Completion Design

CONCEPT 2 COMPLETION

One Stop for Subsurface Products & Services forCompletionSystemofOil&GasWells:-

SCSSV & Accessories

It is advisable, and in most cases mandatory, to have a secondary means of closure for all wells capable of natural flow to surface. The installation of a sub-surface safety valve (SSSV) will provide this emergency closure capability. The valve can be either remotely operated on a fail-safe principle from surface, or will be designed to close automatically when a predetermined flow condition occurs in the well. Subsurface Safety Valves designed and manufactured by C2C, provides positive subsurface control of oil and gas in production, injection and gas storage wells offshore and on land.

Packers & Accessories

In respect of potential damage that can be caused to the production casing, a method of annulus isola-tion is required in the majority of production and injection wells. This annular isolation is performed by installing a packer in the completion string that is lowered into the wellbore with an elastomeric element in the retracted position. At the prescribed depth, the element is set by mechanical or hydraulic manipu-lation, to fill the annular space between the tubing and the annulus. C2C packers fulfil the industrys goal of increased downhole efficiency and offer an economic solution to the oil industrys well completion demands and ever increasing costs.

Flow Control Equipments

In the majority of completions, a specific piece of equipment is installed to allow the opening and subse-quent closure of a circulation port between tubing and annulus in a production environment. This can be provided by installing one or more of the following devices; Sliding Side Door (SSD), Side Pocket Mandrel (SPM) or ported nipple. Often, a secondary means of physical isolation will be installed which supple-ment the downhole SSSV and also provides isolation if the well is hydraulically dead and the SSSV is to be removed. Thus, the provision of this isolation is normally provided deep within the wellbore either just above or just below the packer. The isolation can be provided by lowering a plug down the inside of the tubing string until it lands and locks into a nipple which was incorporated into the design of the comple-tion string. C2C have the capability to supply industry proven designs of flow control equipment to allow control of your well through intervention methods.

Tubulars & Accessories

A range of other functions may be necessary or considered worthwhile for incorporation into the string design as a future contingency. Some of the more prevalent are discussed below.

(a) Downhole tubing detachment - In the event of failure of the tubing string, it may be necessary to pull the completion from the well to effect replacement of completion components that are more prone to failure and require more frequent replacement. This detachment can be obtained by install-ing a removable locator device which seals with the rest of the tubing string to be left in the well during normal conditions but which can be pulled as required. In such cases a means of hydraulic isolation of the tubing below the point of detachment is required. Examples of this are a packer seal system that allows the tubing above the packer to be disconnected and retrieved, or a downhole hanger system that suspends the tubing in the well beneath the wellhead. Completion components which are more prone to failure and require frequent replacement, e.g. SSSV, will be located above such devices.(b) Tubing stresses - During the normal cycle of well operations, the tubing string can extend or contract in length due to variations in both pressure and temperature subsurface. Since the string is normally landed off in the wellhead and in contact downhole with the casing through the packer, if the amount of movement were severe, it would give rise to damage to the packer, wellhead or the tubing itself. A moving seal system could be installed which would allow expansion and/or contrac-tion of the tubing without mechanical failure or disengagement from the packer or seal bore. Various systems are available; however, they all feature a concentric sleeve approach where seals are located in the concentric annulus and one of these sleeves is stationary.(c) Ability to suspend P & T monitoring equipment - It is frequently required to monitor the bottom-hole pressure during production tests and, in such cases, the requirement will exist to be able to run and install at a specific location in the tubing a pressure or temperature gauge. This is normally accommodated by the installation of a wireline nipple as a component of the completion string. Its location is normally as deep in the well as possible.(d) Wireline Entry Guide - It will be necessary, in most wells, to conduct wireline or coiled tubing op-erations below the bottom of the tubing string, eg across the perforated interval. In such cases, whilst retrieving the wireline tool string, assistance must be given to guide the tools back into the lower end of the tail pipe of the tubing string.

GasLiftMandrels&Accessories

Under some reservoir conditions it is necessary to inject gas into the produced fluids to lighten the hy-drostatic head and maintain production at economic levels. Gas Lift Mandrel has long been recognized as a versatile and efficient method of artificial lift. Another example is when produced fluids contain corrosive components such as CO2, or have high pour points with attendant flowing pressure loss prob-lems. In such cases, it may be necessary to introduce specific chemicals into the flow string at a location deep within the well to provide maximum benefit and counteract the impact of these characteristics. C2C provides complete gas lift systems and chemical injection systems tailored to specific requirements.

Service Tools

C2C manufactures, sells and services a complete line of wireline service tools for generalized and special-ized wireline well service.

XMAS TREE

WELLHEAD

S.S.S.V

SIDEPOCKETMANDREL(S)

SLIDINGSIDEDOOR

SEALASSEMBLY

PACKER

NIPPLE

PERFORATEDJOINT

NIPPLE

WIRELINEENTRYGUIDE

Flow Control&Isolation

Tubing & CasingSuspension

SafetyIsolationDownhole

CirculationorFluidInjection

Circulation

Accomodate Tubing Stress

AnnularIsolation

TubingIsolation

AlternativeEntryforFlow

LandingGuages

WirelineEntry

COMPONENT FUNCTIONALITY

CONCEPT 2 COMPLETION PTE LTD - TEL: +65 6546 5700 - FAX: +65 6546 5949 - [email protected] - WWW.C2C.COM.SG


1 COMPLETIONDESIGN

1.1 Introduction ...................................................................................................................................................

1.2 Design Consideration ......................................................................................................................................

1.2.1 Drilling Phase ....................................................................................................................................

1.2.2 Completion Phase ............................................................................................................................

1.2.3 Completion Design Requirements Form ...........................................................................................

1.3 Completion at the Reservior ...........................................................................................................................

1.3.1 Open Hole (Barefoot) Completion ....................................................................................................

1.3.2 Uncemented Liner Completions .......................................................................................................

1.3.3 Cased and Cemented Completions ...................................................................................................

1.4 Functional Requirements of a Completion String ...........................................................................................

1.5 Completion Components Descriptions ...........................................................................................................

1.5.1 Re-Entry Guide .................................................................................................................................

1.5.2 Landing Nipple ..................................................................................................................................

1.5.3 Tubing Protection Joint .....................................................................................................................

1.5.4 Perforated Joint ................................................................................................................................

1.5.5 Sliding Side Door ...............................................................................................................................

1.5.6 Flow Couplings .................................................................................................................................

1.5.7 Side Pocket Mandrels .......................................................................................................................

1.5.8 Subsurface Safety Valves ..................................................................................................................

1.5.9 Production Packers ...........................................................................................................................

1.5.10 Seal Assemblies ................................................................................................................................

1.5.11 Expansion Joints ...............................................................................................................................

1.5.12 Tubing ...............................................................................................................................................

1.6 Dual Completion .............................................................................................................................................

CONTENTS

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Figure 1 - North Sea Casing Profile Example ................................................................................................................................

Figure 2 - Methods of Completing at the Producing Zone ...........................................................................................................

Figure 3 - Completion Design Example 1 .....................................................................................................................................

Figure 4 - Completion Design Example 2 .....................................................................................................................................

Figure 5 - Re-Entry Guides ...........................................................................................................................................................

Figure 6 - Landing Nipples ............................................................................................................................................................

Figure 7 - Perforated Joint ............................................................................................................................................................

Figure 8 - Sliding Side Door (SSD) .................................................................................................................................................

Figure 9 - Side Pocket Mandrel ....................................................................................................................................................

Figure 10 - Typical Surface Controlled Wireline Retrievable Safety Valve (WRSV) ........................................................................

Figure 11 - Typical Surface Controlled Tubing Retrievable Safety Valve (TRSV) .............................................................................

Figure 12 - Example of a Retrievable Packer .................................................................................................................................

Figure 13 - Example of a Permanent Packer .................................................................................................................................

Figure 14 - Example of a HydroSet Permanent Packer .................................................................................................................

Figure 15 - Seal Assemblies ..........................................................................................................................................................

Figure 16 - PBR and TSR Schematics .............................................................................................................................................

Figure 17 - Expansion Joint ...........................................................................................................................................................

Figure 18 - API Type Connection ..................................................................................................................................................

Figure 19 - An Example of a Premium Connection ........................................................................................................................

LIST OF FIGURES

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Table 1 - Completion Equipment and Well Data Questionaire ...................................................................................................

Table 2 - Bottomhole Completion Techniques ...........................................................................................................................

Table 3 - Completion Selection for Completion Example 1 .........................................................................................................

Table 4 - Completion Selection for Completion Example 2 .........................................................................................................

Table 5 - Yield Value for Various API Tubing Grade ......................................................................................................................

LIST OF TABLES

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1 COMPLETION DESIGN 1.1 INTRODUCTION

In simple terms, the term well completion refers to the methods by which a newly drilled 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

1.2.1 Drilling Phase

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.

Figure 1 shows an example of a typical drilling and casing schedule the main features are as follows:

1) The installation of a 30 inches 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) of pile driven (offshore).

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2) The installation of 20 inches 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 133/8 inches 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 usually cemented to a few hundred feet above the casing shoe of the surface casing string.

4) The installation of 95/8 inches 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:

Support for each casing string Support for the BOP equipment for the next section of hole to be drilled Sealing off the various annuli from pressure control purposes Support for the completion string Support for the Xmas Tree 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.

1.2.2 Completion Phase

Oil and gas completion companies are often consulted to assist with well completion designs or the development of detailed equipment specifications. To accomplish this, three major issues must be considered:

Form, Fit and Function of the tools Metallurgy Elastomeric Materials and seal Design

1.2.2.1 Form, Fit and Function

Every completion has its own particular objectives that must be satisfied. Additionally, there are well maintenance considerations. These functional objectives need to be clearly identified. A sketch (well schematic) is particularly helpful in understanding the total completion. Dimensional constraints such as casing size and weight, tubing size and weight, etc are obvious requirements and are included on the form on the following page. Even if completion components will not be made up in a tapered tubing section or set in casing above a liner, this information is critical as it can effect tubing movement calculations and thus influence completion designs.

1.2.2.2 Metallurgy

Many factors must be considered in selecting metals for completion accessories. These include mechanical properties/strength and corrosive degradation, or stress cracking resistance. Material availability, machinablilty and weldability are also of particular interest to manufacturing

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companies. At times it can be difficult or uneconomical to use identical materials for tubing and accessories. For example, materials deriving strength from cold work may not be available in the large diameters required for some accessories. In these circumstances, or when making material recommendations, the following environmental data should be supplied:

Oil or Gas Well Bottomhole pressure and temperature % H2S % CO2 Salt, Chloride or other mineral concentrations in water Formation or Condensed Water In situ pH or acidity of water Water cut or water production rate If injector, are injected fluids below 50ppb oxygen Tubing grade Inhibition program and chemical used Expected time between work-overs Corrosion history

1.2.2.3 Elastomeric Materials and Seal Design

Decisions relating to the elastomeric or plastic materials are based on information similar to metals. Maximum temperatures and minimum temperatures expected at sealing areas are critical. Chemicals can also affect seal selection. Inhibition programs and anticipated acid treatment programs should be considered during the completion design stage. Completion fluids can adversely affect seal materials. Use of zinc or calcium bromides, potassium or calcium chlorides, sodium hydroxide, biocides etc., should be noted.

Once temperatures, pressures, fluids and chemical data are known, then the seal applications inherent in the tool designs must also be considered. Molded seals or elements, V-packings, and O-rings are the most common seal types. The static or dynamic, active or non-active status of the seal application is an additional consideration.

1.2.3 Completion Design Requirements Form The following page provides a form indicating the completion requirements and well data needed. Either imperial or metric units may be used but should be clearly identified. A generic completion sketch, when possible, should also be provided. This is a sample form to obtain the information normally needed to design a total completion package. A more complete guide is available upon request. Any special requirements for elastomers, metallurgy, threads etc should be indicated, as should special processing i.e., certifications, inspections etc.

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Figure 1 Casing Profile Example

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COMPANYNAME : FIELD/WELLNAME :ADDRESS : FIELDLOCATION :

Country State Country OFFSHORE LAND INLANDWATERWELLTYPE: Oil Gas Storage Others

YOURNAME : WaterInjection

GasInjection

SteamInjection

COUNTRYOFFINALEQUIPMENTDESTINATION:

NUMBERCOPIESOFBIDREQUIRED: NUMBEROFWELLS:

SCHEDULEDDATEOFFIRSTCOMPLETION: PARTIALSHIPMENTSACCEPTANCE: Yes NoPLEASEATTACHDIAGRAMSHOWINGANTICIPATEDWELLCOMPLETIONSCHEME

SIZE WEIGHT GRADE THREAD DEPTHCASING LINER

TUBING

WELLHEAD Manufacturer/Model: Size/Rating/Trim: TypeofConnector:Top Wing

PRESSUREDATABOTTOMHOLE SURFACE TREATING TESTING

Static: Static: Surface: Surface:

Flowing: Flowing:

TEMPERATUREDATA

STATICBOTTOMHOLE AMBIENTSURFACE FLOWINGSURFACE

PRODUCTIONDATA

COMPLETIONFLUID PERFORATIONDEPTHDensity: Type: TrueVertical: Measured:

%H2S: %CO2: OilGravity: SpecificGravityofGas:

S.G.Water: GLR: GOR:

DesiredProdRate: Sand/Paraffinetc(ApproxVolumeor%):

CORROSIONDATA

Anticipated: InhibitorTreatment: SpecificType:Yes No Animo Yes NoInjectionMethod: Continuous Batch OtherSpecialHeatTreat,MaterialorCoatingstobeapplied:

ADDITIONALINFORMATIONFORGASLIFT

STATICFLOW GASPRESSURE FLOWLINE OTHERLevel: K.O.Available: Size: LiftGasGravity:

Gradient: MaxOperating: Length: SeparatorPressure:

ADDITIONALINFORMATIONFORSAFETY

VALVE

ControlledFrom: IfSubsurfaceControlled: SettingDepth:Surface Subsurface DifferentialPressureOperated

AmbientPressureOperated

Table 1 Completion Equipment and Well data Questionaire

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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).

1.3.1 Open Hole (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 (Refer to Figure a). This type of completion is ideal where the reservoir rock is of the appropriate mechanical strength i.e. is consolidated and will 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 cost. Openhole completions offer no scope for isolating individual zones for production, stimulation or remedial work. However, this bottom hole 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 openhole completion types are indicated in Table 2.

1.3.2 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 into it (Refer to Figure b). The slots or wire wrapped pipe prevents sand from entering the well bore. 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 bottom hole completion type has all the disadvantages of the open hole completion with the added cost of the liner and liner hanger thrown in. Uncemented liner applications are 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 2.

1.3.3 Cased and Cemented Completions This is the most common type of bottom hole completion methods especially in the more prolific offshore wells. 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 (Refer to Figure C). 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 2.

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Bottom Hole Completion Technique

Advantages Disadvantages

Open Hole

No perforating, no production casing, no cementing expense

Minimum rig time Full diameter hole in the pay zone

improves productivity No critical log interpretation is

required.

Liable to sand out No selectivity for production or

stimulation Ability to isolate is limited to the

lower part of the hole.

Slotted Liner

No perforating or cementing expense for the production casing

Assists in preventing sand production

No critical log interpretation is required.

No selectivity for production or stimulation

Cost of slotted liner or pre-packed screen

Difficult to isolate zones for production control

Slightly longer completion time than for open hole completion.

Cased and Cemented

Introduces flexibility allowing isolation of zones and selection of zones for production or injection.

Requires critical log interpretation to specify actual perforation zone

Cost of casing/liner and cementation

Cost of rig time for longer completion period.

Table 1 - Bottom Hole Completion Techniques - Advantages and Disadvantages

Figure 2 Methods of Completing At the Producing Zone

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1.4 FUNCTIONAL REQUIREMENTS OF A COMPLETION STRING The 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 3. The objective is to design a completion string for this well with 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 down hole 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 3. 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.

Figure 3 Completion Design Example 1

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The completion design of Figure 3 also addresses the other functional requirements of: Suspension 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 3.

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 assembly

Extend 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 2 - Component Selection for Completion Example 1

NOTE: Some components have dual functions. NOTE: This completion design utilises a permanent packer and tailpipe that will be installed

by wireline techniques or hydraulically via a work string, prior to running the completion string. (Packer systems will be discussed later.)

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Completion Design Example 2 Figure 4 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 4.

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 Barrier installation Point

Landing nipple Pressure testing of tubing string Barrier installation point

Retrievable packer Protect the casing from well fluids Ensure retrievability of all components

Landing nipple Pressure testing of tubing string

Barrier installation Point 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 Catches fallen well intervention tools

Re-entry guide Allows unrestricted re-entry of well intervention tools into the tubing

Table 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 systems will 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 4 Completion Design Example 2

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1.5 COMPLETION COMPONENTS DESCRIPTIONS

The following completion component descriptions follow the completion design of Figure 3 and Figure 4. These completions incorporate 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.

1.5.1 Re-entry Guide A Re-Entry Guide generally takes one of two forms:

Bell guide Mule shoe.

The bell guide (Refer to Figure 5) has a 45 lead in taper to allow easy re-entry into the tubing of well intervention tool strings (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 (Refer to Mule Shoe Guide Figure 5) 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 guide the tubing into the liner.

Mule Shoe Guide Ball Guide

Figure 5 Re-Entry Guides

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1.5.2 Landing Nipple A landing nipple (Refer to Figure 6) is a short tubular device with an internally machined profile which can accommodate and secure a locking device (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 bottom hole pressure and temperature gauges.

A No-Go landing nipple (Refer to Figure 6) has a small shoulder located within the internal bore of the nipple. The primary reason for a No-Go shoulder is to locate the correct lock mandrel. A secondary function would be to prevent 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 commonly use landing nipples for depth references.

Figure 6 Landing Nipples & Lock Mandrels

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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.

1.5.3 Tubing Protection Joint This is a joint of tubing included for the specific purpose of protecting bottomhole pressure and temperature gauges from excessive vibration while installed in the landing nipple directly above.

1.5.4 Perforated Joint A perforated joint (Refer to Figure 7) may be incorporated in the completion string for the purpose of providing bypass flow if bottom hole 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 7 Perforated Joint

1.5.5 Sliding Side Door

A sliding side door (SSD) or sliding sleeve (Refer to Figure 8) 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; As an alternative flow path should a plug become stuck in a wireline nipple.

NOTE: As with all 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 is used (e.g. side pocket mandrel, tubing perforating).

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1.5.6 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 internal erosion criteria obtained from fluid velocity and particulate content analysis.

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.

1.5.7 Side Pocket Mandrels A side pocket mandrel (SPM) (Refer to Figure 9) 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:

1.5.7.1 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 the tubing and the upper SPMs are those used to unload the annulus of completion fluid down to the point of gas injection.

1.5.7.2 Chemical injection valves These allow injection of chemicals (e.g. corrosion inhibitors)

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

1.5.7.3 Circulation valves These are used to circulate fluids from the annulus to the

tubing without damaging the pocket. 1.5.7.4 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.

1.5.7.5 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.

1.5.7.6 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 seal replacement.

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Figure 9 Side Pocket Mandrel (SPM)

Figure 8 Sliding Side Door (SSD)

Polished Seal Area

Lock Recess (Open Position)

Lock Recess (Closed Position)

Three Stage Collet Lock

Equalising Port

Seal Assembly

Inner Sleeve

Pack-Off Seal Area

Landing Nipple Profile

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1.5.8 Subsurface Safety Valves

The purpose of a safety valve 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. Many oil operating companies have differing philosophies on the inclusion of safety valve in their completion. For example, in an offshore well, at least one safety valve is placed in every well at a depth which varies from 200 ft to 2,000 ft below the seabed. The depth at which a safety 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 and minimum setting depths)

NOTE: It is generally recommended that a safety valve is installed in a well that is capable of

sustaining natural flow.

In most oil operating areas the installation of a safety valve is governed by law. There are numerous types of safety valves in field operation, but in our case we are going to concentrate on only four types. Two subsurface controlled, and two surface controlled valves.

1.5.8.1 Types of Sub-surface Controlled Safety Valve

Ambient pressure operated Differential pressure operated.

NOTE: Both examples are known as Direct Acting valves and are classed as pressure

activated devices.

Ambient Pressure Activated (Storm Choke)

This type of valve is normally closed. The well pressure (hydrostatic or flowing) keeps the valve open. If the well starts to produce at an increase flow rate, the tubing pressure drops and the valve is closed by a spring and pre-charged nitrogen chamber. The valve must be set for the given well conditions and its location in the well. Once closed, the valve can be re-opened by applying tubing pressure above it, or by means of an equalising valve, run on wireline. The valve is popular in many land operations due to its minimal price compared to a surface controlled system. They are often used as back-ups for tubing, or wireline retrievable safety valves. They can be of the rotating ball, flapper or ball and seat type. The valve can be installed and retrieved under pressure by wireline methods.

Pressure Differential Activated (Velocity Valve or Storm Choke)

This type of valve is normally open. The valve operates on a spring loaded flow bean pressure differential principle. The spring holds the valve off-seat until the well flow reaches a predetermined rate. When the pressure differential across the bean exceeds the spring tension the valve is designed to close off the well flow. Once closed, the valve can be re-opened by applying tubing pressure above it, or by means of an equalising valve run on wireline. The valve can be installed and retrieved under pressure by wireline methods.

1.5.8.2 Surface Controlled Safety Valves

Wireline Retrievable Valve (WRSV) Tubing Retrievable. (TRSV)

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Wireline Retrievable Valve

This valve is actuated open usually by application of hydraulic pressure from surface via a control line run 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 surface/subsurface safety system. Each pilot can be set to monitor various flowing and shut-in parameters, and will close the valve to close if a potentially dangerous situation occurs.

The valve is run on wireline (slickline) and is installed in a special safety valve landing nipple (SVLN). This SVLN is made up as part of the completion string. A control line which is attached to the completion string by special clamp 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 causes a restriction to flow. The pressure or temperature drop across the valve may cause hydrate or paraffin plugging if an appropriate condition exists.

Tubing Retrievable Valve (TRSV)

A tubing retrievable safety valve (TRSV) run as part of the tubing string is classified as a TRSV. To open the valve, hydraulic pressure is applied to the valve through a control line attached to the completion string by means of a special clamp. The main advantage of a TRSV is a full bore unrestricted flow through the flapper or ball valve. The full-bore unrestricted flow may reduce or eliminate hydrate or paraffin accumulation. 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 and the provision of a surface controlled wireline retrievable insert valve which can be installed in the body of the TRSV. Most valves are installed with a flapper operating mechanism. Examples of the two devices can be found in Figure 10 and Figure 11.

Figure 10 Typical Surface Controlled

Wireline Retrievable Safety Valve (WRSV)

Figure 11 Typical Surface

Controlled Tubing Retrievable Safety Valve

(TRSV)

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1.5.9 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, 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.

1.5.9.1 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 12.

1.5.9.2 Permanent Production Packers

These may be run in a variety of ways and become an integral part of the casing once set. A permanent packer may be run as follows:

On electric 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 pipe pressure.

Figure 13 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.

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 14 shows an example of this type of permanent (hydro-set) packer.

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Figure 12 Example of a

Retrievable Packer

Figure 13 Example of a

Permanent Packer

Figure 14 Example of Hydro-Set

Permanent Packer

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1.5.9.3 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.

NOTE: In general, permanent production packers can withstand greater differential pressures than the equivalent retrievable packer, although recent developments in packer technologies have narrowed the gap between the two types.

1.5.10 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 15 illustrates the assemblies available for connecting the tubing to the packer and maintaining a seal.

1.5.10.1 Locator Seal Assembly

Locator Seal Assemblies incorporates a top No-Go shoulder, which 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 No-Go shoulder.

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 or contraction. A completion string may also be spaced out appropriately if overall cooling of the tubing string will occur e.g. in a water injection well.

1.5.10.2 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.

Figure 15 Seal Assemblies

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1.5.10.3 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 (as shown in Figure 16) 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.

1.5.10.4 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 (as shown in Figure 16) 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 manufactured with circulation ports on the inner mandrel.

Figure 15 Seal Assemblies

Figure 16 - PBR and TSR Schematics

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1.5.11 Expansion Joints

These are telescoping devices (Refer to Figure 17) 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 17 Expansion Joint

1.5.12 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 (Production) 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.

Figure 18 API Type Connection

API External Upset API Non Upset

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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 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 5 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 5 - Yield Values For Various API Tubing Grades

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 the well 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 breakout 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 connections, recess free bores, and special clearance. An example of a premium thread is shown in Figure 19.

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Figure 19 An Example of a Premium Connection

1.6 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 dual tubing hanger systems and dual Xmas Trees 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.

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