Part 3 Well Completion Equipment.pdf

Well Completion Equipment By Prof. Abdel-Alim Hashem 1

COMPLETION EQUIPMENT • In general, a well completion should provide a production conduit which: – Maximizes the safe recovery of hydrocarbons from a gas or oil well throughout its producing life. . – Gives an effective means of pressurizing selected zones in water or gas injection wells.

• Downhole accessories used should be designed to provide the safe installation and retrieval of the completion, and flexibility for sub-surface maintenance of the well using wireline, coiled tubing or other methods 2

COMPLETION EQUIPMENT • Even though different types of wells present distinct design and installation problems for engineers, most completions are just variations on a few basic designs types and, therefore, the equipment used is fairly standard. • An overview of the equipment commonly used in single and dual string completions is given in the following sections. 3

Tubing Hanger SCSSSV Control Line

Tubing Flow Coupling SCSSSV Landing Nipple Flow Coupling Side Pocket Mandrel

TYPICAL OIL WELL COMPLETION

Tubing Side Pocket Mandrel

Sliding Side Door Landing Nipple Retrievable Packer Landing Nipple Perforated Joint Landing Nipple Protection Joint 4 Wireline Shoe Guide

Tubing Hanger Tubing Flow Coupling SCSSSV Landing Nipple Flow Coupling

UPPER COMPLETION EQUIPMENT

Side Pocket Mandrel

Tubing

Side Pocket Mandrel

5

Sliding Side Door

Landing Nipple

LOWER COMPLETION EQUIPMENT

Retrievable Packer

Landing Nipple Perforated Joint Landing Nipple Protection Joint Wireline Shoe Guide6

WIRELINE RE-ENTRY GUIDE • A wireline entry guide is used for the safe re-entry of wireline tools from the casing or liner back into the tubing string. • It attaches to the end of the production string or packer tailpipe assembly and has a chamfered lead in with a full inside diameter. • Wireline re-entry guides are generally available in two forms: 7

WIRELINE RE-ENTRY GUIDE Mule-Shoe • This type of guide essentially has the same function as the Bell Guide but incorporates a large 45° angle cut on one side of the guide. • Should the guide hang up on a casing item such as a liner or packer top while being run, rotation of the tubing will cause the 45° shoulder to slide past and enter the liner. Bell Guide • This guide has a 45° lead in taper to allow re-entry into the tubing of wireline tools. • This type of guide is used in completions where the end of the tubing does not need to pass through any casing obstacles such as liner laps. 8

Re-entry Guide

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No-Go or Non Selective Nipple • The non-selective nipple receives a locking device that uses a No-Go for location purposes. • This requires that the OD of the locking device is slightly larger than the No-Go diameter of the nipple. • The No-Go diameter is usually a small shoulder located below the packing bore (bottom No-Go) but in some designs, the top of the packing bore itself is used as the No-Go. • Only one No-Go landing nipple of a particular size should be used in a completion string. • The No-Go provides a positive location and are widely used in high angle wells where wireline tool manipulation is difficult and weight indicator sensitivity is reduced. 10

Go or Selective Nipple • In the selective system, the locking devices are designed with the same key profile as the nipples and selection of the nipple is determined the operation of the running tool and the setting procedure. • The selective design is full bore and allows the instillation of several nipples of the same size. • Uses of landing nipples are to: – Plug tubing tram above, below or from both directions for pressure testing. – Leak detection. – Install safety valves, chokes and other flow control devices. – Install bottom hole pressure and temperature gauges. 11

“X” & “XN” WIRELINE LANDING NIPPLES

Orientation Groove Key Profile

Orientation Groove Key Profile Seal Bore

Seal Bore Trash Groove No-Go Shoulder

“X” Selective Landing Nipple

“XN” NO-Go Landing Nipple 12

Fish Neck

“X” & “XN” WIRELINE LOCK MANDREL

Expander Sleeve Spring “X” or “XN” Keys Packing Mandrel Packing

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OTHER TYPICAL WIRELINE LANDING NIPPLES

Key Profile

Key Profile Top No-Go

Seal Bore

Seal Bore

Bottom No-Go

Baker “AR” Bottom No-Go Landing Nipple

Petroline “QXN” Top NO-Go Landing Nipple

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Perforated Joint • In wells where flowing velocities are high, a restriction in the tubing, such as a gauge hanger, can cause false pressure and temperature readings. • Vibrations in the tool can cause extensive damage to delicate instruments. • To provide an alternative flow path, a perforated joint is instal1ed above the gauge hanger nipple and allows unrestricted flow around the gauge. • The perforated joint is normally a full tubing joint that is drilled with sufficient holes to provide a flow area greater than that in the tubing above. 15

LOWER COMPLETION EQUIPMENT

Retrievable Packer

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Casing Annulus Production Tubing

EXAMPLES OF COMPLETION PACKER FUNCTIONS

Packer Dual Packer Short String

Casing Long String Packer #1

Single Zone/Single String Completion

Packer #2

Packer #3

Dual Zone/Dual String Completion Multi Zone/Single 17 String Completion

Packer Completion

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Packers

• A packer is a device used to provide a seal between the tubing and the casing. • At suitable completion string, this seal allows the flow of reservoir fluids from the production formation to be contained within the tubing up to the surface. • This isolates the production casing from being exposed to well pressure and corrosion from well effluents or injection fluids. • A packer is tubular in construction and consists basically of: – Lock Ring and Mandrel – Slips – Cone – Seal – Inner Mandrel 19

Packers In general, packers are classified in two groups: – Retrievable – Permanent

Retrievable Packers • These are generally run into the wel1bore on tubing production tubing string. As the well implies, retrievable packers can be recovered from the well after setting by pulling it with the tubing. Permanent Packers • These are installed in the wellbore usual1y independent of the production tubing string. • permanent packer may be considered as an integral Part of the casing. Permanent packer can only be removed from the well by milling operations. 20

Packers • Packers may be further classified according to the number of bores required for production. – Single One concentric bore through the packer for use with a single tubing string – Dual: Two parallel bores through the packer for use with two tubing strings. – Triple :Three parallel bores through the packer for use with three tubing string.

• A typical packer description, therefore, might be: 9-5/8” dual 3-1/2”x 3-1/2” hydraulic retrievable packer

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TYPICAL RETRIEVABLE PACKERS

Single Hydraulic Packer

Dual Hydraulic Packer

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TYPICAL PERMANENT PACKERS

Wireline Set

Hydraulic Set

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Tension packer vs. set down packer • Tension packer – No tubing buckling – May fail in case of tubing expansion

• Set down packer (compression packer) – Tubing buckling

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Setting Methods Mechanical Mechanical • Run on a workstring, it is set by manipulation of the tubing by applying compression or tension in combination with rotation depending on the particular setting mechanism for that packer, NOTE: • Packers having rotation set/release mechanisms should not be used in highly deviated wells since the application of tubing torque may not be transferred downhole. 25

Setting Methods Mechanical Hydraulic • Packers can be run on a workstring or on the tubing string. • When the desired setting depth is reached the tubing is plugged below the packer with a check valve, standing valve or a wireline plug. • Hydrautic pressure is applied to the tubing to set the packer. • Generally, a predetermined upward pull on the tubing string will release the seal unit from the packer with a Hydraulic Permanent packer 26 system.

Setting Methods Mechanical Electrically on Wireline • This is generally restricted to permanent packers. • The packer is attached to a wireline setting adapter, connected to a setting gun on the end of the wireline and run in the wellbore. • Oh reaching the desired depth an electrical signal transmitted to the gun activates an explosive charge and, through a hydraulic chamber, provides the mechanical forces to set the packer. 27

Retrievable Packer Accessories Travel Joints (Telescoping or Expansion Joints) • A travel joint is used to compensate for tubing movement due to temperature and/or pressure changes during treating or production and is used with retrievable packer system. • Figure below shows a travel joint commonely used on the short string in dual string completion. • It composed of inner sleeve, outer sleeve and packing element 28

TRAVEL JOINT Packing

Inner Sleeve Outer Sleeve

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Permanent Packer Accessories • An important aspect in a completion with a permanent packer is the tubing/packer seal. • As the packer in effect becomes part of the casing after it is set, .the tubing must connect to the packer in a fashion so that it can be released. • This connection whether it is a straight stab in, latched or otherwise, must have a seal to isolate the annulus from well fluids and pressures. • This seal usually consists of a number6f seal elements to cater for some wear and tear. 30

Permanent Packer Accessories • These seal elements are classified into two groups, ·premium' and ·non-premium'. • The premium group is used in severe or sour well conditions i.e. H2S, CO2 etc. and are normally 'V' type packing stacks containing various packing materials resistant to the particular environment. • The non-premium seals are for sweet service and can be either 'V' type packing stacks or moulded rubber elements 31

Locator Tubing Seal Assemblies • Locator tubing seal assemblies and Tubing Seal Extensions, are fitted with a series of external seals providing an effective seal between the tubing and packer bore. • They also have a No-Go type locator for position determination within the packer. • Locator seal assembles are nominally proceed out so that they can accommodate both upward and downward tubing movement induced by changes in temperature and pressure. 32

Seal Bore Extensions • A seal bore extension is used to provide additional sealing bore length when a longer seal assembly is run to accommodate greater tubing movement. • The seal bore extension is run below the packer and has the same ID as the packer.

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PERMANENT PACKER ACCESSORIES “G” Locator

Anchor Latch

Locator Seal Assembly

Seal bore Extension

“K22” Anchor Seal Nipple

Anchor Latch

“EBH22” Anchor 34 Seal Assembly

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Polished Bore Receptacles (PBRs) • A PBR is simply a seal receptacle attached to the top of a permanent packer or liner hanger packer in which the seal assembly lands. • As the PBR bore can be made larger than the packer. • This provides a larger flow area through the seal assembly 36

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Tubing Bore Receptacles (TBRs) • A TSR is an inverted version of a PBR whereby a polished OD male member is attached to the top of the packer and the female (or overshot) is attached tubing. • The seals are contained in the female member so that they are recovered when pulling the tubing

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POLISHED BORE RECEPTACLE

Shear Ring

Debris Barrier

Seal Units Debris Barrier

Debris Barrier

Debris Barrier

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TUBING SEAL RECEPTACLE

Extra Long Tubing Seal Receptacle (ELTSR)

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PBR and TBR

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Sliding Side Door

LOWER COMPLETION EQUIPMENT

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Wireline Nipple Profile Pack Off Seal Area

SLIDING SIDE DOOR

Inner Sleeve

Seal Assembly

Three Stage Collet Lock Lock Recess (Equalising Position) Lock Recess (Open Position)

Polished Seal Area 44

Sliding Side Doors • Sliding Side Doors (SSDs) or Sliding Sleeves are installed in the tubing during well completion to provide a means of communication between the tubing and the annulus when the sleeve is moved to the open position. SSDs are used to: • Bring a weIl into production after drilling or workover by circulating the completion fluid out of the tubing and replacing it with a lighter underbalanced fluid. ' • Kill a well prior to pulling the tubing in a workover operation. • Provide selective zone production in a multiple zone well completion. 45

Sliding Side Doors • The application of SSDs as a circulation device means they must be positioned as close as possible to the packer, normally within 100 ft. • Used for selective zonal production, a number of SSDs can be installed in a single completion string between isolation packers and selectively opened or closed by wireline or coiled tubing methods. • Coiled tubing is generally used in high angle or horizontal wells where wireIine cannot reach. • SSDs are available in versions that open by shifting an inner sleeve, either, upwards or downwards by the use of the appropriate shifting tool. • When there are more than one SSD in a well, the sleeves may be opened and closed with selective shifting tools without disturbance of sleeves higher up in the string. 46

CT Unit Elements 1. 2. 3. 4.

Tubing Reel Injector Head Control Cabin Power Pack

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Major Components (Wireline Offshore Location) Components A. Grease & Hydraulic Control Unit B. Pressure Test Unit C. Power Pack D. Wireline Unit E. Pressure Control Equipment F. Wireline Mast Unit

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Sliding Side Doors CAUTION: • Tubing and annulus pressures must he equalized before an SSD’s opened to prevent wireline tools being blown up or down the tubing. • A common fault with SSD’s is that the seal failure usually leads to a workover although a pack-off can be installed as a temporary solution. • The top sub incorporates a nipple profile and the bottom sub has a polished bore to enable the installation of the pack-off, sometimes also termed a straddle.

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UPPER COMPLETION EQUIPMENT

Side Pocket Mandrel

Side Pocket Mandrel

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Side Pocket Mandrels • The Side Pocket ,Mandrel system was originally designed" for gas lift completions to provide a means of injecting gas from the casing-tubing annulus to the tubing via a gas lift valve. • However in recent times, they have also been commonly used in place of an SSD as a circulating device because seal failure can be rectified by pulling the dummy gas lift valve (or kill valve) with wireline and replacing the seals. 51

Side Pocket Mandrels • SPMs are installed in the completion string to act as receptacles for the following range of devices: – – – – – –

Gas lift valves Dummy valves Chemical injection valves Circulation valves Differential dump kill valves Equalizing valves.

• It is essential to understand the operation of the device installed in an SPM before conducting any well intervention as it may affect well control. 52

Orientation Sleeve

SIDE POCKET MANDREL

Tool Discriminator Latch Lug Upper Packing Bore Pocket Lower Packing Bore Section A-A 53

SPM LATCH/VALVES TYPICAL LATCH

DUMP KILL VALVE

REVERSE CIRCULATING VALVE

GAS LIFT VALVE

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Gas Lift and Wireline Equipment

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Upward jarring shears trigger pin and permits tool to be pulled out of hole

Tool now in a position to jar down into the pocket

Pin doesn't have to be sheared at this time

Latch

KICKOVER TOOL OPERATION VALVE INSTALLATION

Shear pins in arm will be sheared

Lower knuckle now in line with pocket

Valve Catcher

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UPPER COMPLETION EQUIPMENT Tubing

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Flow Coupling SCSSSV Landing Nipple Flow Coupling

UPPER COMPLETION EQUIPMENT

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Flow Couplings • Flow couplings, are heavy-walled tubulars, which are installed above any completion component which may cause flow turbulence such as wireline nipples, SSD’s, SCSSV landing nipples etc. and combat internal erosion. • They may be manufactured from harder materials and have a thicker wall thickness so that, if erosion is experienced, the flow coupling will still maintain pressure integrity over the projected life of the well. • In higher velocity wells, such as high pressure gas wells or injection wells. a flow coupling may also be placed below restrictions. 59

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Comparison of WRSVs and TRSVs WRSV Applications

TRSV Applications

General application: where intervention by wireline is available

General application: where larger flow area is desired for the tubing size

High pressure gas wells

High volume oil and gas wells

Extreme hostile environments where well fluids or temperature tend to shorten the life of component materials

Subsea compelion

High velocity wells with abrasive production

Multiple zone completions where several flow control devices are set beneath the TRSV Greater depth setting capabilities 61

Poppet Valve

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TYPICAL SAFETY VALVE SYSTEM

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WIRELINE RETRIEVABLE SAFETY VALVE (Ball Type)

Open

Closed

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BALL VALVE MECHANISM

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TUBING RETRIEVABLE SCSSV (Flapper Type)

Valve Closed

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FLAPPER VALVE MECHANISM

Hinge Pin Flapper Seat

Hinge Spring

Flapper 67

LARGE BORE FLAPPER CONSTRUCTION

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ANNULUS SAFETY VALVE

Production Casing

Multi-Purpose Expansion Joint Annulus Ports Tubing Poppet Valves Tubing Retrievable Safety Valve Control Line

Power Spring

Tubing Retrievable Safety Valve Annulus Safety Valve Control Line Flow Coupling

Spacer Annulus Safety Valve

Pack-Off Tubing Anchor

69 Rod Piston Safety Valve

Annular Safety Valve System Installation

Tubing Hanger

UPPER COMPLETION EQUIPMENT

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Horizontal Conventional Production Well Completion

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Horizontal Monobore Production Well Completion

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Casing Profile Example

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Typical Surface Wellhead System

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MANDREL TYPE TUBING HANGER SYSTEM

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Bowl Type Tubing Head/Mandrel Type Tubing Hanger A Tubing Head/Tubing Hanger combination unit is attached to the uppermost casing head on the wellhead. The main functions of this unit are to: – Suspend the tubing – Seal the annular space between the tubing and the casing – Lock the tubing hanger in place – Provide a base for the wellhead top assembly (Xmas Tree) – Provide access to the annular space ('A' annulus). • Suspension of the tubing is accomplished usually by threads, slips or any other suitable device, i e. rams. • The tubing head consists of a spool piece type housing where the internal profile of the top section is a straight or tapered cylindrical receptacle (bowl) into which the tubing hanger is landed, suspending the tubing and sealing off the volume between the tubing and the casing. 76

Features of Tubing Hanger Spools Top and Bottom Connections • the size and pressure ratings of these connections (usually flanged) must be compatible with. the size and pressure rating of the joining connections. Upper Bowl • provides the seal area for various tubing hangers and a load shoulder to support the production tubing. Lower Bowel • This is provided to house some type of isolation seal. Set Screw • or hold-down screws are found in most tubing heads and have two important functions. • Retain the tubing hanger and prevent any upward tubing movement due to pressure surges. • Activate (energize) the body seals on the tubing hanger. 77

Features of Tubing Hanger Spools Outlets • These provide access to the annulus (e.g. for pressure monitoring or gas lift) during production. Test Port • This permits the pressure testing of the hanger seal assembly, lockdown screw packing connection between flanges, and the secondary (isolation) seal. • The important features of tubing hangers are: Landing Threads • These are the uppermost threads on the hanger and they must support the entire weight of the tubing string during landing operations. Bottom Threads • These must support the entire weight of the tubing string and seal the producing conduit from the tubing/casing annulus. 78

Features of Tubing Hanger Spools Sealing Area • These provide compression type sealing between the outside diameter of the hanger body and the inside diameter of the hanger bowl. • Sealing is accomplished by energizing elastomer seals or metal-tometal seals by the action of tubing weight on various load-bearing surfaces. • Tubing hangers are sized according to the upper bowl of the tubing head and the tubing size the hanger win be supporting. • Thus, a 7" x 2-7/8" tubing " hanger means a 2-7/8" production string suspended from a tubing head 7Ihf," top bowl. ..

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COMPOSITE XMAS TREE

Tree Cap

Production Wing Valve Kill Wing Valve

Choke Valve

Upper Master Valve

Lower Master Valve

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Xmas Trees • A Xmas Tree is an assembly of valves and fittings used to control the flow of tubing fluids at surface, provide access to the production tubing and on some subsea completions to provide access to the annulus string. • In general, a Xmas Tree is essentially a manifold of valves, installed as a unit on top of a tubing head or subsea wellhead. • The ranges of trees available is wide and are not all addressed in this manual. • However the valve layout of surface Xmas trees is similar throughout and typically contains the following valves and features: 81

Xmas Trees Lower Master Valve (LMV) • The Lower Master Valve.is utilized on all Xmas trees to shut in a well. • This valve is usually operated manually. As its name implies, the master is the most important valve on the Xmas tree. • When closed, this valve should keep the well pressure under fun control and therefore should be in optimum condition - it should never be used as a working valve. • In moderate to high-pressure wells, Xmas trees are often furnished with a valve actuator system for automatic or remote controlled operation (i.e. surface safety valve system). • This is often a regulatory requirement in sour gas or highpressure wells., 82

Xmas Trees Upper Master Valve (UMV) • The Upper Master Valve is used on moderate to high pressure wells as a emergency shutin system where the valve should be capable of cutting at least 7/32" braidedwireline. • This valve can be actuated pneumatically or hydraulically. The UMV valve is a surface safety valve and is normally connected to an emergency shut-down (ESD) system. Flow Wing Valve (FWV) • The Flow Wing Valve permits the passage of well fluids to the choke valve. This valve can be operated manually or automatically (pneumatic or hydraulic) depending on whether a surface safety system is to be included in the production wing design. 83

Xmas Trees Choke Valve • The Choke Valve is used to restrict, control or regulate the flow of hydrocarbons to the production facilities. • This valve is operated manually or automatically and may be of the fixed (positive) or adjustable type. • It is the only valve on the Xmas tree that is used to control flow. • It is sometimes located downstream at the production manifold. NOTE: • All other valves used on Xmas trees are invariably of the gate valve type providing full bore access to the well. • These valves must be operated in the fully open ·or closed position. . 84

Xmas Trees Kill Wing Valve • The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure equalization across tree valves e.g. during wireline operations or prior to the removal/opening of a sub-surface safety valve. This valve is usually manually operated. Swab Valve • The Swab Valve permits vertical entry into the well for wireIine (e.g. running BHPIBHT gauges, tubing conditioning) or for well interventions such as coiled tubing operations and logging. This valve is operated manually. 85

Xmas Trees Xmas Tree Cap • The Xmas Tree Cap provides the appropriate connection for well control equipment when conducting wen interventions and is installed directly above the swab valve. • The Xmas Tree cap normally includes a quick union type connection and should be strong enough to support the well control equipment. The bore of the cap flange should be compatible with the tree and permit the running of service tools. Sometimes the cap is removed and replaced by tertiary well control equipment. (e.g. Shear Seal) 86

Composite Wellhead

87

Integral X-Tree

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Type 'SRL' Hanger Neck Seal

COMPACT WELLHEAD SYSTEM Identical Seal Assemblies

13-5/8" 10,000 W.P. Cameron 'Fastlock' Connector

13-5/8" Compact Housing 2-1/16" Outlets

20-3/4" 3,000 W.P. Cameron 'Fastlock' Hub Profile

Tubing 7" Casing

20" Casing Head Housing

9-5/8" Casing Hanger

9-5/8" Casing Landing Base

13-3/8" Casing

20" Casing

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SOLID BLOCK XMAS TREE

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End

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