completion design manual (shell)

5/22/2018 Completion Design Manual (Shell)

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Completion Design

CONTENTS

1. COMPLETION DESIGN 1.1

1.1 INTRODUCTION 1

1.2 DESIGN CONSIDERATIONS 1

1.3 COMPLETION AT THE RESERVOIR 5

1.4 PERFORATING 8

1.4.1 Gun Types and Perforation Methods 9

1.5 WELL INFLOW PERFORMANCE 13

1.6 VERTICAL LIFT PERFORMANCE 16

1.7 FUNCTIONAL REQUIREMENTS OF A 19

COMPLETION STRING

1.8 COMPLETION COMPONENTS DESCRIPTIONS 24

1.8.1 Re-Entry Guide 24

1.8.2 Landing Nipple 25

1.8.3 Tubing Protection Joint 26

1.8.4 Perforated Joint 26

1.8.5 Sliding Side Door 27

1.8.6 Flow Couplings 29

1.8.7 Side Pocket Mandrels 291.8.8 Sub-Surface Safety Valves (SSSVs) 31

1.8.9 Annulus Safety Valves (ASVs) 34

1.8.10 Tubing Hanger 34

1.8.11 Xmas Tree 37

1.8.12 Production Packers 40

1.8.13 Seal Assemblies 45

1.8.14 Expansion Joints 48

1.8.15 Tubing 49

1.8.16 Sub-Sea Wellheads 52

1. 8.17 Examples of Single String Completions 54

1.9 DUAL COMPLETIONS 611.9.1 Examples of Dual String Completions 61

RGIT Montrose Ltd 20021


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1 COMPLETION DESIGN

1.1 INTRODUCTION

In simple terms, the term 'well completion' refers to the methods by which a newlydrilled well can be finalised so that reservoir fluids can be produced to surface

production facilities efficiently and safely. In general, the process of completing a

well includes the following:

A method of providing satisfactory communication between the reservoir and the

borehole.

The design of the tubulars (casing and tubing) which will be installed in the well

An appropriate method of raising reservoir fluids to the surface

The design, and the installation in the well, of the various components used to

allow efficient production, pressure integrity testing, emergency containment of

reservoir fluids, reservoir monitoring, barrier placement, well maintenance and

well kill The installation of safety devices and equipment which will automatically shut a

well in the event of a disaster.

In general, a well is the communication link between the surface and the reservoir and

it represents a large percentage of the expenditure in the development of an oil or gas

field. It is of utmost importance that the well be "completed" correctly at the onset, in

order that maximum overall productivity of the field may be obtained. The ideal

completion is the lowest cost completion, which will meet the demands placed on it

during its producing lifetime.

1.2 DESIGN CONSIDERATIONS

Before a production well is drilled, a great deal of planning must be undertaken to

ensure that the design of the completion is the best possible. A number of factors

must be taken into consideration during this planning stage, which can broadly be

split into reservoir considerations and mechanical considerations.

RESERVOIR CONSIDERATIONS

Producing Rate

Multiple Reservoirs

Reservoir Drive Mechanism

Secondary Recovery Requirements Stimulation

Sand Control

Artificial Lift

Workover Requirements

MECHANICAL CONSIDERATIONS

Functional Requirements

Operating Conditions

Component Design

Component Reliability

Safety



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Figure 1:1 shows an example of a North Sea drilling and casing schedule, the main

features are as follows:

1. The installation of a 30 ins conductor to approx. 500 ft. Conductor pipe provides

structural strength, covers soft formations just below the sea bed and is the largest

diameter pipe installed in a well. The hole required to accommodate conductor

pipe can be drilled (onshore) or pile driven (offshore).

2. The installation of 20 ins surface casing which terminates at 1,000 ft total vertical

depth. Surface casing pipe provides protection against shallow gas, seals off

shallow water bearing sands, and provides a base for the BOP stack and the

wellhead assembly. Surface casing is always cemented back to surface.

3. The installation of 133/8ins intermediate casing which terminates at 4,000 ft total

vertical depth. Intermediate casing pipe is used to protect weak formations, helps

prevent lost circulation of drilling fluids, and hole caving. (In a deep well, more

than one intermediate casing string may be set.) Intermediate casing is usuallycemented to a few hundred feet above the casing shoe of the surface casing string.

4. The installation of 95/8ins production casing which terminates approx. 7,500 ft

total vertical depth. Production casing pipe is used to provide control of the

completed well and is the main string that reaches down to the producing

interval(s). Production casing is usually cemented to a few hundred feet above the

casing shoe of the intermediate casing string.

NOTE: Drilling operations may be resumed to deepen the well and liner

casing installed and hung off from the lower end of the production

casing.

A wellhead provides a means of:

1. Support for each casing string.

2. Support for the BOP equipment for the next section of hole to be drilled.

3. Sealing off the various annuli from pressure control purposes.

4. Support for the completion string.

5. Support for the Xmas Tree.

6. Control of annulus pressure.

Surface wellheads are installed in sections after each casing string is run. Each casing

hanger also provides an annulus seal. Subsequent wellhead sections seal off on top of

the previous casing string. Figure 1:2 shows a simplified schematic of surface

wellhead sections. The letters shown represent a common way of representing annuli.

A. The 95/8 ins or production casing string when we insert tubing in the well this

would be termed the tubing/production casing annulus.

B. The 9

5

/8ins and 13

3

/8ins annulus.

C. 133/8 ins and 20 ins annulus.



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Figure 1:1- North Sea Casing Profile Example



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Typical OBS drilling sequence

Figure 1:2 Typical Surface Well Head System



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1.3 COMPLETION AT THE RESERVOIR

There are several methods of completing a well at the producing zone (or zones) in

order to admit reservoir fluids into the borehole at the depth of the reservoir (or

reservoirs).

1) Openhole {Barefoot) Completion

Production casing is set and cemented to a depth just above the producing zone. The

reservoir is then drilled into and the drilled hole left as it is; See Figure 1:3a. This

type of completion is ideal where the reservoir rock is of the appropriate mechanical

strength i.e. is consolidated and not slough or cave in.

Open hole completions have very little application in the North Sea where reservoirs

are heterogeneous or where the development is high risk and high costs. Open hole

completions offer no scope for isolating individual zones for production, stimulationor remedial work. However, this bottomhole completion type is used extensively in

land fields where cost savings from not running and perforating casing significantly

reduce total well costs. The advantages and disadvantages of open hole completion

types are indicated in Table 1:1.

2) Uncemented Liner Completions

In a non-consolidated formation where sand is likely to be produced, a non-cemented

liner may be used. The production casing is set above the producing zone and an open

hole drilled. The open hole is then lined with a short length of slotted or wire-

wrapped casing (or tubing) which is hung from the production casing and sealed intoit; See Figure 1:3b. The slots or wire wrapped pipe prevents sand from entering the

wellbore.

In sandy wells where slotted or wire wrapped liner has proved inadequate, the

refinement technique of gravel packing has been developed. Gravel packing consists

of filling the annular space between the open hole and the liner with a sheath of

gravel the external gravel pack. The gravel used is coarse sand with a grain

diameter appropriate for controlling unwanted sand production. Sand screens are

available where the coarse sand is already pre-packed in the liner assembly.

This bottomhole completion type has all the disadvantages of the open hole

completion with the added cost of the liner and liner hanger thrown in. Its application

is as for the open hole type, but where unconsolidated sands require to be controlled.

The advantages and disadvantages of uncemented liner completion types are

indicated in Table 1:1.

3) Cased and Cemented Completions

This is the most common type of bottomhole completion methods especially in the

North Sea. In this type of completion the production casing or liner is set and

cemented through and beyond the producing zone or zones. Communication with the

reservoir is then established by shooting holes through the casing or liner; See Figure

1:3c. The cement sheath around the liner/ casing isolates each zone or layer of a

reservoir and permits zones to be selectively perforated, produced, and stimulated.The initial cost of completing this way has higher cost implications. The advantages

and disadvantages of cased and cemented completion types are indicated in Table 1:1.



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BOTTOMHOLE ADVANTAGES DISADVANTAGES

COMPLETION

TECHNIQUE

Open Hole No perforating, no production Liable to "sand out"

casing, no cementing expense

Minimum rig time No selectivity for production

or stimulation

Full diameter hole in the

payzone improves productivity Ability to isolate is limited to the

lower part of the hole

No critical log interpretation

is required

Slotted Liner No perforating or cementing No selectivity for production or

expense for the production stimulation

casing

Assists in preventing sand Cost of slotted liner or pre-

production packed screen

No critical log interpretation is Difficult to isolate zones for

required production control

Slightly longer completion time

than for open hole completion

Cased and Introduces flexibility allowing Requires critical log

Cemented isolation of zones and selection interpretation to specify actual

of zones for production or perforation zoneinjection

Cost of casing/liner and

cementation

Cost of rig time for longer

completion period

Table 1:1- Bottomhole Completion Techniques -Advantages and Disadvantages



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Figure 1:3 Methods of Completing at the Producing Zone



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1.4 PERFORATING

It will be necessary in most cases to perforate a hydrocarbon bearing zone in cased

hole completions in order to realise optimum production. Some wells can flow open-

hole but, where a formation is relatively unconsolidated, flow rates are expected to be

high and for reasons of safety, perforated cased hole completions are usually

considered preferable. Perforating is an operation whereby holes are made through

the production casing (or liner) and its cement sheath into the reservoir to permit oil

or gas to flow into the wellbore. Nowadays, virtually all perforating is performed with

shaped charge perforators. Bullet perforators are occasionally used for particular

applications.

As far a completion design is concerned, the following comment cannot be

overstated. "The fate of a well hinges on years of exploration, months of planning,

and weeks of drilling. But ultimately it depends on perforating the optimal

completion, which begins with the first millisecond of perforating. Profitability is

strongly influenced by the critical link between the reservoir and the wellbore.

Perforations must provide a clean flow channel between the producing formation and

the wellbore with minimum damage to the producing formation. The ultimate test of

the effectiveness of a perforating system, however, is the well productivity. The

productivity of a perforated completion depends significantly on the geometry of the

perforations. The major geometrical factors, See Figure 1:4, that determine the

efficiency of flow in a perforated completion are:

Perforation length

Shot density

Angular phasing

Perforation diameter

The relative importance of each of these factors on well productivity depends on the

type of completion, formation characteristics, and the extent of formation damage

from drilling and cementing operations. The method of perforating a well must be

meticulously planned.

Figure 1:4 Perforation Geometry



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1.4.1 Gun Types and Perforation Methods

There are three basic perforating gun types:

Retrievable hollow carrier gun Non-Retrievable or Expendable gun

Semi-Expendable gun

Each type is available for through-tubing work or as a "casing gun"; See Figure 1:5a.

The retrievable hollow gun carrier consists of a steel tube into which a shaped

charge is secured - the gun tube is sealed against hydrostatic pressure, The charge is

surrounded by air at atmospheric pressure. When the charge fires, the explosive force

slightly expands the carrier wall but the gun and the debris within the gun are fully

retrieved from the well.

The non-retrievable or expendable gunconsists of individually sealed cases made ofa frangible material e.g. aluminium, ceramic or cast iron; See Figure 1:5b. The shaped

charge is contained within the case and when detonated, blasts the case into small

pieces. Debris remains in the well.

With semi-expendable guns, the charges are secured on a retrievable wire carrier or

metal bar; See Figure 1:5c. This reduces the debris left in the well and generally

increases the ruggedness of the gun.

There are currently three standard methods of perforating a well using shaped

charges:

Casing gun perforating (run on wireline)

Through-tubing perforating (TTP) (run on wireline)

Tubing-conveyed perforating (TCP) (run on tubing)

Figure 1:6 shows schematically the application of the three main perforating

techniques.

TCP combines the best features of both casing guns and through-tubing guns and not

surprisingly is now the most widely used perforating technique used in the North Sea.

The guns are run as an integral part of a Drill Stem Test (DST) or a completion string.

The guns are fired only after a packer has been set, an Xmas Tree has been installedand the entire completion string pressure integrity tested. Firing (detonation) can be

achieved using annulus or tubing pressure, mechanically or electrically in which case

a wireline assembly has to be run in the well. The guns can be jettisoned after firing

and allowed to fall to the bottom of the well below the perforated interval.

NOTE: The completion requirement for a TCP system is to allow an appropriate

sump for the guns to fall into.



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The advantages of TCP systems are:

Large intervals can be perforated at one time

Easy to perforate in deviated wells

Large gun sizes can be used with high shot densities Perforating may be carried out in under-balanced conditions

Safest method to perforate

The disadvantages are:

Entire completion string must be pulled and re-run if the guns fail

Additional hole must be drilled below the reservoir to accommodate the guns

For a TCP system, a radioactive source is incorporated in a sub in the completion

string for correlating the guns. The sub can be logged with a gamma ray logging tool

to determine the exact position of the guns with respect to the formation.



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Figure 1:5 Perforating Gun Types


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Figure 1:6 Perforating Techniques


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1.5 WELL INFLOW PERFORMANCE

The first tangible evidence of having found a hydrocarbon bearing reservoir in an

exploration well is provided by the drill cuttings. This evidence may be backed up by

core sampling and/ or logging. However, the only way to find out if the hydrocarbons

are recoverable is to run a Drill Stem Test (DST), which is a means of flowing the

well safely to surface to monitor the reservoir's dynamic performance. Historically

DSTs were performed using drill string, as the name implies, but nowadays most

offshore DSTs are run using a specially designed string with tubing as the production

conduit. An example of a DST string is illustrated in Figure 1:7.

The purpose of a DST is to obtain reservoir data necessary to plan the development of

a field and to optimise recovery from a well. Such reservoir data includes:

The static reservoir pressure

The composition of the produced fluids

The well productivity Indications of reservoir heterogeneities or boundaries

Knowledge of the initial static reservoir pressure is vital and must be made before it is

disturbed by significant flow. It is from this reference point that comparisons and

calculations are made which help to define the development of the reservoir. Also of

great importance is the effect of flowing the well on its drive mechanism. Accurate

well testing and analysis of results from several exploratory wells will reveal the

nature and source of this drive.

Inflow performance relates to the movement or flow of fluid form a reservoir into the

bottom of the wellbore. Inflow performance response (IPR) or deliverability curves

are used to evaluate and predict well performance at the exploration stage. Periodic

production tests are also used to define the IPR curve after the completion string has

been installed in the well. An IPR curve is a plot of the drawdown induced by flowing

the well versus the flowrate at the bottom of the well. For a reservoir containing

liquids, the drawdown is the difference between the static reservoir pressure and the

flowing pressure at the depth of the reservoir. An example of an IPR curve for a

liquid reservoir is shown in Figure 1:8. An IPR curve is specific to the well at the

time of testing. Pressure depletion from the reservoir will change the IPR curve.

An important application of IPR curves for wells drilled into a particular reservoir

system is in the maintenance of production. If one or more wells are shut in,

petroleum engineers, using IPR curves, can predict the appropriate choke sizes forflow from other wells in the same field to compensate for lost production. The other

important application of IPR curves is in completion design.



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Figure 1:7 Typical Drill Stem Test (DST) String


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A (Oil Well) - typical IPR showing LowProductivity.

B (Oil Well) - typical IPR showing High

Productivity.

C (Gas Well) - IPR showing an AdditionalPressure Drop caused by inertial andturbulent effects in the vicinity of thewellbore.

Figure 1:8 Example of an IPR Curve


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1.6 VERTICAL LIFT PERFORMANCE

Vertical lift performance (VPR) is concerned with the movement of reservoir fluids

from the wellbore at the depth of the reservoir to the production choke on surface.

VPR curves are dependent on tubing intake pressures, tubing head pressures, tubing

IDs, tubing pressure losses, fluid properties, fluid phase behaviour, and choke

performance; The inflow and outflow systems for a well are illustrated in Figure 1:9.

Figure 1:9 -Well Outflow and Inflow Systems



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NOTE: During production, critical flowing conditions are usually maintained at

the choke

An example of VLP curves for various pipes Ids is shown in Figure 1:10.

Intake

Pressure

(psi)

Oil Flowrate (bopd)

Figure 1:10 Typical Vertical Lift Performance (VLP) for Various Tubing Sizes



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Matching the VLP curve to the IPR curve (nodal analysis) will identify which ID will

be appropriate for the production required from the well; Figure 1:11. Tubing

selected on this basis will optimise flow from the reservoir to production facilities.

When depletion of a reservoir occurs, VLP curves are utilised to determine the new

conduit size to match its new IPR curve.

Figure 1:11 Matching VLP Curves with an IPR Curve



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1.7 FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING

Design of a completion string involves the selection of components that perform

specific functions and these functions are dependent on the philosophy of the

operating company. Operating company philosophies differ with respect to

completion string design and in some cases there are historic reasons for the inclusion

of components that provide specific functions.

In this section the functional requirements for a completion string will be discussed

here by example.Next, actual completion examples will be illustrated and differing

philosophies discussed.

Completion Design Example 1

Consider the casing schematic of Figure 1:1. The objective is to design a completion

string for this well with the following basic functional requirements:

To provide optimum flowing conditions To protect the casing from well fluids

To contain reservoir pressure in an emergency

To enable downhole chemical injection

To enable the well to be put in a safe condition prior to removing the production

conduit (i.e. to be killed)

To enable routine downhole operations

NOTE: The above functional requirements are not exhaustive.

A completion string that fulfils these functional requirements is illustrated in Figure

1:12. It is important to realise this example design is only a solution and not the

solution. This design is called a Single Zone Single String Completion.



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Master Valve

Swab Valve

Figure 1:12 Completion Design Example 1


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The completion design of Figure 1:12 also addresses the other functional requirements of:

Suspension of the tubing

Compensation for expansion or contraction of the tubing

Internal erosion of the tubing Protection of the reservoir during well kill operations

Pumping operations for well kill

Well intervention operations out of the lower end of the tubing

Pressure integrity testing

Reservoir monitoring

Installation points for well barriers

The component selection for this completion is shown in Table 1:2.

FUNCTIONAL REQUIREMENT COMPONENT

Optimise Production Tubing ID

Casing Protection Tubing Hanger

Permanent Packer

Emergency Containment Safety Valve Landing Nipple (SVLN)

Hydraulic Control Line

Wireline Retrievable Safety Valve (WRSV)

Chemical Injection Side Pocket Mandrel (SPM)

Well Kill Sliding Side Door (SSD)

Routine Downhole Operations Xmas Tree

Tubing String Movement Seal AssemblyExtend Tubing Life Flow Couplings

Support Tubing Hanger

Barrier Installation Points Landing Nipples

Tubing Hanger

Pressure Testing Landing Nipples

Pumping Operations Piping Manifold c/w Choke

Table 1:2- Component Selection for Completion Example 1

NOTE: Some components have dual functions.

NOTE: This completion design utilises a permanent packer and tailpipe that is

installed by wireline techniques prior to running the completion string

(packer systems will be discussed later).



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Completion Design Example 2

Figure 1:13 shows another example of a Single Zone Single String Completion that

illustrates additional functional requirements.

The component selection for this completion is shown in Table 1:3:

COMPONENT FUNCTION

Tubing hanger Tubing Support

Tubing-to-Casing Seal

Barrier Installation Point

Sub-Surface Safety Valve (SSSV) Emergency Containment

Flow Couplings Tubing Protection Against Internal Erosion

Upper Side Pocket Mandrels (SPMs) Unloading Annulus Liquids

Lowest Side Pocket Mandrel (SPM) Point of Gas Injection

Sliding Side Door (SSD) Tubing-to-Annulus Circulation


Landing Nipple Pressure Testing of Tubing String


Retrievable Packer Protect the Casing from Wellfluids

Ensure Retrievability of All Components

Landing Nipple Pressure Testing of Tubing String


Installation Point for Plug to Set Packer

Perforated Joint Allows Flow of Fluid when Monitoring Reservoir

Performance

Landing Nipple (No-Go) Installation Point for Pressure/Temperature Gauges

Re-Entry Guide Allows Unrestricted Re-Entry of Well Intervention

Tools Into the Tubing

Table 1:3- Component Selection for Completion Example 2

NOTE: This completion utilises a retrievable packer that will be run and set in

the casing by the application of pressure to the tubing (packer systemswill be discussed later).

The additional functional requirements of this completion design are:

Retrievability of all components from the well

Reservoir monitoring

Injection of gas in into tubing to assist production



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Figure 1:13 Completion Design Example 2


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1.8 COMPLETION COMPONENTS DESCRIPTIONS

The following completion component descriptions follow the completion design of

Figure 1:12 and Figure 1:13. This completion incorporates components common to

many well completions. Workovers are often a result of the failure of a completion

component, and thus a good working knowledge of completion components and their

purpose is an essential pre- requisite to understanding workover and well control

problems.

1.8.1 Re-Entry Guide

A re-entry guide generally takes one of two forms:

1. Bell Guide

2. Mule Shoe

The Bell Guide; Figure 1:14, has a 45 lead in taper to allow easy re-entry into thetubing of well intervention toolstrings (i.e. wireline or coiled tubing). This guide is

commonly used in completions where the end of the tubing string does not need to

bypass the top of a liner hanger.

The Mule Shoe Guide; Figure 1:14, is essentially the same as the Bell Guide with the

exception of a large 45 shoulder. Should the tubing land on a liner lip while running

the completion in the well, the large 45 shoulder should orientate onto the liner lip

and kick the tubing into the liner.

Wireline Entry Guide withBell Bottom

Wireline Entry Guide withHalf Muleshoe Bottom

Figure 1:14 -Re-entry Guides



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1.8.2 Landing Nipple

A Landing Nipple, Figure 1:15 is a short tubular device with an internally machined

profile which can accommodate and secure a locking device called a lock mandrel run

usually using wireline well intervention equipment. The landing nipple also provides

a pressure seal against the internal bore of the nipple and the outer surface of the

locking mandrel.

Landing Nipples are incorporated at various points in the completion string

depending on their functional requirement. Common uses for landing nipples are as

follows:

Installation points for setting plugs for pressure testing, setting hydraulic-set

packers or isolating zones

Installation point for a sub-surface safety valve (SSSV)

Installation point for a downhole regulator or choke

Installation point for bottomhole pressure and temperature gauges

A No-Go Landing Nipple, See Figure 1:15, has a small shoulder located within the

internal bore of the nipple for the purpose of preventing wireline tools from falling

out of the end the tubing, if dropped. Only one No-Go Landing Nipple of the same

size can be used in a completion string, the lowermost nipple being the No-Go nipple.

More than one No-Go Landing Nipple can be incorporated in a completion string

provided that a step down in No- Go shoulder size is observed.

NOTE: In highly deviated wells it may not be possible to use Landing

Nipples at inclinations greater than 70. Wireline operators com-

monly use Landing Nipples for depth references.

Figure 1:15 Landing Nipples



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The plugs that may be installed in Landing Nipples are:

Plug with shear disc (pump-open)

Plug with equalising valve

Plug with non-return valve

and the choice of plug depends on the pressure control required and the chances of

retrieval.

1.8.3 Tubing Protection Joint

This is a joint of tubing included for the specific purpose of protecting bottom hole

pressure and temperature gauges from excessive vibration while installed in the

landing nipple directly above.

1.8.4 Perforated Joint

A Perforated Joint, See Figure 1:16, may be incorporated in the completion string for

the purpose of providing bypass flow if bottomhole pressure and temperature gauges

are used for reservoir monitoring. The design criteria for a Perforated Joint is that the

total cross-sectional area of the holes should be at least equivalent to the cross

sectional area corresponding to internal diameter of the tubing.

Figure 1:16- Perforated Joint



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1.8.5 Sliding Side Door

A Sliding Side Door (SSD) or Sliding Sleeve, See Figure 1:17, allows communication

between the tubing and the annulus. Sliding Side Doors consist of two concentric

sleeves, each with slots or holes. The inner sleeve can be moved with well

intervention tools, usually wireline, to align the openings to provide a communication

path for the circulation of fluids.

Sliding Side Doors are used for the following purposes:

To circulate a less dense fluid into the tubing prior to production

To circulate appropriate kill fluid into the well prior to workover

As a production device in a multi-zone completion

As a contingency should tubing/tailpipe plugging occur

As a contingency to equalise pressure across a deep set plug after pressure

integrity testing

To assist in the removal of hydrocarbons below packers

NOTE: As with any communication devices, the differential pressure across

SSDs should be known prior to opening.

NOTE: In some areas, the sealing systems between the concentric sleeves

are incompatible with the produced fluids and hence alternative

methods of producing tubing-to-annulus communication are used

(e.g. Side Pocket Mandrel, Tubing Perforating).



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Figure 1:17 Sliding Side Door (SSD)


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1.8.6 Flow Couplings

Flow Couplings are used in many completions above and/ or below a completion

component where turbulence may exist to prevent loss of tubing string integrity and

mechanical strength due to internal erosion directly above and/ or below the

component. Turbulence may be caused by the profiles internal to a component.

Flow Couplings are thick-walled tubulars (of the same internal diameter as the

tubing) made of high grade alloy steel usually supplied in 10, 15, or 20 ft lengths and

their use depends on erosional criteria obtained from fluid velocity and particulate

content.

NOTE: In multi-zone completions, Blast Joints are commonly used to

prevent loss of tubing string integrity due to external erosion

resulting from the jetting actions directly opposite producing

formations.

1.8.7 Side Pocket Mandrels

A Side Pocket Mandrel (SPM); See Figure 1:18, along with its through bore, contains

an offset pocket which is ported to the annulus. Various valves can be installed/

retrieved into/from the side pocket by wireline methods to facilitate annulus-to-tubing

communication. Side pocket valves, which provide a seal above and below the

communication ports, include:

1. Gas Lift Valves -when installed in the SPM, the valve responds to the pressure of

gas injected into the annulus by opening and allowing gas injection into the

tubing. In a gas lift system, the lowest SPM is that used for gas injection into thetubing and the upper SPMs are those used to unload the annulus of completion

fluid down to the point of gas injection.

2. Chemical Injection Valves -these allow injection of chemicals (e.g. corrosion

inhibitors) into the tubing. They are opened by pressure on the annulus side.

3. Circulation Valves -these are used to circulate fluids from the annulus to the

tubing without damaging the pocket.

4. Equalisation Valves -are isolation and pressure equalisation devices that prevent

communication between the tubing and the annulus, and can provide an

equalisation facility by initially removing a prong from the valve.

5. Differential Kill Valves -these are used to provide a means of communication

between the annulus and the tubing by the application of annulus pressure. An

SPM with a differential valve installed provides the same function as a Sliding

Side Door.

6. Dummy Valves -these are solely isolation devices that prevent communication

between the tubing and the annulus.

NOTE: An SPM may be used as a circulation device in preference to an

SSD as side pocket valves may be retrieved for repair and/or sealreplacement.



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Figure 1:18Side Pocket Mandrel (SPM)


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1.8.8 Sub-Surface Safety Valves (SSSVs)

The purpose of an SSSV is to shut off flow from a well in the event of a potentially

catastrophic situation occurring. These situations include serious damage to the

wellhead, failure of surface equipment, and fire at surface. Different operating

companies have differing philosophies on the inclusion of an SSSV. For example, in

an offshore well, at least one SSSV is placed in every well at a depth, which varies

from 200 ft to 2,000 ft below the seabed. The depth at which an SSSV is installed in a

completion is dependent on well environment (onshore, offshore), production

characteristics (wax or hydrate deposition depth), and the characteristics of the safety

valve (maximum failsafe setting depth).

NOTE: It is generally recommended that an SSSV be installed in a well

that is capable of sustaining natural flow.

In the North Sea the installation of an SSSV is governed by law.

SSSVs can be divided into type groups according to their method of operation:

Direct Controlled Safety Valves

These are designed to shut in the well when changes occur in the flowing conditions

at the depth of the valve, that is, when the flowing condition exceed a pre-determined

rate or when the pressure in the tubing at the depth of the valve falls below a pre-

determined value. Such valves are often called "storm chokes". These valves are

termed Sub-Surface Controlled Sub-Surface Safety Valves (SSCSVs).

Remote Controlled Safety Valves

These are independent of changes in well conditions and are actuated open usually by

hydraulic pressure from surface via a control line to the depth of the safety valve.Loss of hydraulic pressure will result in closure of the valve. A number of monitoring

pilots or sensing devices can be linked to the safety system, each pilot capable of

causing the valve to close if it senses a potentially dangerous situation. These valves

are termed Surface Controlled Sub- Surface Safety Valves (SCSSVs).

An SCSSVs run on wireline is called a wireline retrievable safety valve (WRSV) and

is installed in a special safety valve landing nipple (SVLN) which is made up as part

of the completion string; See Figure 1:19. A control line external to the tubing

provides hydraulic pressure to actuate the valve open.

The main advantage of utilising a WRSV is that it can be economically retrieved for

inspection. A primary disadvantage of a WRSV is related to its restricted bore which

does present a restriction to flow, and can cause hydrate or paraffin plugging if the

appropriate conditions exist. An SCSSV run as part of the tubing string is called a

tubing retrievable safety valve (TRSV); See Figure 1:20. Again, a control line

external to the tubing provides hydraulic pressure to actuate the valve open.

The main advantage of a TRSV is that unrestricted flow is provided by its full-bore

design, which does not contribute to hydrate or paraffin plugging problems. The main

disadvantage is that in the event of a critical failure of the valve, the completion string

must be pulled and this can be an extremely expensive operation. This disadvantage

has been partially overcome by the development of lock open tools for the TRSV and

the provision for a surface controlled wireline retrievable insert valve to be installedin the body of the TRSV.



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Figure 1:19 Typical Surface Controlled Wireline Retrievable Safety Valve (WRSV)


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Model T-5 Safety Valve

Figure 1:20 Typical Surface Controlled Tubing Retrievable Safety Valve (TRSV)


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1.8.9 Annulus Safety Valves (ASVs)

In gas lift systems where large amounts of pressurised gas exists in the tubing-casing

annulus, Annulus Safety Valves may be incorporated to contain this gas inventory in

the annulus in the event that the wellhead becomes damaged. ASVs are not discussed

here but an example completion design incorporating such a device is shown in

Figure 1:38.

1.8.10 Tubing Hanger

The Tubing Hanger is a completion component, which sits inside the Tubing Head

Spool and provides the following functions:

Suspends the tubing

Provides a seal between the tubing and the tubing head spool

Installation point for barrier protection

The Tubing Head Spool provides the following functions:

Provides a facility to lock the tubing hanger in place .

Provides a facility for fluid access to the' A 'annulus

Provides an appropriate base for the completion Xmas Tree

Both the Tubing Hanger and Tubing Head Spool are prepared to allow the actuation

of an SCSSV.

An example of a Tubing Hanger/Tubing Head Spool system is shown in Figure 1:21.

Such Tubing Hanger systems allow completion tubing to be suspended in neutral (ie.

all the tubing weight minus fluid buoyancy) or the tubing suspended in compression.

NOTE: Completion strings may be set in compression to accommodate for

tubing movement as a result of pumping cold fluids into the tubing,

i.e. thermal contraction effects. For example, water injection wells

may be set in compression prior to landing the hanger by installing

additional tubing in the well. When the water injection system is

operating, thermal effects will contract the string appropriate to the

additional tubing installed. Setting a completion in compression

requires that the tubing-to-packer arrangement be appropriate(packer systems will be discussed later).

NOTE: Completion strings may also be set in tension to compensate for

thermal expansion of the tubing due to production. Setting a

completion in tension requires pulling the tubing in tension prior to

production and dosing rams around a hanger nipple. The hanger

nipple is run an appropriate distance below a Ram Type Tubing

Hanger, See Figure 1:22, and the tension applied to the tubing

string to remove tubing from the well equivalent to that expected

from thermal expansion. Setting a completion in tension requires

that the tubing-to-packer arrangement be appropriate (packersystems will be discussed later).



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Figure 1:21 Tubing Head Spool/Tubing Hanger System


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Figure 1:22 Ram Type Tubing Hanger System


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1.8.11 Xmas Tree

An Xmas Tree is an assembly of valves, all with specific functions, used to control

flow from the well and to provide well intervention access for well maintenance or

reservoir monitoring.

NOTE: The Xmas Tree is normally connected directly to the tubing hanger

spool that sits on the uppermost casing head spool. The whole

assemblage of Xmas Tree, Tubing Hanger and uppermost Casing

Head Spool is sometimes referred to as the Wellhead.

A Xmas Tree may be a composite collection of valves or, more commonly nowadays,

constructed from a single block; See Figure 1:23. The solid block enables the unit to

be smaller and eliminates the danger of leakage from flanges.

Typically, from bottom to top, an Xmas Tree will contain the following valves:

Lower Master Gate Valve Manually operated and used as a last resort to shut in

a well.

Upper Master Gate Valve Usually hydraulically operated and also used to shut

in a well.

Flow Wing Valve Manually operated to permit the passage of hydro-

carbons to the production choke.

Kill Wing Valve Manually operated to permit entry of kill fluid to into

the tubing.

Swab Valve Manually operated and used to allow vertical access

into the tubing for well intervention work.

NOTE: Nowadays, all Xmas Tree valves are of the gate-valve type that

allows full bore access.

A typical surface wellhead and Xmas tree are shown in Figure 1:24.



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Figure 1:23 Typical Xmas Tree


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Figure 1:24 Typical Surface Wellhead and Xmas Tree


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1.8.12 Production Packers

A production packer may be defined as a sub-surface component used to provide a

seal between the casing and the tubing in a well to prevent the vertical movement of

fluids past the sealing point, allowing fluids from a reservoir to be produced to

surface facilities through the production tubing.

NOTE: By no means are all wells completed with production packers.

However, for the purposes of this course, only those packers used

in well completions will be discussed.

The prime purpose of using a packer or packers in a well completion is as follows:

To protect the casing from reservoir fluids

To protect the casing from the effects of flowing pressures

To isolate various producing zones

In general, packers are constructed of hardened slips which are forced to bite into the

casing wall to prevent upward or downward movement while a system of rubberised

elements contact the casing wall to effect a seal.

Production packers may be grouped according to their ability to be removed from a

well, that is, retrievable or permanent.

Retrievable Production Packers

Are run on the tubing string and may be set mechanically or hydraulically. They are

usually removed from the well by the application of mechanical forces. An example

of a retrievable production packer is shown in Figure 1:25.

Permanent Production Packers

These may run in a variety of ways and become an integral part of the casing once

set. A permanent packer may run as follows:

On wireline and set in the casing using pyrotechnics to generate the forces

required to set it in the casing

Or

On pipe and set hydraulically by the application of tubing pressure.

Figure 1:26 shows an example of this type of permanent packer.

NOTE: Both the above methods provide a disconnect mechanism from the

setting device. The setting device is removed from the well after the

packer has been set. The completion string is then run into the well

and a seal assembly stabbed into the polished bore of the packer.



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Figure 1:25 Example of a Retrievable Packer


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Figure 1:26 Example of a Permanent Packer


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Permanent packers may also be run

Latched onto the completion tubing and hydraulically set by the application of

tubing pressure.

NOTE: The tubing may be disconnected from the packer by rotation of the

latch system or by utilising an expansion joint located in the

completion directly above the latch assembly.

Figure 1:27 shows an example of this type of permanent (hydro-set) packer.

Permanent/Retrievable Production Packers

These packers have the same mechanical characteristics as permanent packers, but

have the facility to be released and recovered from the well. These packers will not be

discussed in this course.

NOTE: In general, permanent production packers can withstand much

greater differential pressures than the equivalent retrievable

packer.



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Figure 1:27 Example of a Hydro-Set Permanent Packer


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1.8.13 Seal Assemblies

Seal assemblies, run on tubing, packs off in the bore of a permanent packer. The

sealing element frequently used is the chevron packing ring, fabricated from synthetic

rubber, or from plastic such as Teflon. Seal rings are assembled in sets, facing

opposite directions, to give a two-way seal. An alternative to chevron seals is the

moulded rubber sleeve and in some permanent packer systems a choice of either is

provided.

Figure 1:28 illustrates the assemblies available for connecting the tubing to the packer

and maintaining a seal.

Locator Seal Assembly

Here the top collar or (No-Go Shoulder) locates on the bevel of the packer body, just

above the left-hand thread. This type of assembly allows the tubing to set in neutral or

compression.

NOTE: Seal assemblies of this type can be used without the locating collar.

Locator Seal Assemblies do not permit the tubing to be landed in tension. At most the

full tubing weight can be hung off at the tubing hanger. However, when the well is

producing, the temperature of the tubing will increase and the tubing will expand

longitudinally. With the locator seated on the packer, and top of the tubing string

fixed in the tubing hanger, expansion can take place only at the expense of buckling.

By using a series of seal subs below the locator, the tubing can be pulled back a

calculated distance (space-out) and then landed, leaving the locator the same distance

above the packer, but with the seal assembly still within the packer bore. This will

allow for tubing expansion. A completion string may also be spaced out appropriately

if overall cooling of the tubing string will occur eg. in a water injection well.

Anchor Seal Assembly

This seal assembly has a latch sleeve, threaded to match the left-hand thread at the top

of the packer. The lower part of the sleeve, carrying the thread, has vertical slots cut

in it, and the lower flank of the thread is chamfered. On entry into the packer, the

latch sleeve collapses inwards, and then springs out to engage the thread of the

packer. The anchor seal assembly permits the tubing to be landed in compression,

neutral, or tension. The anchor seal assembly can be released from the permanent

packer by pulling the tubing in slight tension and rotating the tubing right-handed at

surface. The latching sleeve will back out of the packer.

Polished Bore Receptacles (PBRs)

These are usually anchor latched to a hydro-set packer and run in the well in the

closed position (shear ringed, shear pinned, J-slotted). After the packer is set, the PBR

may be spaced out appropriately. A PBR affords maximum flow capability through

the packer and allows a method of disconnecting from the packer for workover

operation.

Tubing Seal Receptacles (TSRs)

These are usually anchor latched to a hydro-set packer and run in the well in the

closed position (shear ringed, shear pinned, J-slotted). After the packer is set, the TSR

may be spaced out appropriately. A TSR affords maximum flow capability through

the packer and allows a method of disconnecting from the packer for workover

operation. A TSR affords protection to the seals. Also, a TSR may be manufacturedwith circulation ports on the inner mandrel.

PBRs and TSRs are shown in Figure 1:29.



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Figure 1:28 Seal Assemblies


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Figure 1:29 PBR and TSR Schematic Seal Assemblies


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1.8.14 Expansion Joints

These are telescoping devices, See Figure 1:30, usually used in a completion string

above a retrievable packer to compensate for tubing movement and possibly to

prevent premature release of the packer from the well.

Figure 1:30 Expansion Joint



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1.8.15 Tubing

Although tubing is the last string of tubulars to be run in the well, its requirements

often dictate the whole well design. Tubing is run mainly to serve as the flow conduit

for the produced fluids. It also serves to isolate these fluids from the A annulus

when it is used in conjunction with a casing packer.

The basic tubing string design criteria are:

Size, appropriate to producing operations.

Tensile strength

Stress

Corrosion resistance

The American Petroleum Institute (API) identifies, assesses and develops standards

for oil and gas industry goods. Tubing is considered appropriate to API standard if the

following conform to certain specifications:

Weight per foot

Length ranges

Outside diameter

Wall thickness

Steel grade

Method of steel manufacture

and API standards also specify:

Physical dimensions of the thread connections

Performance for burst, collapse and tensile strength of the pipe body and thread

connections

An API type connection is shown in Figure 1:31.



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Figure 1:31- API Type Connection

API Tubing steel grades are identified by letters and numbers which dictate various

characteristics of the steel. For each grade, the number designates the minimum yield

strength. Thus J-55 grade steel has a minimum yield strength of 55,000 psi. In other

words, it can support a stress of 55,000 psi with an elongation of less than 0.5%. The

letter in conjunction with the number designates parameters such as the maximum

yield strength and the minimum ultimate strength which for J-55 pipe is 80,000 psi

and 75,000 psi respectively.

Table 1:4 shows the yield values for various API tubing grades:

Grade Minimum Yield (psi) Maximum Yield (psi) Minimum Ultimate

Yield (psi)

H-40 40,000 80,000 60,000

J-55 55,000 80,000 75,000

C-75 75,000 90,000 95,000

L-80 80,000 95,000 95,000

N-80 80,000 110,000 100,000

P105 105,000 135,000 120,000

Table 1:4 -Yield Values for Various API Tubing Grades



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Grade C-75 is for hydrogen sulphide service and where a higher strength than J-55 is

required.

In addition to API grades, there are many proprietary steel grades which may conform

to API specifications, but which are used extensively for various applications

requiring properties such as:

Very high tensile strength

Disproportionately high collapse strength

Resistance to sulphide stress cracking

Many tubing strings are run which contain these non-API tubulars. This pipe is made

to many but not all API specifications, with variations in steel grade, wall thickness,

outside diameter, thread connections, and related upset. Due to these variations, the

ratings of burst, collapse, and tensile specifications are non-API.

The type of tubing connections selected for a completion will depend mainly on thewell characteristics. The connection must be able to contain the produced fluids safely

and at the maximum pressures anticipated. The basic requirements of a tubing string

connection are:

Strength compatible with the operational requirements of the string during, and

after running.

Sealing properties suitable for the fluid and pressures expected.

Ease of stabbing during make-up, and safe break-out when pulling the tubing.

Resistance to damage, corrosion, and erosion.

There are two types of thread connection -API and Premium.

Premium connections are proprietary connections that offer premium features not

available on API connections. Most offer a metal-to-metal seal for improved high

pressure seal integrity. Premium connections exist with features such as flush connec-

tions, recess free bores, and special clearance. An example of a premium thread is

shown in Figure 1:32.



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Figure 1:32 - An Example of a Premium Connection

1.8.16 Sub-Sea Wellheads

Sub-Sea Wellheads serve the same function as a surface wellhead in providing

support and pressure integrity but are assembled differently. After positioning a

guidebase on the seabed, which is run with the initial conductor casing, a wellhead is

then run on the next string of casing and hung off in the conductor, See Figure 1:33.

This sub-sea wellhead is the basis for further operations. Drilling BOPs are installed

in some cases on a special oriented profile on top of the wellhead. The sub-sea Xmas

Tree is subsequently latched to the wellhead; See Figure 1:34.



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Figure 1:33 Sub-Sea Wellhead


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Figure 1:34 Typical Sub-Sea Wellhead and Xmas Tree

1.8.17 Examples of Single String Completions

1. Single Zone Single String Gravel Pack Completion See Figure 1:35

2. Single Zone Single String Water Injection Completion See Figure 1:36

3. Multiple Zone Single String Completion See Figure 1:37

4. Single Zone Single String Completion c/w ASV System See Figure 1:38

5. Dual Zone Single String Completion See Figure 1:39

6. Single Zone Single String Gravel Pack Horizontal See Figure 1:40

Completion



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Figure 1:35 Single Zone Single String Gravel Pack Completion



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Figure 1:36 Single Zone Single String Water Injection Completion



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Figure 1:37 Multiple Zone Single String Completion



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Figure 1:38 Single Zone Single String Completion c/w ASV System



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Figure 1:39 Dual Zone Single String Completion



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1.9 DUAL COMPLETIONS

Dual completions allow two zones to be produced separately and simultaneously via

separate tubing strings. Dual completions maximise the hydrocarbon recovery from a

well where the producing zones differ in pressure and/ or fluid type. The philosophy

behind designing each production conduit is the same as that for a single zone

completion possibly with the added contingency for converting the completion to one

that allows alternate production from each zone usually up the long string.

Apart from using dual hydraulic set production packers, See Figure 1:41, dual tubing

hanger systems, See Figure 1:42, and Dual Xmas Trees; See Figure 1:43, the

completion components used are as that for a single zone completion. To combat

erosion of the long string opposite perforations in the upper zone, the long string is

fitted with blast joints.

1.9.1 Examples of Dual String Completions

1. Dual Zone Dual String Completion See Figure 1:44

2. Triple Zone Dual String Completion See Figure 1:45

Figure 1:40 Single Zone Single String Gravel Pack Horizontal Completion



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1.9 DUAL COMPLETIONS

Dual Completions allow two zones to be produced separately and simultaneously via

separate tubing strings. Dual completions maximise the hydrocarbon recovery from a

well where the producing zones differ in pressure and/or fluid type. The philosophy

behind designing each production conduit is the same as that for a single zone

completion possibly with the added contingency for converting the completion to one

that allows alternate production from each zone usually up the long string.

Apart from using dual hydraulic set production packers, See Figure 1:41, dual tubing

hanger systems, See Figure 1:42, and Dual Xmas Trees, See Figure 1:43, the

completion components used are as that for a single zone completion. To combat

erosion of the long string opposite perforations in the upper zone, the long string is

fitted with blast joints.

1.9.1 Examples of Dual String Completions

1. Dual Zone Dual String Completion See Figure 1:44

2. Triple Zone Dual String Completion See Figure 1:45



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Figure 1:41 Example of a Retrievable Dual Production Packer


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Figure 1:42 Segmented Dual Hanger System


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Figure 1:43 Example of a Dual Xmas Tree


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Figure 1:44 Dual Zone Dual String Completion



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Figure 1:45 Triple Zone Dual String Completion


completion design manual (shell)

Documents

completion string1

completion design manual

completion designfigure

completion designcontents1

reservoir considerations

design considerationsbefore

lowest cost completion

reservoir monitoring