable cost more. However, the ease of removing the packer from the wellbore as well as features, such as reset-ability and being able to reuse the packer often, may outweigh the added cost.

Retrievable Packers

Mechanical set packersThese packers are seldom used in permanent production strings. In contrast they are perfect for temporary stimulation, cementing and testing strings. This is because they can be reset immediately without having to be pulled out and because they are simple to retrieve. Generally speaking, these packers are set by compression, tension or rotating the string. They are equipped with friction pads to release and actuate the slips by rotating 90° in a J slot. Unseating them is very easy, usually by using the reverse of the setting procedure.

Compression packerRetrievable compression packer is activated or set by applying compressive force to the packer assembly. In most cases, this is achieved with set-down weight from the running string, which is controlled by the driller or operator observing the weight indicator on the rig. The retrievable compression packer is recommended for low- to medium-pressure/medium-temperature oil- or gas-production applications.

More common models of the compression packer with bypass have an additional set of hold-down slips, or an anchor system above the packing-element system.

The Tension Packer Assembly is an easy set – easy release retrievable packer set by

tension applied via the pipe string. It is typically used in medium- to shallow-depth

production or injection applications. The tension packer has a single set of

unidirectional slips that grip only the casing when the tubing is pulled in tension. The

tension packer does not have an equalizing (or bypass) valve to aid in pressure

equalization between the tubing and annulus to facilitate the retrieval of the packer.

This seldom presents a problem because the packer is run at relatively shallow

depths, and differential pressures across the packer during retrieval should be low.

Tension packer

Compression packer with bypass and set of hold-down slips

Compression packer

PackingElement

Cone

Slip

PackingElement

BypassSeal

Cone

Slip

Hold-downSlips

PackingElement

Mandrel

Cone

Slip

Tension packer

Hydraulic set packers

Hydraulic packers are set by pressurizing the production string. The setting slips are located under the seal, which usually consists of three rubber packing elements. The packing elements are often of different hardness and are chosen according to setting conditions and depth. They are separated by rings that limit extrusion of the rubber. The slips keep the packer in place and prevent it from slipping downward as long as there is some "weight" on it. The use of hold down buttons (friction buttons that are actuated hydraulically when the pressure under the packer is higher than the annular pressure) helps keep the packer from slipping upward.

Hold-downbuttons

Slip

The hydraulic-set packer has a bidirectional slip system that is actuated by a predetermined amount of hydraulic pressure applied to the tubing string. To achieve a pressure differential at the packer and set it, a temporary plugging device must be run in the tailpipe below the packer. The applied hydraulic pressure acts against a piston chamber in the packer. The force created by this action sets the slips and packs the element off.

This is a “mid-string” isolation packer that is designed to seal off approximately two strings of tubing. The dual packer allows the simultaneous production of two zones while keeping them isolated. Most multiple-string packers are retrievable; however, some permanent models exist for use in HP/HT applications.

Dual-string packer

Single-string packer

Hydraulic-set single-string packer Hydraulic-set dual-string packer

https://www.youtube.com/watch?v=FGdyiC2WIAkThey are good for use in deviated or crooked holes where tubing movement is restricted or unwanted.

Downhole Equipment

This is equipment that is used down hole. They are being set below and/or above the packer and are usually set using wireline techniques. Examples of this equipment are1. Circulating devices2. Landing nipples3. Other equipment like

(i) perforated tube (ii) blast joints (iii) flow couplings (iv) blanking plugs(v) buttonhole choke

Circulating Device

This is a device that is placed above the packer which allows the tubing and the annulus to communicate. It is used to control the well during work over operations. The main point when selecting this device is (1) Reliability(2) the ease of operation, compatibility with other special devices and

equipment in the well(3) its being able to facilitate or being repaired or reconditioned in a small-

scaled environment where a wireline may be used.NOTE: Any circulating system between the tubing and the annulus is a potential source of leakage or sticking. When this happens, it requires some or all the tubing-packer connection to be pulled out in order to replace it.

Types of circulating device1. Sliding sleeve2. Side pocket mandrel

Sliding SleeveIn oil- and gas-well completions, the sliding sleeve provides a means of establishing communication between the tubing and annulus for fluid circulation, selective zone production, or injection purposes. They are often used in multiple reservoir wells to regulate flow to and from the zones. The sliding sleeve is ported from ID to OD and has an internal closing sleeve that can be cycled multiple times using slick line or coiled-tubing shifting tools. When in the open position, the sleeve allows communication from tubing to annulus, and when closed, pressures are once again isolated.

Sliding sleeve (in closed position)

The sliding sleeve also incorporates a nipple profile and polished seal bore above and below the ports to allow the landing of various flow-control devices or an isolation tool should the sleeve fail to close. The isolation tool locks into the profile in the upper end of the sleeve, and seal stacks on the tool straddle the ports to achieve isolation. The success of sliding sleeves depends on well conditions. High temperature, sour gas, scale, and sand may cause operational problems in the opening and closing of sliding sleeves.

Side Pocket MandrelIt is a welded/mechanical product which contains a “side pocket” alongside with the main tubular conduit. The side pocket design eliminates the need to pull or re-run the tubing string, to install or replace gas- lift equipment. It maximizes the flow area and allows full tubing drift for well servicing operations through the mandrel, without restriction. It also has an oval-body mandrel design which is ideal for dual-completions and reduces overall running clearances.There is a slotted orienting sleeve in some selected models which enables precise installation and retrieval of gas-lift equipment in straight and deviated wellbores. It has a tool guard which protects gas lift equipment from damage by deflecting tools larger than the pulling/running tool from the flow control device. The mandrel material is fully heat-treated to provide the best combination of strength and corrosion resistance for its intended use.

Looking at the two types of circulating device, the one that offers the largest cross sectional area is the sliding sleeve valve, which is also installed in many wells. The side pocket mandrel is only advantageous for wells where workover is costly or fairly complex like subsea wells.

Landing NipplesThese are completion components fabricated as a short section of heavy wall tubular with a machined internal surface that provides a seal area and a locking profile. It is also referred as a profile setting nipples. ID slightly smaller that tubing ID, they are included in most completions at predetermined intervals to enable the installation of flow-control devices, such as plugs and chokes. They are positioned at strategic locations within the tubing string to allow the accurate placement of slick line plugs, check valves, bottom hole chokes, down hole flow regulators, and bottom hole pressure recorders. Larger ID’s are used near the surface than at bottom to allow tools with different ID’s to be set in the same string. Usually, they have a locking device to hold the tool in place. At least one landing /profile seating nipple is recommended near the bottom.

Types of landing nipple1. Top no- go nipples2. Bottom no-go nipples3. Selective- landing nipples4. Simple landing nipples

Top no-go nippleThe "top no-go" nipple is generally run when a single nipple is required in the hole and the largest ID possible is required through the nipple profile. However, more than one "top no-go" may be run if the IDs of the profiles are reduced sufficiently as the nipples progress in the hole to allow passage of the appropriate locking assembly through the nipple located immediately above the intended target nipple. The "top no-go" nipple accepts a lock assembly with a no-go shoulder located on the lock itself. When the lock assembly is run in the hole, the no-go shoulder on the lock engages or locates on top of the nipple. Once located, the locks are engaged into the locking groove, and the installation process is complete. Care must be taken when designing the completion to ensure that there are no ID restrictions above the nipple to prevent passage of the lock assembly.

For certain applications no locking device is required, such as in setting a hydraulic packer with an equalizing standing valve. In such cases, a nipple with a top no-go shoulder on the uppermost end and a polished bore is used. The standing valve shoulders against the reduced ID of the packing bore and seals in the polished section.

Bottom no-go nippleThe "bottom no-go" nipple has a no-go shoulder located in the bottom of the nipple. The lock assembly or slick line device landed in this type of nipple locates the nipple by landing on the bottom no-go. Once landed and located in the nipple, the locks can be engaged and the installation completed. Because its ID will not allow passage of any flow-control device through the nipple, the bottom no-go nipple is always run as the lowermost nipple in the completion. Another benefit of having a no-go nipple in the completion is that any other slick line tools or tubing swabs that are lost in the tubing string should not fall to the bottom. The lost equipment usually can be fished out of the tubing string or, in cases when it cannot, the tubing can be pulled to recover the tools.

Selective landing nipple"Selective" nipples are perhaps the most versatile of the three. In such a design, an unlimited number of the same size and type profile seating nipples may be run in the hole because the locking assembly or flow-control device is able to find and selectively land in any of them. In most systems, either the packing stack or a collet indicator is used to help the slick line operator locate the nipple, and alternately picking up and slacking off through the nipple actuates the locks and sets the flow-control device. The benefit of this type system is a larger ID through the completion and fewer slick line accessory items that must be inventoried. Generally, it is still advised that a no-go nipple be run on the bottom of the tubing string to prevent any lost tools from falling into the cased hole below the completion.

Other Equipments Used

It is positioned below the packer and will offer an alternative entry path for reservoir fluids into the tubing in case the tubing shoe becomes blocked by a stock perforation gun etc. for more information, check out your textbook.

Perforated Tube

Bottom hole ChokeBottom hole chokes are flow-control devices that are landed in profile seating nipples. The bottom hole choke restricts flow in the tubing string and allows control of production from different zones. It can be used to prevent freezing of surface controls. The choke assembly consists of a set of locks, packing mandrel, packing assembly, and choke bean. The choke bean is available with orifices of varying sizes. The orifice size must be predetermined and sized specifically for the intended application.

debris

Blast JointsThey are thick-walled tubular placed in the tubing string opposite the upper perforations in order to minimize the damage from erosion by the produced fluids. The blast joint is used in multiple-zone wells in which the tubing extends past a producing zone to deter the erosional velocity of the produced fluids and formation sand from cutting through the tubing string. In most cases, the blast joint is simply a thick, heavy wall joint of steel pipe; however, there are also more sophisticated designs that use materials such as Carbide® for severe service applications. Care must be taken when running and spacing out the tubing string to position the blast joint evenly across the open perforations. It is wise to run enough length of blast joint to provide 5 to 10 ft of overlap across the perforations to allow for errors in tubing measurements. Their cost is dependent on tubing size and number of joints.

Flow CouplingsFlow couplings are heavy wall connectors usually the same OD as the tubing couplings and have the same ID as the tubing string with which they are run. They are run above and below any profile seating nipple and sliding sleeve in which it is anticipated that the turbulence created by the flow through the nipple restriction can reach erosional velocity and damage the tubing string. The flow coupling does not stop the erosion; however, because of its thick cross section, it can and will extend the life of the completion because more material must be lost to erosion before failure occurs than in the case of the tubing string alone. Flow couplings are recommended when a flow-control device is to be installed on a permanent basis (i.e., safety valve or bottom hole choke).

Flow control device

Flow coupling

Flow coupling

Landing nipple

Blanking PlugsBlanking plugs may be landed in profile seating nipples or sliding sleeves to temporarily plug the tubing string, allowing pressure to be applied to the tubing string to test tubing or set a hydraulic packer, or to isolate and shut off the flow from the formation. The basic blanking plug consists of a lock subassembly, a packing stack, and a plug bottom. Each size and type of blanking plug is designed to fit a specific size and type of profile seating nipple or sleeve. Slick line blanking plugs always have an equalizing device incorporated into the design to allow pressure above and below the plug to equalize before releasing the lock from the nipple to prevent the tool string from being blown up the hole.

https://www.youtube.com/watch?v=Z-vCBV1AhBs

Subsurface Safety ValvesIf a catastrophic failure of the wellhead should occur, the subsurface safety valve provides a means to automatically shut off the flow of the well to avoid disaster. There are basically two types of down hole safety valves

- Subsurface-controlled safety valves (SSCSV)- Surface-controlled subsurface safety valves (SCSSV)

Subsurface-Controlled Safety Valves (SSCSV)The subsurface-controlled safety valves (often called velocity valves or Storm chokes) are wireline retrievable and are installed in standard profile seating nipples in the tubing string below the surface tubing hanger. A subsurface safety valve requires a change in the operating conditions at the valve to activate the closure mechanism. There are two models of subsurface controlled safety valves:

1. Pressure differential safety valve2. Pressure operated safety valve

Pressure differential safety valveThe velocity valve contains an internal orifice; the orifice is specifically sized to the flow characteristics of the well. The valve is normally open and is closed by an increase in flow rate across the orifice. This creates a pressure drop, or differential pressure, across the valve that causes it to close. The velocity valve reopens when the pressure is equalized across the valve.

Pressure operated safety valveThis is another type of subsurface-controlled valve which is the gas-charged or low-pressure valve. This valve is normally closed, and the bottom hole pressure must be higher than the preset pressure valve for the valve to remain open. If the flow rate of the well becomes too great and the bottom hole pressure falls below the preset value of the valve, the valve will automatically close. It is reopened by applying pressure to the tubing string to raise the pressure above the preset pressure value of the valve.

For either valve to work properly, the well must be capable of flowing at sufficient rates to close the valve, and the catastrophe must be severe enough to create the conditions necessary to actuate the closing system. The settings of the valves are critical to success, and they must be checked periodically.

Surface-Controlled Subsurface Safety Valves (SCSSV)The SCSSVs are also installed in the tubing string below the surface tubing hanger; however, they are controlled by hydraulic pressure through a capillary (control) line that connects to a surface control panel. Most SCSSV designs today use a flapper to form a seal. Both elastomeric and metal-to-metal seal designs are available.

The SCSSV is a normally closed (failsafe) valve and requires continuous hydraulic pressure on the control line to keep it open. The pressure acts upon an internal piston in the valve, which pushes against a spring. When the hydraulic pressure is relieved, the internal spring moves a flow tube upward and uncovers the flapper. The flapper then swings closed, shutting the well in. Ball valves work similarly. The surface control panel, because of a change in flowing characteristics that exceed predetermined operating limits, generally initiates the closing sequence. However, any failure of the system that results in loss of control-line pressure should result in the valve shutting in the well.

Types of SCSSVThe SCSSV is available in a tubing-retrievable model a wireline-retrievable type

To open the SCSSV, the pressure above it must be equalized (usually by pressuring up on the tubing string), and hydraulic pressure must be reapplied to the control line. Some models have a self-equalizing feature and can be reopened without the aid of pressuring up on the tubing. Whether the valve is working or not, most models have a pump-through kill feature that allow fluids to be pumped down the tubing to regain control of the well.

Wireline-retrievable SCSSVThe wireline-retrievable SCSSV is installed in a special ported safety-valve nipple. The capillary line is connected from the surface control panel to the ported nipple. The hydraulic pressure applied at the surface communicates to the valve through the ported nipple.The wireline-retrievable SCSSV can be pulled and serviced without pulling the tubing string out of the hole. However, because of the design and the use of elastomeric seals, they are somewhat less reliable than the tubing-retrievable version. Because of its smaller ID, the wireline-retrievable valve has a reduced flow area for production to pass through. The reduction in ID can create a pressure drop across the valve and turbulence in the tubing above it. In high-flow-rate wells, the turbulence can lead to erosion of the valve or tubing string. Access to the tubing string below the valve is restricted when the wireline-retrievable SCSSV is installed. The valve must be removed before performing any through-tubing work over or wireline operations below the valve.

Tubing-retrievable SCSSVThe tubing-retrievable model is more robust and offers a larger internal flow diameter. This helps eliminate turbulence and increases production capabilities. It also allows full-bore access to the tubing string below the valve. One disadvantage, in some instances, is its large OD. This may limit the size of tubing that can be run into certain sizes of casing.To service the tubing-retrievable SCSSV, the tubing string must be retrieved. However, to avoid this and extend the life of the completion, it is possible to disable the valve permanently by locking it open. A new wireline-retrievable SCSSV can then be inserted into the seal bore of the retrievable valve, enabling the well to continue production without interruption.

Major difference between SCSSV and SSCSV• Surface

– supplies hydraulic pressure to valve – holds open the valve against a spring or nitrogen charge that seeks to close the

valve• Subsurface

– flow from the well itself can be used in some cases to shut- in the well.

READING ASSIGNMENT: READ 3.7- RUNNING PROCEDURE