Sonatrach's _Well Completions

8/7/2019 Sonatrach's _Well Completions

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September October 2005abalt solutions limited - 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION

Introduction to Hydrocarbon Exploitation

2005 Abalt Solutions Limited. All rights reserved

Well Completions

SectionBy Pratap Thimaiah

WellCompletions


Overview

Introduction to Well Completions DesignCompletion TypesCompletion Practices Casing and Cement

Brines and Completion Fluids


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Suggested Texts

L. DAKE: Applied Reservoir EngineeringL. DAKE : Basic Reservoir EngineeringECONOMIDIES : Petroleum Production SystemsMIAN, M.A : Petroleum Engineering : Handbookfor Practicing Engineers(Vol.1&2)JOSHI : Horizontal Well TechnologyALLEN & ROBERTS : Production Operations(Vol. 1-3)

Reservoir Engineering ManualCraft & Hopkins : Basic Reservoir EngineeringGATLIN : Drilling/Well CompletionsGOLAN: Well Performance

WellCompletions


Fundamental Requirements

A completion system must provide a meansof oil or gas production which is:

Safee.g., well security, environment

Efficient

e.g., production objectives Economic

e.g., cost vs. revenue


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Completion Definition

Definition: The methodology and technology required to

produce recoverable reserves (reservoir tosurface).

Process: The design, selection and installation of

tubulars, tools and equipment, located in thewellbore, for the purpose of conveying, pumpingor controlling production (or injection) fluids.

WellCompletions


Completions The Last 25 Years

Over the past 25 years completion evolutionhas effected:

Philosophy Technology Applications

Safety Contingency


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Completion Cost

Completion cost (relative) example for a 10,000 ft landwell

Mob/D

emob

Casin

g

Drilling

Rig

Drilling F

luids

Comp

letion

Tubula

rs&Eq

uipme

nt

Log g

ing &P

erfora

ting

Direc

tionalSe

rvices

Bits&C

oring

Ceme

nting

Supe

rvision

SitePre

parat

ion

Renta

lEq uip

ment

Perso

nnelLog

istics

Othe

r

Camp

100

200

300

400

r t ona Ph / t a te r y

x1

500

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Completion Design Process

Three distinct phases in the process: Conceptual completion design. Detailed completion design. Procurement and installation.


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Developing Prospect SOR

Defining problem andestablish needs

Gather Field/Well Data

Discussperspective/objectives

Feasibilitystudy/Appraisal

Economics

Conceptual Design

Translating aims to design

Detailed DesignField DevelopmentPlans

Detailed WellPlan

Detailed objective

Constraints: Ex sand, waterproblems

Resources:ex money, material

Environmental factors

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Procedure to establish an SOR

Review Data and establish initial objectives

Interdisciplinary discussion

Analysis of collective views

Modification to SOR

Write Final SOR


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The Completion provides the connection,

within the Well Structure,between the reservoirand the surface facilities.

Consists of The Inflow System

Perforations Sand control system

The Outflow System Tubing with flow

controls & safetydevices

Wellhead & Xmas Tree Flowline

The Total SystemPerformance


3030 at 151 mat 151 m

2020 at 299mat 299m

13 3/813 3/8 at 977mat 977m

9 5/89 5/8 at 1817mat 1817m

77 at 2383 mat 2383 m

5 1/25 1/2 at 2612mat 2612m

3 1/2 Tubing

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1. Determining the Range of WellPerformance

Conceptual Design Consideration Predict the range of initial near ideal (minimum

near wellbore effects) inflow performance anddetermine how this performance is likely tochange with time.

Data Required All well test and formation evaluation data from

appraisal or analogous wells, including RFTs,cores and logs.


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2. Determining the Range of OutflowPerformance

Conceptual Design Consideration In order to determine production rates, a method of

accurately modelling tubing performance is required. Thismodel should be used to determine the initial range of tubing performance and predict how this performance willchange with time.

Questions To Be Addressed Is there an appropriate method for predicting tubing

performance and what are the potential errors and theirimpact on the predictions?

What is the likely range of tubing performance over thearea of the field and with time?

Data Required PVT samples and flash data. Flowing gradient surveys from appraisal wells analogous wells to validate pressure drop prediction

method.

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3. Combining the Inflow and OutflowPerformance

Conceptual Design Considerations Confirm to an acceptable range of accuracy that the rates can be met. Determine the likely range of well performance over the field life.

Data Required Results from above inflow and outflow analyses.

Questions To Be Addressed Is the range of initial rates economically and technically feasible? Is the selected WHFP the economic optimum. What are the

repercussions of changing it? What is the appropriate tubing size for the range of inflow performance

and production rates? Will this tubing size sustain flow at the required rate over the

completion life? Is re-completing with a smaller tubing size economically attractive? Is artificial lift likely to be a requirement? If so, what is the conceptual

technique?


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4. Near Wellbore Performance

Conceptual Design Considerations The likely well performance was based on achieving near ideal

inflow performance (ie near zero skin). In the conceptual phase, the aim is to identify wells where the near

wellbore performance is likely to be less than ideal (positive skin),or where there is a potential for better than ideal, ie stimulation(negative skin).

Questions to Be Addressed Identify the potential types of near wellbore damage, possible

stimulation methods and potential sand production problems? Evaluate the sensitivity to perforating techniques? Identify if near wellbore performance is a critical factor in the field

development and attempt to quantify the risks?

Data Required

Appraisal well tests should be designed to acquire all the datanecessary to avoid near wellbore problems in the developmentwells..

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5. Architecture of Completions

Conceptual Design Considerations Based on the above work, alternative designs for the reservoir/wellbore

interface need to be developed. Determine the number of zones to be completed and likely method of

production, ie segregated or commingled. Based on the tubing stress analysis and an evaluation of the potential

well servicing and workover techniques (see below) alternatives for thecasing/tubing interface should be evaluated.

Provide input to casing design

Data Required Formation evaluation data from previous or analogous wells. Results from well performance, near wellbore performance and tubing

stress analyses. Required completion life. Brief evaluation of potential well servicing and workover philosophies.

Questions To Be Addressed Do all the alternative structures satisfy all the requirements? Are the completions simple, safe, reliable and flexible?


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6. Tubing Movement & StressCalculations

Conceptual Design Considerations Identify whether standard stock tubulars are

suitable for the application. Can tubing movement be eliminated.

Data Required Pressures and temperatures associated with all

likely well conditions.Questions To Be Addressed

Will the selected strength of tubular satisfy allthe operating conditions with acceptable designfactors?

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7. Selection of Tubulars and Materials

Conceptual Design Considerations Identify the alternative materials that can provide the required

completion life given the well conditions. Is the desired completion life and workover frequency realistic? Evaluate the economic trade-off between corrosion resistant materials

and workover frequency.Data Required

Accurate samples and analyses of well fluids or reliable data from

analogous wells.

Questions To Be Addressed Is the data representative of conditions throughout the field? Can material of suitable strength be made in the desired corrosion

resistant material? Will conditions change with time? Have all the fluids likely to be used been considered? Does the selected material and completion life provide the lowest risk

and best economic return? Is the lead time on the selected material compatible with project timing?


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8. Selection of Completion Equipment

Conceptual Design Considerations This activity should be performed as part of the

detailed design process. However, if thecompletion requires special equipment, careshould be taken to ensure that the equipmentcan be designed, tested and built within the timeframe of the project.

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9. Well Servicing & Workover Philosophy

Conceptual Design Considerations Identify the techniques required to maintain the

well throughout its life.Data Required Likely well duty.

Likely production chemistry problems.Questions To Be Addressed Are the conceptual completion designs

compatible with the well maintenancephilosophy?

The final stage in the conceptual design is toestablish broad budget costs and approximate leadtimes.


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Completion Classification

Completions are categorised in several ways,common criteria include:

Wellbore/reservoir interfaceOpen hole or cased hole

Production methodNatural flowing or pumped production

Number of producing zonesSingle or multiple zone completion

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Requirements:

Wellbore StabilitySelectivity in production

Minimum restrictions in flow pathWell safetyFlow adjustmentWorkover for later date


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OPEN HOLE COMPLETIONS Barefoot Completion

Competent reservoirs

No Equipment. No Selective production/zonal isolation Selective zones with multilaterals now possible for barefoot

completionsSCREEN or SLOTTED LINER COMPLETION Screens or Expandable Screen Systems (ESS)

Barefoot screen completion for solids control in unconsolidatedreservoirs

Slotted Liner or Expandable Slotted Liner (ESL)

Wellbore Support and solids control in unconsolidated sandsPERFORATED COMPLETIONS Production Casing or Liner Installed to TD and cemented Perforation operation carried as part of Workover.

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Open hole Completions (Barefoot)

Conductor with open holeNo ground waterprotection

Casing string with openhole

Provides top-hole stability Liner with open hole

Cross-flow protection

Reservoir

Cap Rock

Open holeCompletion

Gravel PackCompletion


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Completion Design: Open Hole Completion

They are only feasible in reservoirswith sufficient formation strength toprevent caving or sloughing.

There exists no means of selectivelyproducing or isolating intervals withinthe reservoir or open hole section.

The production casing/liner is set andcemented in the reservoir cap rockleaving the wellbore through thereservoir open.

The final section through the pay zoneis drilled using non-damaging fluids, orin an underbalanced condition.

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Completion Design: Open Hole Completion

The tubing is set in the casing and the well put on production. In most cases the casing would be set just above the reservoir.

Advantages: Cheap and simple (especially for long intervals) Radial flow into well through 360 Good access to fractures

Disadvantages: Mud filter cake will reduce productivity unless it cleans up Production has to pass through any damaged zone No protection against wellbore collapse No zonal isolation


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Completion Design: Uncemented Liner The top of the liner is hung off in the

previous casing. In most cases the previous string of

casing would be set just above thereservoir.

Advantages: Relatively cheap - dependent on type of

liner (especially for long intervals) Slots/holes need only be opposite

reservoir Radial flow into well through 360 Good access to fractures slot sizes may afford some degree of sand

control Tubing shoe can be placed closer to

reservoir Protection against hole collapse

Disadvantages: Mud filter cake will reduce productivity

unless it fully cleans up Production has to pass through any

damaged zone No zonal isolation

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Cased Completions

Casing or linerWithout production tubing

Casing or liner withproduction tubing

Production through tubingor annulus

Casing or liner with tubingand packer

Production throughtubing, enables flowcontrol

Reservoir

Cap Rock

Cementedcasing

Cementedliner


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Completion Design: Cased & Perforated

Modern perforating charges and techniques are designed to provide aclear perforation tunnel through the damaged zone surrounding thewellbore. It provides access to undamaged formation allowing the

reservoir to be produced to its full capability.

Efficient reservoir interpretation and appraisal techniques combinedwith a high degree of depth control, enables selective perforating.

Multiple zone completions are often used in reservoirs with complexstructures and unusual production characteristics. The ability to select and control the production (or injection)

of individual zones is often the key to ensuring the mostefficient production regime for the field or reservoir.

Modern multiple completions may be complex but maintain a highdegree of flexibility and control of production.

WellCompletions


Completion Design: Cased & PerforatedAdvantages:

No need to clean up filter cake Perforations by-pass the damaged

zone (if engineered correctly) Good zonal isolation Casing programme not compromised Multiple/selective completions possible Good well integrity - if properly

cemented Protection against hole collapse

Disadvantages:

Possible skin due to lack of 360coverage

Permeability impairment due tocrushed zone and perforation debris

Expensive, especially over longintervals


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Modern Completion Configuration

Four zone selective production system Dual production strings Commingled or alternate production

controlled by sliding sleeves System contains about 28 major

downhole components

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Factors Affecting Well Performance

1. Reservoir boundaryCan be estimated

2. Reservoir propertiesCan be measured

3. CompletionCan be controlled


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The Phases of Well Completion

A logical, sequential approach is required forcompletion design and installation

Establish the objectives and the design criteria Construct the wellbore Install the completion components Initiate production Evaluate and monitor production

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Establishing Objectives

Ensure potential for optimum production (orinjection)

Provide for adequate monitoring and servicing Provide some flexibility for changing conditions,

applications or contingency measures

Contribute to efficient field/reservoir developmentand production Ensure cost efficient installation and operation


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Constructing the Wellbore

Wellbore construction objectives typicallyinclude:

Efficiently drill the formation while causing theminimum practicable near wellbore damage

Acquire wellbore survey and reservoir test dataused to identify completion design constraints

Prepare the wellbore through the zone of interestfor the completion installation phase

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Issues Effecting Wellbore Design

Issues influencing wellbore construction designand execution processes include:

Formation damagefluid invasion

Completion geometry

wellbore profile Fluid behaviour

multiphase flow Geology

fractures and heterogeneity


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Completion Design: Natural Flowing Wells

Wells completed in reservoirs which are capable of producing without assistance are typically more economicto produce.

These wells require less complex downhole componentsand equipment.long-term reliability and longevity of the downholecomponents is generally better than that of pumpedcompletions.

In many cases, wells may be flowed naturally during theinitial phases of their life, with some assistance provided byartificial lift methods as the reservoir depletes.

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Completion Design: Pumped Production Wells

All pumped or artificially lifted completions require theplacement of specialized downhole components.These features often mean the longevity or reliableworking life of a pumped completion is limited.The maintenance or periodic workover requirements willgenerally be greater than that of naturally flowing

completions.Pumped or assisted lift production methods currently inuse include the following: Rod pump Gas lift Electric submersible pump Plunger lift Jet pump


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Completion Design: Single Zone

It is relatively straightforward to produce and control the interval of interest with the minimum of specialized wellbore or surfaceequipment.Since typically one conduit or tubing string is involved, the safety,installation and production requirements can be easily satisfied.In most single zone completions, a packer (or isolation device) andtubing string is used.

This provides protection for the casing or liner strings and allowsthe use of flow control devices to control production.

The complexity of the completion is determined by the functionalrequirements and economic viability.

Several contingency features may be installed at a relativelyminor cost at the time of initial installation.

WellCompletions



Single Zone Retrievable Packer

Recovery/Function Primary recovery

Frequency of Usage Common

Operational Advantages Fully retrievable completion

no permanent components. Packer can be set with well

flanged up sliding sleeveallows circulation of kick-off orperforating fluids.

Thru-tubing perforationpossible where size permits.


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Single Zone Seal-bore Packer


Frequency of Usage Common

Operational Advantages Seal-bore packer set on electric line or

tubing. On-off connector and tubing anchor

allows tubing to be retrieved whileleaving the packer and tailpipe in place.

Tailpipe can be retrieved with tubing if required.

WellCompletions


More than One Pay Section.Commingling from Various ZonesSegregated Flow but Multiple DepletionAlternate Zone CompletionMultilateral Completion

Completion Design: Multiple Zone


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Dual

String

Single

String,SelectiveProducer

TripleCompletion

Dual Zone ,Annular Flow

Dual Zone , Cross-over Flow

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There are many possible configurations of multiple zone completion, some of which allow forselective, rather than simultaneous production.For a reservoir having multiple pay zones thereare four basic completion options:

Produce the zones sequentially through asingle tubing string.

Produce several zones simultaneously through

multiple tubing strings. Produce several zones, commingled through a

single production string. Drill and complete a separate well for each

zone of interest.Selection of the most appropriate option mustfollow a careful study of the specific conditionsencountered.The equipment installed to allow the necessaryflexibility and production options may becomplex.


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Multiple Zone Seal-bore Packer (Two Zones,One Packer)Recovery/Function

Primary recoveryFrequency of Usage

UncommonOperational Advantages

Separate or commingled flow through singleproduction tubing string.

Upper zone may be produced through theannulus.

Blast joint protects tubular integrity acrossperforated intervals.

On-off connector and tubing anchor allowstubing to be retrieved with lower intervalisolated.

Sliding sleeve or the on-off connectorfacilitates circulation of well fluids and killfluid.

Operational Disadvantages Upper zone produced through casing. Lack of casing protection.

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Multiple Zone Multiple Packers (Two Zones,Two Packers)


Frequency of Usage Uncommon

Operational Advantages Independent production through two tubing

strings. Both packers are fully retrievable. Tailpipe instrument facility in both strings. Thru-tubing perforation possible on bottom

zone. Blast joint protection

Operational Disadvantages Complex downhole design and

configuration. Multiple packer system retrieval can be

difficult to release.


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Completion Design: Multiple ZoneMultiple Zone Multiple Packers (3-Zones)



Operational Advantages Several zones produced through one

tubing string. Flow controlled by wireline retrievable

choke/check valves. By-pass sliding sleeve prevents

communication during service work. Up to five zones have been produced using

this method.

Operational Disadvantages Complex downhole design andconfiguration.

Multiple packer retrieval can be difficult torelease.

Co-mingled flow limits reservoirmanagement options.

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Completion Design: Multiple ZoneMultiple Zone Multiple Packers (4-Zones)



Operational Advantages Four zone selective production system, two at a

time, with the lower two zones alternating orcommingled through the long string.

Upper zone produced through the short stringwith remaining zone being produced througheither the short or long string.

Operational Disadvantages Complex downhole design and configuration

(System contains 28 major downholecomponents).

Multiple packer retrieval can be difficult torelease.

Flow capabilities may limit reservoirmanagement options.


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Completion Design: Liner

Liner Completion Casing SealReceptacle


Frequency of Usage Becoming more common

Operational Advantages Simplest liner-type hook-up. CSR replaces packer function. Sliding sleeve permits well fluid or

kill fluid circulation. Tailpipe retrieved with production

tubing

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Completion DesignSpecial Service Completion: Sand

Control Gravel Pack


Frequency of Usage Common (regional)

Operational Advantages

Tools and gravel placed using aservice tool and tubing work string. Gravel squeezed into perforation

tunnels. Production tubing stung-in to

production seal assembly.Operational Disadvantages

Can constrain future reservoir orwellbore treatments


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Completion Design

Special Service Completion:Inhibitor Injection (1)

Recovery/Function Primary/Secondary

Frequency of Usage Uncommon (field

requirements)Operational Advantages

Side-pocket mandrelinjection permitsprotection insideproduction tubing abovethe packer.

Injection nipple and smalldiameter injection line issuitable for shallowinjection requirements.

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Completion Design

Special Service Completion:Inhibitor Injection (2)


Frequency of Usage Uncommon (field requirements)

Operational Advantages Parallel flow tube and seal-bore

packer enables inhibitor to bepumped down short string,through the packer body andinto annulus below the packer.

All flow-wetted completioncomponents are exposed toinhibitor fluid.

Inhibitor controlled by surfaceinjection rate.


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Completion Design

Special Service Completion:Water flood


Frequency of Usage Common (offshore)

Operational Advantages Two injection zones treated

with both flow controlregulators located at surface.

Totally separate injectionsystems.Operational Disadvantages

Casing string exposed toinjection pressures

WellCompletions


Remedial Completion Scab Liner

Key Features Isolation of damaged

casing/liner orabandonment of a depletedzone

Hydraulic set packers at topand bottom of scab liner On-off connector on lower

seal-bore packer allowedinstallation with the lowerperforations isolatedthroughout the operation


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Completion Components

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Completion Components

Requirements

to hold back (control) reservoir pressure and fluids.to provide a communication between the reservoir and the wellbore.to enable flow of the desired (optimum) production rates.to isolate the reservoir fluids from the casing-tubing annulus.to enable circulation between the tubing and the annulus.to enable monitoring of the Reservoir behaviour & performance.to enable pressure testing of the completion string.to ensure tubing free movementto ensure component long lifeto provide safety devices down-hole to enable control of fluidsflow to surfaceto enable re-entry and intervention into the tubing string


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Functional Requirements

REQUIREMENT COMPONENT

Control reservoir fluids Casing, liners

Reservoir > wellcommunication

Perforations / open hole /gravelpack & screen

Optimum production Tubing size

Casing tubing isolation Packer & sealsTubing hanger seals

Tbg-ann comm.

Chemical injection

SSD /

SPM & injection valveInstallation of plugs andgauges

Landing nipples &locking mandrels

Artificial lift Gas lift mandrels,downhole pump

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REQUIREMENT COMPONENT

Tubing string movement Seal assembly, PBR,expansion joint, tbganchor

Well killin Kill wing valve, annulusconnection & tbg/anncomm

Safet SSV, SSC-SSSV,SC-SSSV, SC-ASV

Tubing long life Blast joints, flowcouplings

Tubing support Tubing hangerFlow control chokeWell entry x-mas tree with swab

valve


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Provide Reservoir to Wellbore connection


PERFORATIONS

CASING

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to enable optimum flow rates ( = Tubing)


PERFORATIONS

TUBING


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to protect the Casing from reservoir fluids bycreating Casing-Tubing annulus (= Packer)


PERFORATIONS

PACKER

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to ensure safe-guard down-hole againstuncontrolled well flow. (= SSSV & ASV)


PERFORATIONS

1/4 Hydraulic Control line

Landing Nipple for SC-SSSV

Flow Couplings (FC)


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to enhance Tubing long-life as well as enablepressure-testing of conduit ( = Blast Joints, FlowCouplings and Landing Nipples)


PERFORATIONS - 1

PERFORATIONS - 2

Blast -JointLanding Nipple (LN)

WellCompletions


to facilitate well-killing through enablingcirculation between Tubing - Annulus (= SSD andwellhead piping manifold)


PERFORATIONS - 1

PERFORATIONS - 2

Landing Nipple (LN)

Sliding Sleeve (SSD)


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to enable routine well re-entry and routine down-hole operations ( = Xmas Tree)


PERFORATIONS - 1

PERFORATIONS - 2

Landing Nipple (LN)

Sliding Sleeve (SSD)

} Xmas Tree

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Tubing

Tubing is not just another iece of pipe"!

Its a special equipment manufactured tohigh standards in order to, withstand high stresses, pressures and temperatures often in a corrosiveenvironment for long periods.


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International Standards relevant to Tubular Goods

API Committee 5 - Tubular Goods Specification andPublications

The API Committee 5 on Standardisation of TubularsGoods publishes and continually updates a series of

Specifications, Standards, Bulletins and Recommendedpractices covering the manufacture, performance and

handling of tubular goods.

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API Recommended Practices & Recommendations

Specification for Casing & Tubing API SPEC 5CT (Metric Units)

Specification for Casing & Tubing API SPEC 5CT (US Customary Units)

Recommended Practice for Case and Use of Casing

and Tubing API RP 5C1

Bulletin on performance Properties of Casing, Tubing& Drill Pipe

API RP 5C2Bulletin on Formulas and Calculations for casing,Tubing, Drill Pipe, and Line Pipe Properties

API RP 5C3


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International Standards relevant to Tubular Goods

International Standards Organisation (ISO)

ISO is described as the specialized international agency forstandardisation. Members are from the national standard

organisation of more than 91 countries. ISO is responsible forall fields of international standardisation except electrical and

electronic.ISO Technical Committee 67 (ISO/TC 67) Oil Industry matters

Issues standards on material, equipment and offshore structuresused in drilling, production, refining and the transport by

pipelines of petroleum and natural gas.

WellCompletions


KEY WORDS

OD = SIZEGRADE, YIELD / TENSIONSTRENGTHWEIGHT lbs/ft > WALLTHICKNESSTENSIONCOMPRESSIONCOLLAPSEBURST


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Tubing Specification

Completion selection process based heavily ondimensional data, including: Length (depth) Inside and outside diameter (ID/OD) Well path deviation Upsets and profiles in wellbore tubulars Connection or tool joint type and size

WellCompletions


Tubing Specification

Tubing strings specified by the following: Size and dimensions

ODWeight and wall thicknessCoupling OD

Material gradeMinimum yield strength

ConstructionSeamless/electric welded pipe

Tool jointNonupset/UpsetPremium thread


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Tubing Grade

Tubing grades criteria are specified by API: Standard API grades

J-55, C-75, C-95, N-80, P-105

Special gradese.g., C-75 and C-95 for H2S service

High strength gradesGrades having a yield strength above 80,000 psiMore sensitive to defects or damage

manufacturing defects handling or transport damage hydrogen embrittlement

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Which Tubing Grade?

Selection of tubing grade is based on:

Physical strength Chemical Properties (resistance to H 2S, CO 2 ,

water etc.)

Availability and standardisation at customer Cost


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Tubing Grade Examples

API identification of tubing GRADEcharacter + two digit figure

character is an indication of the type of steel (C,J, K, L, etc)

two digit figure X 1000 PSI = yield strength API L80 = Carbon Steel. Suitable for H2S

service Relatively inexpensive API P105 = high strength steel. Suitable for

deep wells, high load. Expensive

WellCompletions


Tubing Material

Material Type selection?establish the wellbore environment Sour Gas: resistance to H2S, > low hardness, stress

relieved, > J55, C75, C95. Sweet Gas: CO2, provisions for inhibition or

appropriate material selection, > L80 13 Cr


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SAMPLE OF TUBING MATERIALSTubing Material

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Tubing Selection Criteria (Forces & Stresses -1)

Tension: Loading due to own weight and retrieving

certain packers. Actual stress < 80% of tubing yield

strength

Compression: Loading when setting certain packers.


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Tubing Selection Criteria (Forces & Stresses -2)

Collapse: when annulus pressure is high and tubing is empty

design by assuming that annulus is full of liquid,while the tubing is empty and has maximumtubing head pressure at surface (i.e. CITHP)

Burst: when tubing pressure is high, and annulus is empty

WellCompletions


Tubing String Specification

Diameter Common sizes from 2-3/8,2-7/8,3 and 4 and 7 in

Construction Seamless pipe

Wrought steel tubes.Manufactured from hot working or necessary coldfinishing to produce desired shape

Electric arc weldedPipe with longitudinal seam formed by electric flashwelding or resistance welding

LengthTubulars are manufactured in lengths termed joints range 1 : 20 to 24 feet; range 2 : 28 to 32 feet; range 3 : 32 to 48 feet Pup joints or spacers are used for shorter lengths.


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Tubing String Specifications

Two standard API Connectionsavailable:

Non-Upset (NUE) is a 10 round thread. Joint strengthpipe body

Non-upset(8 round) Connection

EUEIntegral Connection

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Tubing Design


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Mechanically Applied Force

Top joint tension

(1) Tubing string weight

(2) Tubing packer forces

(3) Buoyancy

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Tubular forces-Buoyancy

F p A AB o i

where:

p = pressure at the bottom of the string, psiAo = area corresponding to the nominal pipe OD, in 2Ai= area corresponding to the nominal pipe ID, in 2

An open ended tube freely suspended in a fluid issubjected to hydrostatic pressure as shown in thefollowing figure.The result of this pressure acting on the cross-sectional area at the bottom of the string is acompressive axial force in the tubing


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Tubular forces-Crossovers

With change in cross-section there is anadditional force on the completion tubularproportional to the change in inside andoutside areas.

where A is the change in cross-section,in 2

Fx=Pi Ai Po Ao

WellCompletions


Any plug in tubing will causepressure acting on an area togenerate a force.

This force is proportional tothe pressure differentialacross the plug and crosssection area of the inside of tubing.

Fplug = Pplug Ai

Tubular forces-Plug


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ooii

io

PBAL ApAp

AAE

LL

2

wherep= the change in pressure

compared to the base case =Poissons Ratio

Tubular forces-Poissons effect

F A p A pBAL i i o o 2

WellCompletions


HEAT

Neutral (As installed)

Cooling increases tension

Heating reduces tension

Tubular forces Temperature effect

When the average temperature is decreased, eg by injecting cool fluids, thestring will shorten in length if the tubing is free to move.

If the tubing is restrained from moving, a tension force will be applied to thepacker.

When the average tubing temperature is increased, either by injecting orproducing hot fluids, it will cause the tubing to elongate if it is free to move.If the tubing is restrained from moving, a compressive force will be applied tothe packer.

L C TLTEMP T whereCT=coefficient of thermalexpansion, 1/F

T=average change intemperature, F from thebase case to the load case

L=length of tubing


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Packers

Selection & Running Guide

WellCompletions


Packer/PBR or Tubing Anchor?


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Packer Selection - Which type?

Selection of one type in preference to another fora given application should be based on :

designing for those parameters critical to thesuccessful performance of this equipment inthat completion

select the packer which most economicallysatisfies the conditions dictated by eachindividual situation.

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Packer Selection Process


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PACKER SELECTION GUIDE - Typical application

production well aspects

PERMANENT PACKER

straightand

shallow

deviatedand deep

horizontal highPress. &Temp.

multiplezones

shortlife

longlife

wire line set v v v vhydraulic set v v v v vRETRIEVABLE PACKERhydraulic set v v v v v vrotational set v v v vcompression set OPTION vtension set OPTION v

WellCompletions


Packers-Functions

to provide a sealing safety barrier at the bottom of the tubing as nearthe productive zone as practicable.

to facilitate well work over of damaged tubing without exposing theproduction zone to damaging fluids.

to provide a tubing anchor point to minimise tubing movement;

to assist in well killing operations by providing a positive safety barriernear the reservoir

to improve vertical flow conditions and prevent erratic flow and headingcycles;

to separate pay zones in the same well bore in multiple productionstring arrangement;

to pack off perforations rather than squeezing cement (bridge plugs);

to facilitate gas lift or hydraulic power fluid off the formation;

to facilitate temporary well service operations (eg, stimulations,squeezes) or well testing


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Packers-Permanent

Permanent packers run by: Wireline Tubing Coiled tubing

Permanent packers set by: Hydraulic (tubing) pressure Mechanical mechanism Electric wireline

Packing elements

Latch profile

Seal-bore extension

Bottom sub/adapter

WellCompletions


Packers-Permanent

Advantages

the packing element system is more resistant to Swab-Off during completioninstallation;

mechanical strength once set in the casing the permanent packer is stronger andis more resistant to high loading in tension or compression;

full cycle slips distributes hydraulic and mechanical loading and minimises casing

damage;

they generally have a larger ID through the packer;

they normally have a higher differential pressure capability than retrievablepackers;

Disadvantages

they can only be removed from the well bore by milling;

they are not re-usable once removed from the well bore.


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Hostile operating conditions, e.g.,differential pressure >5000 psitemperature >300FH2S > 10%

Medium or deep set applications Deviated and extended reach wells Selective single completions

setting point correlated by wireline

Dual completions with parallel flow tubes Sump packer for gravel packer operations

Permanent Packer Applications

WellCompletions


Packers-Setting the Packer

1. This type of packer is set by means of hydraulic pressure in the tubing.

2. The pressure acts on the piston, forcingthe piston along the lock ring andpushing the bottom slip over the cone.

3. circumferential slips split into segmentsas they grip the casing wall.

4. bottom slip contacts the casing wall, theload on the cone builds and the pinlocating the cones shears, allowing theelement to compress.

5. As the element compresses, the pin inthe upper cone shears, forcing the upperslip out into the casing.


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Retrievable packers preferred for applicationswhere:

Completion life is relatively short Wellbore conditions are non hostile

e.g., temperature, pressure, H2S Setting depth shallow to medium Low to moderate differential pressures Straight wellbore or moderate deviation

Multiple zones are to be produced

Packers-Retrievable

WellCompletions


Advantagesthey can be removed from the well bore intact without milling;

certain types of retrievable packer can be retrieved with the completionstring;

once removed they may be re-usable after redress (depending on theseverity of the well conditions ie, how much corrosion pitting etc).

Disadvantagesif the packer cannot be removed by normal means, milling can be longand problematic;

corrosion of the retrieving mechanism may impair retrievability;

they may not be so easy to provide compatibility with well conditions ascertain components may require high strength materials;

Packers-Retrievable


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Retrievable Packer-Applications

Retrievable packers preferred for applicationswhere:

Completion life is relatively short Wellbore conditions are non hostile

e.g., temperature, pressure, H2S Setting depth shallow to medium Low to moderate differential pressures Straight wellbore or moderate deviation

Multiple zones are to be produced

WellCompletions


Retrieving Packers-Permanent

Permanent packers are the most difficult,time consuming and costly to retrieve.

In order to retrieve a permanent packer theanchor has to backed out of the packer andthe tubing removed from the well.

A milling tool is then made to the drill stringand run into the well. If the milled packer isto be retrieved from the well then themilling tool has to be engaged and the catchsleeve un-jarred.

The rotary table and mud pumps can nowbe started and the weight slowly set downon the packer. As the milling tool cuts downover the outside of the packer- drop ontothe catch sleeve of the milling tool.

Once this happens the rotary and the mudpumps are stopped. The packer can now bepulled from the well.

Flow (circulation divider)

Mill shoe with wash pipeadapters to suit size ofpacker and seal-boreextension

Spear/packer retrieverengagesin packer bore or mill-outextension

Lower section of packerretrieved when upper slipsare removed


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Retrievable packers (depending on their design) can be retrieved in oneof three ways:

Using Retrieving Tools;

Tubing Manipulation;

Retrieving Packers-Retrievable

WellCompletions


Cement Packers

Tubing cemented behindconventional casingCement circulated in tubing-casing annulus-cementingtubing in the open hole fortubeless well.

Advantages

Isolating leaking squeezedperforations & casingfailures

Avoid setting liner duringdeepening operations

Minimizing wirelinecompletion equipment formultiple wells


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Swell Packers

Makes use of the thermodynamicabsorption process. It is seenthat most solids, liquids andgases have what is known as asolubility parameterPolymer & hydrocarbons willshow strong affinity to eachother and cause the polymer toswell.

AdvantagesThere is no swelling in water orbrine and as a result they can besafely deployed in mature fieldswhere water cut is very

It is self repairing and robust inconstructionIt saves on the logistics point of view in terms of rig time and caneasily be deployed/set downhole.



Oil and Gas Well Completions

Tubing head and X-mass tree


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Tubing head and X-mass tree

Tubing head Surface equipment from which the tubing is

suspended

Xmas tree or valve array Used to control well during production Mounted above wellhead Typically sourced from same manufacturer

API Spec. 6A: Specification for Wellhead Equipment

WellCompletions


Well Components at Surface

Xmas tree

Wellhead


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TUBING HEAD & X-MAS TREETubing head and X-mass tree

WellCompletions


Tubing head functions

Primary functions of tubing head

Suspend tubing with hanger Provide a hydraulic seal between

tubing and annulus Provide access port(s) to annulus Provide mounting for Xmas tree


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Tubing Hanger Types

Threaded Hanger Flangeused in low pressure wells (e.g. Pumping wells)

Boll Weevil Type Tubing Hanger for Bowl Type TubingHead.

Unsuitable for completions in which the tubing is tobe landed tension or latched under compression

Ram Type Tubing Hangerallows free tubing manipulation to latch ortension/compress before landing

WellCompletions


Boll-Weevil Type hanger & Housing

Hanger tie-down bolt

Seal

Tubing

Annulus connection

Boll-Weevil


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Spool and Hanger

Thread for plug or check valve

WellCompletions


Hanger

Rams

Tubing tension hanger Cameron SRT


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Hangers for Dual Completion

DCBS DualTubing Hanger

WellCompletions


Tubing Hanger with Extended Neck

Hanger may also have extended neck Projects into base of X-mas tree Sealed flow path through wellhead-Xmas tree

interface


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Tubing Hanger/Xmas Tree Interface

Tubing hangerextends insidebase of Xmas

tree

WellCompletions


Compact Spool System

Disadvantage of conventional wellhead Separate spool/housing installed at each stage of

drilling BOP removed each time

Compact spool system Provides hang-off areas for two or more casing strings


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Compact Spool System

Spacer spool - could be usedfor 7 in. full string hanger ifdesired

30 in. conductor20 in. casing

13-7/8 in. casing9-5/8 in. casingProduction tubing

WellCompletions


Xmas Trees

Primary flow control system for well once in production

Features and access requirements Outflow from well - production Inflow to well - injection or killing Vertical access to tubing - wireline, etc. Access for electrical cables or hydraulic conduits

e.g. ESP or safety valve


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Kill valve or servicevalve with blank

plate during normalservice

Upper master valve(operational valve)

Lower master valve

(back-up)

Tree cap and gauge

Swab valve

Choke

Production wing valve

Flanged Xmas Tree

WellCompletions


Xmas Tree Components

Pressure gaugesallow well pressures to be monitored

Gauge flange or tree capprovides seal for top of tree

Swab valve (lubricator valve)isolate pressure, well access for intervention tools

Flow teeused to direct flow, enable thru-tubing access

Production wing valveused to isolate well for most routine operations


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Xmas Tree Components

Kill wing valveenables connection of pumping equipment

Chokecontrols rate of flow from well

Master valves (main isolation valves)Upper Master Valve (operational valve)

hydraulically controlled Surface Safety Valve

Lower Master Valve (back-up valve) manually operated

WellCompletions


Well cluster in shallow water


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Categories of Xmas Tree

Flanged tree Several flanged components (leak paths) Much more common than monoblock design More flexible than monoblock design takes up more space (height)

Monoblock construction tree Single block construction Fewer possible leak paths Used in high pressure/leak sensitive

locations More expensive than flanged tree

WellCompletions


Monoblock Xmas Tree

Comprises inline or "Y" shaped block of singlecasting/forging

Valving arrangement

Lower Master Valve (manual) Upper Master Valve (Surface Safety Valve) Y piece or side outlet flanges

houses both production and kill wing valves Uppermost valve (manual swab valve)


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Monoblock Xmas Tree

Tree cap and gauge

Swab valve

Production wing valve

Upper MasterValve

Lower Master Valve

Kill wing valve

WellCompletions


Tree hook-up


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Multiple Completions

Cases where more than one completion string installed Each string independently suspended Must seal off tubing casing annulus

either independently or collectively Independent control of fluid flow in each string

WellCompletions


Multiple Completion Tree


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Xmas Tree Selection

Classify the Well Type Water Well ( low or medium pressure, GOR, Rate) Oil Well (low, medium or high pressure, GOR, Rate) Gas Well ( low, medium or high pressure, GOR, Rate)

This will be the basis for the design and the selection of equipment type and rating

WellCompletions


TREE-SAVER

Stroke lengthup to 5 ft

Rating15000 PSI

To protect X- mas tree againsthigh pressures during frac jobs etc.

Seal element for hanger ortubing

Connection to X-mas tree


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Wellhead Flanges and Connections

Several methods of ensuring pressure integrity of wellheads

Hydraulic seals required during well construction

At hanger/seat locationprevent communication between casing/tubingstrings

At flangesprevent release of fluids/pressure

WellCompletions


Flanges

Flange sealing Commonly accomplished using metal ring joint

gaskets Ring Joint gasket installed in circular recess in flange

face On make up, gasket is compressed"C" clamp or Grayloc connector Alternative connection Used in higher pressure applications Pair of clamps act on flange profiles


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API Flange Features

A = Nominal bore (in.)

B = Flange OD (in.)C = Face OD (in.)

D = Flange height (in.)

E = Bolt circ. diameter

F = Number of boltsG = Bolt hole diameter

H = R or RX ring number

WellCompletions


API 6B and 6BX Flanges

Closed face

BX ring

Stand-off

R or RX ring

API 6BX flangeAPI 6B flange


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Gaskets

R and RX ring joints Used with API 6B flange Pressure service rating up to 5000 PSI Energized by compressive force on make up Stand-off gives instability Oval or octagonal cross-section

WellCompletions


Gaskets

BX ring joint gasket Used with API 6BX flange Pressure service rating 5000 PSI and higher

Energized by compressive force and from pressureinside Closed face gives stability Octagonal cross-section with equalizing hole


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Seating Nipples

Slightly restricted andpolished ID

Tools locate onshoulder section andheld in place bypressure from above

Standing valves(check valves) areoften located in

seating nipplesPolished nipple

(for sealing only)Seating nipple

WellCompletions


No-Go Nipples

Typically placed asa single nipple in astring, or as thebottom nipple in aseries withselective nipples

Have restricted IDand latch profile onwhich the downholetools locate No-go nipple

(top)No-go nipple

(bottom)


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Sliding Sleeve

Sliding sleeves providean efficient, high volume,method of circulatingbetween tubing andannulus

for selectively producinga zonefluid circulation(treatment)well kill or contingency

Operated by wirelineusing a special shiftingtool

SLIDING SIDEDOOR

PORTSCLOSED

SlidingInner Sleeve

PORTSOPEN

SlidingInner Sleeve

WellCompletions


Side pocket mandrels can alsobe considered landing deviceswhich:

provide an unrestricted flowpath within the productionstringcan receive/locate a variety of control devices and

equipment Used to land/locategas lift valveschemical injection valvescirculating valvescirculating sleeves

Side Pocket Mandrels


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Three basic types of safety valve: Tubing conveyed Wireline conveyed Annular safety valve

isolates tubing and annulusOperating systems may be: Surface controlled (SCSSV)

Actuated from a control panel located on surface

Subsurface controlled (SSCSV)Actuated by the pressure differential/flow velocity

Safety Valves

WellCompletions


Safety Valves


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Locking Mandrels Although some tools have an integral latching mechanism, a lock

usually has to be attached to the device before it is run. The lock is designed so that the locking dogs fit into the locking

recesses of the landing nipple which the tool is to be run or hung from.

Collar Lock A collar lock, which can also serve as a tubing stop, has a large straight

through bore and locks in the recess of a tubing coupling. The coupling recess in the tubing string may serve as a landing location

when other landing nipples are not available.

Slip Lock Slip locks allow devices to be landed within the tubing without a collar

recess. They can be set at any depth in the tubing string.

Tubing Plugs Tubing plugs (plug chokes and blanking plugs) are flow control devices

used for isolating formation pressure as a temporary or permanentbridge plug.

Standing Valve A standing valve functions as a downhole check valve. This valve allows

flow in one direction and may be landed in a seating nipple or landingnipple

Flow Control Equipment

WellCompletions


Locking Mandrel

Slip type lock

Flow Control Equipment

Shear plugStanding valve

Sealing Cups

Locking Slips

Fishing Neck


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Development PhaseINTRODUCTION TO HYDROCARBON EXPLOITATION

WellCompletions


Flow Coupling

High-grade alloy steelmanufactured in 2 to 4 ftlengths with tubing threads atthe ends.

Installed at points in thetubing string where excessiveturbulence is expected.

above and belowcrossovers,

above and below a landingnipple, SSSV nipple, etc

Thick wall tubular with fulltubing ID

Protects against internalerosion

Tubing

Landing Nippleor other component

Flowing Coupling

Flowing Coupling

Tubing

Sonatrach's _Well Completions

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