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Institute of Petroleum Engineering This manual and its content is copyright of Heriot Watt University © 2013 Any redistribution or reproduction of part or all of the contents in any form is prohibited. All rights reserved. You may not, except with our express written permission, distribute or commercially exploit the content. Nor may you reproduce, store in a retrieval system or transmit in any form or by any means, electronic, mechanical, photocopying, recording or otherwise without the prior permission of the Copyright owner. Production Technology

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Page 1: Chap 1 and 2.pdf

Institute of Petroleum Engineering

This manual and its content is copyright of Heriot Watt University © 2013

Any redistribution or reproduction of part or all of the contents in any form is prohibited.

All rights reserved. You may not, except with our express written permission, distribute or commercially exploit the content. Nor may you reproduce, store in a retrieval system or transmit in any form or by any means, electronic, mechanical, photocopying, recording or otherwise without the prior permission of the Copyright owner.

Production Technology

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1 CONVENTIONAL COMPLETIONS

2 ADVANCED WELLS AND COMPLETIONS

3 RESERVOIR AND TUBING PERFORMANCE

4 SELECTION AND DESIGN OF ARTIFICIAL LIFT

5 GAS LIFT

6 PERFORATING

7 FORMATION DAMAGE

8 MATRIX ACIDISING

9 HYDRAULIC FRACTURING

10 UNSTABLE FORMATIONS AND SAND CONTROL

11 FIELD DEVELOPMENT CONCEPTS AND FLUID PROCESSING

12 RESERVOIR AND TUBING PERFORMANCE TUTORIAL 13 EXAMINATION AND MODEL SOLUTIONS

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Production Technology Petroleum Engineering

Conventional Completions O N E

Initiate Design

Conceptual Design

Final Design(s)

Bottom HoleCompletionTechnique

CasingString

Design

DetailedCompletion

String Design

WellPerformanceOptimisation

Selection ofProduction

Conduit

CompletionString

Facilities

WellProductivity

Objective of this chapter

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O EN T N T SC

INTRODUCTION

1 BOTTOM HOLE COMPLETION TECHNIQUES 1.1 Open Hole Completion 1.2 Screen or Pre-slotted Liner Completions 1.3 Cemented and Perforated Casing / Liner

2 SELECTION OF FLOW CONDUIT BETWEEN RESERVOIR AND SURFACE 2.1 Tubingless Casing Flow 2.2 Casing and Tubing Flow 2.3 Tubing Flow Without Annulus Isolation 2.4 Tubing Flow With Annular Isolation

3 COMPLETION STRING FACILITIES 3.1 Basic Completion String Functions and Facilities 3.2 Additional Completion String Functions 3.3 Composite Completion String

4 COMPLETION STRING COMPONENTS 4.1 Wellhead / Xmas Tree 4.2 Production Tubing 4.2.1 Tubing Diameter 4.2.2 Tensile Strength 4.2.3 Internal Pressure 4.2.4 External Pressure 4.2.5 Corrosion 4.2.6 Coupling Types� ������ ���� �������������� 4.3 Annular Pressure Seal 4.3.1 Ease of Retrieval 4.3.2 Setting Mechanism 4.3.3 Ability to Withstand Differential Pressure 4.3.4 Number of Packer Bores 4.4 Seal Between Tubing and Packer 4.5 Sub-Surface Safety Valves 4.6 Side Pocket Mandrel (SPM) 4.7 Sliding Side Door (SSD) 4.8 Landing Nipples 4.9 Perforated Flow Tube 4.10 Flow Coupling

5 MULTIPLE COMPLETIONS� ���� ������������ 5.2 Multiple Zone Depletion Concepts 5.2.1 Co-mingled Flow 5.2.2 Segregated - Multiple Zone Depletion 5.2.3 Alternate Zone Well Completion Stratege 5.2.4 Selection of Development Strategy� ���� ����������������������������� ����! 5.3.1 Dual Zone Completion 5.3.2 Completions for Three or More Zones 5.4 Multiple Completion Equipment 5.4.1 Tubing Hanger Systems 5.4.2 Multiple Tubing Packer Systems 5.4.3 Blast Joint

6. WIRELINE SERVICING OF COMPLETION ACCESSORIES 6.1 The Wire 6.2 Surface Monitoring Equipment

7 TUTORIALS 7.1 Well Completion Designs 7.2 Completion Tutorials: Spot The Errors

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LEARNING OBJECTIVES:

Having worked through this chapter the Student will be able to:

"� #$ �� ������ ���$���!�$����!� �����%��������%������������������!� �&�make a recommendation based on well integrity and reservoir management requirements.

"� '!!!!� �&������&������� �������� ����!�����&����&�*�����!��������%�production and injection applications.

"� +&����,;�$ �� �� �&������&�������� �� � �����,�������������!�����!�for a variety of situations.

"� �!���� �%� �����!� �&� ����� ��� ����� �������!� ���� � <��� ���������equipment components.

"� +&����,������ ��������*������������!%� �� ��&!���!� �&������� ��� �����mechanisms/operational problems with equipment.

"� '!!!!�*���! ��,��=������!� �&� � ������!���%�������*���&!����

"�� �!�����%�������!;� �&��%�����%������!�� ���!> &$ �� �!;��������&�����multiple reservoir units.

"�� ?����!���� �����������!%� ���������!��������&������*�;��%���������zones simultaneously.

"�� �����%�=��������=������!�������!����� @�!;��������% ���!� �&�K� !�trees for multiple completion strings.

"� �!�����%�=��������!&�����*������!�$������������������������!�

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Institute of Petroleum Engineering, Heriot-Watt University 3

INTRODUCTION

The development of a hydrocarbon reservoir requires a large number of wells to be drilled and completed to allow the structure to be depleted. The drilling and completion ��� ����!� ����� ������%����������$� �����,�����%�*��������������!�!���&�objectives. The design and completion of both production and injection wells must:

"� ?��$�&������������&�����>��<����������� ��

"� #�!���! ��,�Y���%���!!��� �&�[��&���� �����!\�

"� � ]���!��%��������,� �&���� �����,�����%�����������$���%��$�! �&�����of the completed well

"� ������!��%���� ���!�!���������$��������[��&����&�&������<�&;�����������!��%���� ���!�!��������� ����������;�� ��� ���������&������ �&���&� ��� !��!

"�� ^�%������� ������������! �&����&������&��&����������%�� ����� ����!�$����characteristics or development constraints.

�%����������&!������$��$!������������ ��&�!���� � !;��% ������%�����$�&�a conceptual design (Figure 1):

"� ���� ���������%��������%�������������%��=�

"� �����������%����&��������&���

"� '!!!!����������������!������� �����!

"� #$ �� ��������*��������� ��>����&���$��,_��<��$��,

This conceptual design process is initiated on the basis of data from exploration wells. Considerable uncertainty may exist as to the validity and accuracy of that data. Thus a number of alternative designs for well completions will normally be selected and contingency designs may be developed. The detailed design evaluation and costing of the selected completion concept will then be undertaken to:

"� ����,� ���=������� �&�� ��� �!

"� ^�����!���������������� �

"� ^�����!�*��������� �

It is essential that an interactive approach is adopted at both the conceptual and detailed &!����!� �!���%�!��!��!! �,�&������%�&�$�!��,����&!����& � ;������!�$������@� �&�[��&��������!;����&��������!�� ���!;���� �&��%�� ������&�!�����!�*%�%�% $������!�������%�&�!����� @�������!!;�����&�������������!;��!�$���������!�and production technologists.

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Initiate Design

Conceptual Design

Final Design(s)

Bottom HoleCompletionTechnique

CasingString

Design

DetailedCompletion

String Design

WellPerformanceOptimisation

Selection ofProduction

Conduit

CompletionString

Facilities

WellProductivity

Objective of this chapter

Figure 1 Completion design strategy.

Well Integrity is the process that sets the Standards and Policies which the completed *���!%���&� &%�������%�*���!%���&��������,�����!����&;����� �!����� �&� �&�maintained to these (company) standards and policies. These standards and policies � ,������ ��,� ���� ��;������ ,� �!����� ����&� ��&��������%�� ��������%���&� �&��%���� ������$���������

Well integrity encompasses:

"� ̀������!��������+������,{ Wellhead & X-mass tree Casing & Cement Integrity Shoe bond & window cement bond tests CBLs Casing Corrosion Logs Zonal Isolation Well bore integrity Etc.

"� ����������+������,�'!!�� �{ Wellhead & X-mass tree integrity management� � ��*��}���<*���,��������,� !!�� ��Y��*��}���� ��,�~ �$;������!;�

� ���&���� ��&� ����;�`��� ���� #���,� ���&;� �� �� ��� ������ ? @�� ��%�� � ?�� �����������$ ��;���\

Accessibility assurance (i.e. no obstruction) Annulus Management

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Institute of Petroleum Engineering, Heriot-Watt University 5

Gas Lift & Gas Injection Pump Integrity Assurance Etc.

"�� ���*�'!!�� �{ Scale Management Asphaltene Management Corrosion Management Etc.

"�� ̀��������,��� � ����

Examples of well integration failure are presented in Table 1.

FAILURE EVENT OPERATIONAL CONCERN CONSEQUENCES IF NOT REPAIRED

Tubing failure in wall leak Tubing - Well safetyor coupling Annulus communication Packer failure Annulus reservoir Well safety communication

Seal failure Annulus reservoir Well safety communication Tubing hanger leak Tubing - annulus Well safety communication Xmas tree seal leakage External leak Well safety

Wellhead leakage External or annulus Well safety leak

Circulation sleeve seal failure Annulus communication Well safety Sub Surface Safety Valve • Inability to isolate well Well safety and loss failure • Inability to land flow of flow control devices

Gas lift valve leak Tubing annulus Well control limitation communication

Gas lift valve closure Inability to lift well at No or limited valve depth production

Downhole pump failure Failure to lift well No production

Table 1 The nature and consequence of completion failure.

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1 BOTTOM HOLE COMPLETION TECHNIQUES

The three alternative approaches for the completion of the reservoir zones are:

"�� ^���%�����������

"� ?�_&����&�>���_!����&���������!������������Y�����&\ "�� � !������������*��%� ���� ����� ����� �&�!��!=��������� ����

1.1 Open Hole CompletionThe simplest approach to bottom hole completion is to leave the entire drilled reservoir section open after drilling (Figure 2). Such completions are sometimes referred to as “barefoot” completions and the technique is widely applied. Since no equipment requires to be installed there are savings in both costs and time. However this type of completion does mean that the entire interval is open to production and hence does �������$�&�!���$���������$��[��&����&��������� ��<������ +�� �!� �%���������recommended for production or injection wells where distinctive variations in layer ��� �����,�*����&������ ��,��������%�!*������,�������!���&��* ���[��&����� !���<������+���!�&�����������!�� ��* ��>� !��� @�%����%�������� �����������%�wellbore unless the entry pour is at the base of the well where isolation with a cement ������ ,���!�!!������%���!!������,����������� ����!!�[�*������� ��� @���!!���dictating multizone depletion cannot be corrected with this type of completion. This lack of zonal control for production or injection is the major limitation on the application of this technique.

OPEN HOLE

Figure 2 Open hole completion.

Open hole completions can only be applied in consolidated formations as the borehole � ,�������!� ������ �&� *&�*����� ����&������&���%�*������[�*��+��!�%�cases either total collapse of the formation or the production of sand may occur.

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Institute of Petroleum Engineering, Heriot-Watt University 7

The above characteristics of open hole completions explains why they are used in:

"� ��*��!��&$������!"� ��;���!���& �&��!�$���!���������&�&��,�&�������&��$��!��!����&�

contact between fracture and well"� � ��� ��,��� ���&��!�$���!�"� ����%������� �� �&�������� �� ��*��!�*��%�%��%�&��������!�!

1.2 Screen or Pre-slotted Liner Completions'�*��_*� ��&�!��;�!����&�!���������� ���� ��$�! �&��������!����!���!� ��&�(Figure 3) once the drilling through completed reservoir section has been completed. The screen or liner is installed to prevent sand production into the wellbore and tubing. The success of the completion in controlling sand production is dependent upon the screen or slot sizes and the sand particle sizes. The screen will only become 100% effective if it totally restrains sand production which requires that the slot size be equal ����%�!�������%�!� ��!��� ����!��}�*$�;����!�%� !!��%�!���!�� ,��=��@�,����������&� �&����&�[�*;��!���������� ���!!����*������&���$��,��

This system is also used in high angle angle wells to prevent major borehole collapse or facilitate the passage of logging tools.

PRE SLOTTED LINER( or Alternative)

Figure 3 Well completed with wire wrapped screen or slotted liner.

This technique shares the inability for zonal control of production or injection with open hole completion. It may also only effectively control sand production over a �����&�� ��������&�����!��}�*$�;�����!� �Y�� ��$�,\���*��!���%��=����!����conventional sand screens restricts the technique's application to reservoir rock that consists of relatively large and homogenous sand grains. The introduction of woven mesh screens and in particular expanding sand screens has greatly extended its range of applicability.

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1.3 Cemented and Perforated Casing/Liner�%��� ����������!������!� �����%�� ����&� !����!������*%�%�]��&!�� @����surface or a cemented liner which extends back into the shoe of the previous casing !������Y�������\���?���� �����!��!=����,����$�&!�� �%!�����[��&����[�*���>�����the wellbore and formation.

CEMENTED ANDPERFORATED

LINER OR CASING

Figure 4 Cemented and perforated production casing or liner.

The integrity and selectivity of the completion depends on an effective hydraulic seal being provided in the casing-formation annulus by the cement placed during �%����� �,�����<�����%� �!������ ���������%����� ��� &������%��[��&����� ������%��&��%� !�������!��� ;������ ���%������������������� ����!������which it was assumed to be isolated. It may be possible to regain annular isolation or close off unwanted perforations by a remedial cement squeeze operation.

This type of completion involves considerably greater costs and time than the previous options. The cost of a full length of casing from the surface to the base of the well ������!�&� ��;����*%�%���!���� &&&��%��!���������� ����;�������� �&�the additional rig time. The use of a liner helps to reduce the required length (and �!�\� ��� !�����}�*$�� �%� �����,� ��� ������� �%�&���������� ��&�$�&� �� ���!;��!�� ���%���[�*������&!�� ������&�&�[��&!� �&���������%���<��������[��&!�into zones are essential to a large number of developments. This has resulted in the cemented and perforated liner or casing being the most widely applied bottom hole completion technique.

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Institute of Petroleum Engineering, Heriot-Watt University 9

2 SELECTION OF THE FLOW CONDUIT BETWEEN THE RESERVOIR AND SURFACE

�%�� �� ����������������!�����[��&�[�*����!��� ���� ����&������*��;��������%����� �������� ����<�����*��������!�&� ����!�*%�%�� ,���[����%�%�������&��!�;�[�*�!� �����,;� �����,�����������[�*� �&��!������*���! ��,� �&��������,����the well by minimising corrosion or erosion.

The following alternatives exist for a single zone completion:

"� �������!!� !����[�*"� � !���� �&��������[�*"� �������[�*�*��%���� ���� ���!�� ����"� �������[�*�*��%� ���� ���!�� ����

These options are depicted in Figure 5

TUBINGLESSCOMPLETION

TUBING COMPLETIONWITHOUT PACKER

(with optionalannulus production)

TUBING COMPLETIONWITH ANNULUS PACKER

(a) (b) (c)

Figure 5 Alternative production conduits for a single zone.

2.1 Tubingless Casing Flow (Figure 5a)Once the well has been drilled and the bottom hole completion technique implemented Y����%����������� �&� !���\��%�*����!���&�&����[�*���&��&� *&�*�� �&�[��&�is produced up the inside of the casing. This technique is very simple and minimises �!�!��}�*$�����&�!�% $���!�&�! &$ �� �!�����!��,;��%����&������ !����� ,���!��� ��� �&� �����% ���%�[��&�!����� ��$�����!� ����*�����%������% !�!� � ����� �&�!����������;��!������������!� ���[�*� �&���� !&�[�*������!!�����!!�����%� !������%����&�&�[��&��!� �!�����&������� ��*��%��%� !���;������� ��,��!���������� !��������!���;����}

2S or CO

2� ����!���������&�&�[��&!���� !����

��!���;����! �&��!���������&�&��&�����!�����%� !�����������,�&�������%�����the above can result in potential burst of the casing at the wellhead if the well changes from oil to gas production.

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�%� ��!�� �=������� ��� � *��@�$�� �!� �% �� �%� *��� �!� %,&� ��� ��,� @���&�� �%����!� �������� �%,&� ����% &����[��&�*%�%����$�&!� ��������%�����!!���greater than reservoir pressure in this type of completion can only be accomplished by either squeezing��%�*�����������!�� @�������%����� ����;�������� ����� ��!!�the wellhead using the Volumetric Technique����=������� ���$����!����[��&!�� @�������%����� ������!���&!�� ������� �,� !!�!��� �,���!�;�! �������%��particulates will be carried in the perforation or the formation matrix. Thus killing such wells will result in a compromise between safety and subsequent productivity. In &&�����;������!��!=������ ����!;��%��=���&���<�������!!��!�*���&���� !� !�[��&!� �����<�&� �&��%�!�� ,� �!�������$�� !�������!������� ����!�������%�� ���&� ���� !���;��%�&�!��@����[��&�� ,�� ����%����%��%����%���%,&�� ����;�inhibiting the squeeze process.

�%�!�����������!�� ��,��!&�&������%!�&� *� @!���%��������!!���������;� �$ �� �������%�!� ���� %;��!�!�����!� ����&���������������!��}���%����%����!�drilled passed all the zones and individual tubing strings located opposite each zone. The entire borehole is then cemented and each tubing string perforated with orientated guns. This is not a simple multi-zone completion but its design precludes workovers if problems subsequently arise.

2.2 Casing and Tubing Flow (Figure 5b)'�� ���� ��$�����������!!� !����[�*�����%��%�,����&���$�*��!�*%�� �� �����!!�!���� �� � �����[�*��!�&!�� ��;��!������!� ��� ����&������������� �&� ���*�[�*������������%�������� �&��%�������_� !���� �����!����%�!��,��������������has the very important advantage of providing a circulation capability deep in the *���*%���!�$����[��&!� ����&�!�� &����!��� ��,� ����<�&�@����[��&�����%�required density to provide hydraulic overbalance on the reservoir. This capability ������� ��Y����_���\�@����[��&���*���%� �����!� �&��%�����������$!��%�necessity for reinjection into the reservoir. It also does not require the high pressures !!�� �&�*��%�!=������ ����!����%�!�����������!�$�,��!��������%��%�[�*�� ��*��!����$�&&������!�$��������!�$�������&!� ����!�������%�[�*�!�� ��

2.3 Tubing Flow Without Annulus Isolation (Figure 5b)+��!��� ����!�*%�� ���� ��[�*���� � !���_!����������������!���!����]!!�$��% !�!���� ��*��%���!=������� !&�[�*������!!�����!!� �&�[�*���!� �����,;�consideration should be given to closing the annulus at surface and preventing annular [�*���+���%�[�*�����������%�����!!����!� ��������*��%������������;�� !;�*�������� ����* �&!���&�����, �,����!� !����[�*!�������%����� ���������%��������tailpipe. Some gas will accumulate in the annulus resulting in an increased casing head ��!!��� ��!��� ���� !�����&��������%� �����!�*������������������ !�������,����!�the annulus when it off-loads as a gas slug into the base of the tubing and is produced. This production instability will be cyclical and is referred to as annulus heading.

In this type of completion the casing is exposed continuously to the potentially corrosive ���&�&�[��&����%�!;�����&�*��%��%������� ������ ���� ��% &���;� ���� $��&&�when the annulus is not left open to production.

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Institute of Petroleum Engineering, Heriot-Watt University 11

2.4 Tubing Flow with Annular Isolation'������ �����!� �� �!������ ����!;� !�&�!�!!&�������� ��$����%����;��%� �����!��!����� ��,��!�� �&��,��%���!� �� �������� �� @�� �&��%����&�&�[��&�[�*!�����%�!��� �$� ��%�����������%�� @��% !� ������������*%�%;�*%������!!&������[ �&;�*����]� �&���������%� �����!���*���%�������� �&��%�casing. The packer is normally located as close to the top of the reservoir as possible to minimise the trapped annular volume beneath the packer. Hence the volume of gas which can accumulate there is minimised; simplifying downhole pressure management *%���%�� @���!��� !&��,��%�&������������&��������$�,���� ����!���}�*$�;�� @����!� �� ��������$!��%� �����,�����_����������� ��@����[��&���*���%�������� �&� �����!����%����� ����� � �����,� �����!���&�$� �������� !!��,;�such as a sliding side door which allows annulus communication. Alternatively one can ����� ���%�������;�*%�%�*���&��&���� ��������������%����������������&��������+�����%� !!;��%����� ������������!����� ��,� !�&������%�*��� !���!!���;����� ��$��%�� @��

This completion system is by far the most widely used and offers maximum well security and control.

3 COMPLETION STRING FACILITIES

There are many capabilities which can be included in the string design. Some of these � ������!� ��!!��� �;�!�%� !��%�!����$�&������� ���� ��!����,�����! ��,;�*%��!����%�!����$�&������$&������� �����[]������,���}�*$�;� ����� !&�&������[]������,����$�&&��,��%�������������� ��,��!���!���� �����]����������design with a large number of components. Such inbuilt complexity compromises the reliability of the completion string. The design process should thus initially identify the minimum functional requirements. Any additional options are then assessed on �%�� !�!���������� ������]��,�$�!�!������� ���������

3.1 Basic Completion String Functions and FacilitiesThe basic facilities provided by a completion string must allow it to continue the ���&�����������<��������[��&!��$�� !������ �����&� !���!!����*��%�����%��!!��,���� �� <�������$�����������&���*����� ��!�������%�;��%�&!������!���!����%�safe operation of the well at all times and also reliably allow for its shutdown in a $ ���,����!��� ����!����%����������!�����;����&������ !���� �&�*��% &���!��act as a composite high pressure system which prevents the unintended escape of ���� �����[��&!� �&���!!������� ���[�*��!�����%����&������������� �&��%�K� !�Tree into the surface processing facilities.

The following (see also Figure 6) are considered to be the essential for the majority of completion string installations to allow the well to be produced in a safe and controlled manner:

Y \��%� �����,� ��� ��� ��� �%� ]��&� [�*���� ��!!��� !� *��� !� �%� %��%!��%,&� ������!!���*%�%�� ,�������,&����*������ ����!������&�!%���&�[�*����!��� �Y���&�����\�����%��!�$����Y��<�����*��!\�*��%������ ��[�*������!!�����!!� �&������ ��[�*�!� �����,�

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Y�\����������!�$����[��&���� ��*��%� �%����&������ !�����,� �!�� ����� �%�annulus between the production casing and the tubing.

(c) The ability to affect downhole shut-in either by remote control or by automatically ��$ �&��,��%�% ������*���[�*������&�����!�

(d) A means to establish circulation between the annulus and the tubing.

(e) The ability to block the tubing by the installation of a plug. This allows pressure testing of the tubing etc.

Surface Isolation(wellhead / Xmas tree)

Tubing Isolation (SSV)

Tubing Isolation (nipple)

Circulation betweenAnnulus & Tubing (SSD)

Annulular Isolation (packer)

Figure 6 Basic well completion schematic.

�%� ��$� ���*!��%����������!������������&����� �! �;�������� ���� ������Consider each of the functions in turn:

Pressure and Flow Containment�%��!�$������!!����!���� ��&�*��%����%����&������ !���;��%����&������������;��%�*��% &� �&��%�!��� �$ �$���!���!,!���@��*��� !��%�K� !����������%�;�the casing and tubing annulus is protected from the reservoir or injection pressure if a packer is installed at the bottom of the production tubing. The tubing size is selected !�%��% ��*������&������� �!� ��������!&� �&��%�[�*��!�!� ���

�%�!;����%��%� !���� �&��������!%���&���&!���&����*��%!� �&��%�� ]�������!!���]��&�����%�*��������%����&������ !���;�� @�� �&�*��% &� �� !� �� @��������� ���[��&!� �&���!!��!�����%�$������ ��������� @������� ��,;��%�*��% &;�from which each casing string is suspended will be rated for maximum anticipated !��� ���!!��!��̂ $� �������������[��&����&����������;������<���������;��%�*���

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is provided by the valve system located on top of the wellhead. This Xmas tree usually comprises an in-line valve with a backup valve to shut in the well and side outlets with valves for both choke and kill line attachment during well killing procedures.

Annulus IsolationAnnulus isolation is required in the majority of production wells for reasons of tubing [�*�!� �����,� �&��������������%����&������ !�������������!�����+���!���=����,�necessary to isolate the annulus to prevent surface injection pressures being exerted on the wellhead and possibly giving rise to burst of the production casing. This occurs in injection wells and during well stimulation operations.

This annular isolation is normally achieved by installing a packer at the bottom of the completion string which is lowered into the wellbore with an elastomeric element ����%���� �&���!��������'���%���!���&�&��%;��%�������!�!���,�]���!���������[ �������������%� ���� ��!� ���*���%�������� �&��%� �����!������������!��%�$��������*��%�� @�� �&��%�����%���� !����]��!&����*���[��&!;��%�� @��is normally set quite deep in the well.

Downhole Closure of the Flow String+���!� &$�! ��;� �&������!�� !!�� �& ���,;����% $� �!��& �,�� �!������!������� ���*��!� � ������� ��� ��[�*����!��� ��'!!�����%�K� !���������!��%�K� !�tree valve is not possible. The installation of a sub-surface safety valve (SSSV) will provide this emergency closure capability. The valve can be either remotely operated from the surface {a surface controlled sub-surface safety valve (SCSSSV)} or will ��!� ���� �� ��,�*%�� ���&�����&�[�*���&������Y]!!�$�[�*�� ���������low bottom hole pressure) occurs in the well.

Circulation Capability^������%�� <�������� ����!�����!���� ����&������ !���� !��%�[�*���&����Y����without a production tubing) is the inability to kill the well by circulation. A coiled tubing unit or snubbing unit could be used but is unlikely to be available at short notice to carry out the well killing operation. Hence the majority of completions include one of the following devices to provide circulation between the annulus and tubing:

"� ���&����!�&�&����Y���\����!��&����!�$�Y��\"� ��&���@��� �&���Y�?�\"� ?���&������

They can all be opened when required and subsequently closed. An alternative is to use a tubing punch or a perforation gun with a low power tubing perforator charge. }�*$�;��%�!��!����,��!&���������� �*��@��$��!����%��!�������%����!���� ����

Tubing IsolationA further means of physical isolation of the reservoir is installed at one or more places ����%����������%�!��%����$�!��������!�� ������!�&��*��%����%�*�����;���%��<�!��above and/or just below the packer. The isolation is normally provided by lowering a plug on wireline down the inside of the tubing string until it lands and locks into a wireline nipple which was incorporated into the design of the tubing string at an appropriate depth.

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3.2 Additional Completion String FunctionsA range of other tubing functions may be necessary as a future contingency. Some of the more prevalent are discussed below.

Downhole Tubing DetachmentFailure of a tubing string component often results in the necessity to pull the completion ������%�*������������!���� �����}�*$�;�����!��!�������������!��%� ������of equipment to be pulled from the completion while making this replacement. Thus a point of easy detachment and reconnection would be useful. This is obtained by installing a removable locator device that seals in the remainder of the tubing string left in the well during the repair operation. A means of hydraulic isolation of the tubing below the point of detachment is also required. Examples of such systems are �� @��! ��!,!��;�*%�%� ���*!��%�������� ��$��%�� @�������&�!����&�and retrieved; or a downhole hanger system which suspends the tubing in the well beneath the wellhead. Completion components that are more prone to failure and �=������=������� ���;��������~;�*�������� �&� ��$�!�%�&$�!�

Tubing stressesTemperature and pressure changes during normal well operations results in the tubing string can expand or contract in length. The resulting changes in the tubing stress can ��!�������,�!$�� !������$���!����& � ������%�� @�;�*��% &�����%����������!�������%���������!��]&������!�� ��&� ���%�!��� ��,�� �&��������%�*��% &�and downhole in the packer.

These stresses can be avoided by installing a moving seal system which allows expansion and/or contraction of the tubing without mechanical failure or disengagement from the packer or seal bore. Various systems are available. They all feature a concentric !�$� ���� %�*%��! �!� ���� �&���� �������� �����!;����!��� ����*%�%�moves while the other is stationary.

Ability to Suspend Pressure and Temperature Monitoring EquipmentIt is frequently required to monitor the bottomhole pressure during production tests by ��!� ������ ���!!���������� ����� ��� �� �!������ ���������%���������'�*�����������;���!� ��&� !�&������%�*��� !���!!��������%����������!���������$�&!��%�!�� ����,��'������ �&������!���!� ��&� ��$��%�!�������������$�&� �� ���� ��$�[�*�entry point when the packer tail pipe is blocked by installation of the gauge.

Controlled Fluid Injection from the Annulus into Tubing?��&�&�[��&!� ����� �������!�$��������!;�!�%� !��^�;����% $�%��%�����������!�*��%� ���& ���[�*������!!�����!!�������!���%�� �!�Y����!������%������!������������&��!! ��!;���\� ������<�&��+��� ,����!! �,���������&��%�� �!�������%�[�*�!������ �� ��� �����&��*��%����%�*���������$�&�� ]���������� �&�counteract the impact of these characteristics. Examples of this may be the injection ��� �����!������%���������������������&��!! ����^����������!������<���%!�[��&!�into the casing-tubing annulus and include in the tubing string a side pocket mandrel *��%� �$ �$�*%�%�*����������&����!���&���!!�����&�����!���%��� �����[��&�*�����%��[�*�������%� �����!�������%����������%����������!�,���������������,�

'���%��] �����!�� !��������!� �� ����!�*%��� !� ���<�&�������%����&�&�[��&!�to lighten the hydrostatic head and maintain production at economic levels.

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������������The selection of an electrical or hydraulically powered downhole pumping system or of gas lift will require the inclusion of the pump or of multiple side pocket mandrels in the completion string design. Important design issues will be:

"� �%���%�&������!� �� ����� �&�����$ ������%������������ �����

"� ���!�� ���!���� !!�����%�����������*�������� �%��%������

"� +�!� �� �����&��%�����%�!�&���@��� �&��!��������� &���� �&����&������%�well.

Wireline Entry Guide+��*�������!! �,;������!��*��!;������&���*������������&����������� ����!����*��%������������%��������!�����;��� ��!!��%������ �&�����$ ���̀ ������#���,�Guide (WEG) aids retreval of the wireline tool string from the casing into the lower end of the tail pipe of the tubing string.

3.3 Composite Completion String�%����������!������&!�����!���[��&��,� �� �������!�$���� �&���%��� � ���!��� �,�&�������&!���!�]�!�� �&����� %�!����!��� ����;� ����������&!���!� ��be considered. Figure 7 summaries the general completion components and their functions.

XMAS TREE

WELLHEAD

(SC) S.S.S.V.

SIDE POCKETMANDREL(S)

SLIDING SIDEDOOR

SEAL ASSEMBLY

PACKER

NIPPLE

PERFORATED JOINT

NIPPLE

W.E.G.

Flow Control andSurface Isolation

Tubing & CasingSuspension

Safety IsolationDownhole

Circulation orFluid Injection

Tubing / AnnulusCirculation

AccomodateTubing Stress

Annular Isolation

TubingIsolation

AlternativeEntry for Flow

Landing T and PGuages

WirelineRe-Entry

COMPONENT FUNCTIONALITY

Figure 7 General well completion string schematic.

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4 COMPLETION STRING COMPONENTS

�%�&� ��&�&!��������%����������!��������$��$!��%�!������ �&�!��� �������� �����!���������� ��!���%�� ��� �,������� ���������!� $ �� ��;� %����has numerous variants and each equipment supplier has their own particular designs. In practice most companies use one supplier or have considerable experience with !�����,�!�����������!��'�!�;��%�=��������!�!���&� !� ��� ���!��� �&�with a certain type of threaded coupling. Hence tubing completion equipment is of necessity fairly standard and comparable between the different suppliers.

Equipment selection should be done on the basis that the component will provide a !����� ����,��!! �,������%�!�!!���������� �� �&���� ���������%�*���under a range of operating scenarios. Each component adds undesirable complexity to the completion. This must be compensated for by the fact that it is necessary or ������� �������� ���������. One approach to discussing whether a particular *�������������!����_���_�����!���!����$ �� ���%�� �����!��% �� %������������$�&!���%�&!�����!��%�!�<�!���&���� ���&!��� !�!� �&��%�����!����[]������,�can be assessed against the drawback of incremental complexity.

Each component in Figure 7 will now be discussed below in relation to its purpose in production operations. It should be remembered at all times that the purpose of well design is to minimise the wells "total life time cost" (i.e. the sum of the well construction capital costs and the subsequent operating costs. Thus a range of reservoir depletion scenarios should be considered during the above evaluation.

4.1 Wellhead/Xmas TreeThe wellhead provides the basis for the mechanical construction of the well at surface or the sea-bed. It provides:

"� ��!��!������� �����&�$�&� �� !���!� �&������ �!;������� ��,�����%�*��

"� '�����,� ��� ��!� �� � !��� � ��!��>[�*� ������� &$�� ��� ���� ��� �%� *��� This is ether a blow out preventer stack whilst drilling or the Xmas tree for production or injection

"� },&� ���� !!�����%� ��������*�� !������� ���*������� ���� �&�between the production casing and tubing for well circulation

�%�K� !����$ �$����$�&�[�*������������%�[��&!����&�&�����������<�&�into the well. The Xmas tree is normally installed on the wellhead after installation of the production tubing has been completed. The wellhead provides the facility for all the casing strings and the production tubing are suspended from the well head *%�%��!���!���!������&��,��%���&����;��%�����& ���������%�*�����%�� �� ����������� !��K� !����&!���!��������������+��% !��*��*����$ �$������!;�����������&������ �&��%���%��������<����;�����*���@��������'&&����� ��,;� �%��%��&�outlet (swab value) provides vertical access into the tubing for insertion of wireline or coiled tubing tools into the well. The lower valve is the master valve. It controls all hydraulic and mechanical access to the well. Well safety may require it to be duplicated. All outlets have valves which may be manually operated or are remotely controlled valves operated from a control room.

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GAUGE VALVE

TOP CONNECTION

SWAB VALVE

FLOW FITTING

CHOKE

WING VALVEMASTER VALVE

TUBING HEAD ADAPTOR

TUBING HANGERTUBING HEAD

TUBING

CASING HANGERCASING HAEDINNER CASINGINTERMEDIATE CASING

SEALING MEDIUM

CASING HANGER

CASING HEAD

OUTER CASING

XM

AS

TR

EE

WE

LLH

EA

D

Figure 8 Simple wellhead assembly including casing spools and Christmas tree.

4.2 Production TubingThe bulk of the completion string comprises threaded joints of tubing which are coupled together. The integrity of the tubing is vital to the safe operation of a production or ��<�����*�����%�!��� �������� ����&���������������!���� ���&������ !&�������%��% �� �� �&�%,&� ������� �������&�����!��$�! �&;��%������!&���� ������$�������� �&���������*������!�&� ����!���%����������!����!���&�������$�&�the following capabilities:

Y�\��%� ��!�&�&� ������� �%� ���������!�����$�&� ����&�&�[��&�$����,� ���minimise the total pressure loss (the tubing performance relationship).

(2) The tensile strength of the string (both tubing and coupling) must be high enough to allow suspension of the complete string without tensile failure.

(3) The completion string must be able to withstand the maximum conceivable

internal (or burst) pressure.

(4) The completion string must be able to withstand the maximum concievable external differential pressures between the annulus and the tubing (the collapse pressure).

(5) The tubing must be resistant to chemical corrosion which may arise because of [��&���� ������%�*�����;� �&����%������� ��,� �� ��!������� ������,�one of the loads and stresses mentioned above (2)-(4).

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Each of the above facets of tubing selection are discussed below.

4.2.1 Tubing Diameter���$����� ��,��%����!�&�&� ��������%���������!�!���&���%���!�&�&� �����!�&��&��,��%�* ����%�@�!!����!���$� ��%��������!��*��%���������Y��!>��\��������^����������������!>�����%�* ����%�@�!!�*������[����%���!���!�����%�����%�steel as well as its resistance to failure with high internal (burst) or (collapse) external ��!!���&������� �!���%���������!��%�!�!���&� !��������� ��� ������!�&�&� ���� �&���� �!�����*��%�>������*%�%��%�!�!���!��%�* ����%�@�!!�

4.2.2 Tensile StrengthThe maximum allowable tensile load of a joint of tubing is determined by the tensile !�����%�����%�!��;��%�* ����%�@�!!�����%��������Y �&�%���%���� ����&� � �\�and the tensile strength of the threaded coupling.

�%�� ��!$� ��!� �& �&��� &!����!����}_��;��_��;��_��;��_��;��_��� �&�?_������The numbers after the letter grading signify the minimum yield strength in units of a thousand psi. The letter grades indicate the manufacturing process or subsequent �� ���������%�!��������&��,���!��������!;������%��� �&����� &!� ��% ���� �&�������$�� ���!����!��!��+����� �;��%�%��%���%�,��&�!�����%�� �&��,�*��@�����%�!��;��%�����!�!����������!��������������� �&�� ������,�}

2S.

�%���������,��&�!�����%�&��!��%�����������!���!�����%�����!����%���!����� &��!� ���&��,��%��� ����&� � ����* ���!����� � �����%����;�%���%�*��%�>foot of the pipe also affects the tensile load. The joints nearest surface are under the greatest tensile load due to weight of the suspended pipe since each joint suspends the joint immediately beneath it.

�%��%� &&���������% !�������$�&��*��� !���������!����!��,������ �!������!���load up the tubing string and secondly to produce a connection which provides a seal to retain internal pressure within the tubing.

The design of a completion string to withstand a given tensile load will obviously be dependent upon the depth to which the completion string will be run but the following aspects will also be considered.

(a) The minimum tensile strength of the pipe utilised for the design will be based ������%�� ��� ����!�& � ������%��!��� ������+��*�������&�&��,��%�application of a safety factor with a typical value of 1.6 to 2.0.

(b) The tensile load of a suspended string will cause it to become longer leading to a reduction in the tubing's wall thickness. This will have to be taken into failure conditions due to high external pressures by derating the nominal collapse resistance.

4.2.3 Internal Pressure+���!������%�� �����&�����%��������!������ ����!!����% ���!������� ��;������ �%��the differential pressure between the internal and the external pressures. The "highest" burst condition is usually encountered at the surface where the external pressure is at its minimum. The maximum design burst pressure is normally the pressure when the

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!�������!�� !����&������%��������% &���!!���=� �!��%��!�$������!!�������!�the hydrostatic head of gas in the well.

A safety factor which varies from 1.0 to 1.33 is normally used to reduce the tubing manufactures test data.

��������������������The collapse condition occurs when the external pressure exceeds the internal pressure. This condition is normally greatest at the bottom of the well when the annulus is full ���[��&� �&���������!�$ � �&�

The published minimum tubing collapse data are derated by a safety factor of 1.0 to 1.125.

4.2.5 CorrosionThere are two principal types of corrosion encountered in oil and gas production wells namely:

(1) Acidic Corrosion – due to the presence of carbonic acid (from CO2) dissolved

����%����&�&�* �������%���� ��� �&�����������%�%,&�� �����[��&�

(2) Sulphide Stress Cracking/Hydrogen Embrittlement – due to the presence of H

2������%�[�*����*���[��&!�������%��!�$�����}

2S can also be generated by

�%����*�%��&������ ��� ����!� �� ���[��&!;���������%� !���_������� �����!�or in the reservoir.

Most corrosion is selective (pitting) rather than an even reduction in wall thickness. Corrosion inhibitor treatments will assist in minimising corrosion damage but must be continiously applied. The alternative approach is to select a steel that is naturally ���������%����&�&�[��&!�����] ���;���*��� &�!����!������&&�����!� ���}

2S

� ��� ����!!��!�!����%!� ���!!�!�!�������������������;�������������_����Figure 9 is an example of a completion metallurgy selection chart illustrating how more complex and expensive alloys are required as the partial pressure of hydrogen sulphide and carbon dioxide increases. Increasing reservoir temperature will further complicate the selection process.

(3) Corrosion/erosion is also encountered due to the presence of produced solids ����%�*����!����&�&� �� �����%��%� �[�*�$����,�

4.2.6 Coupling TypesThere are two general classes of threaded coupling:

(1) Connections which require internal pressure to produce a pressure tight seal.

This type of coupling includes the API round thread and buttress connection whereby a thread compound applied to the threads must be compressed by external pressure ���������%��������� �!�������������� �,�$��&�!� !�*��%����%���������

(2) Metal to metal or elastomeric seal connection - Premium threads.

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This class of coupling includes the Extreme Line as well as a range of specialised �������!����!��������� ��&!���;�����},&�������~'��&!���!���%��������!�do not always utilise the threads to give the pressure seal but allow torque to be applied to bring together seal shoulders or a tapered surface within the coupling.

^�%��!�� ��!&��������!;�!�%� !��!������! ������!;� �� �!���!&�������$�&� ���additional seal system.

��������� �� �!����� !!��&� !������Integral or ������� couplings:

"� '��]��� ����������!�%� !��%�~'����������Y������� \��=���!��% �� �� ��thread be cut on each end of the tubing joints and while the coupling has two female connection.

"� '��]��� ����������% !� �� ��������$�* ����%�@�!!�����%���������!�����(Dc > D) giving it higher load capacity compared to an integral coupling. The integral coupling (Figure 9b) has a male and female thread cut on opposite ends of the pipe.

"� '��]��� ����!�����������!!� ����� !&�* ����%�@�!!�������� ������&�����%����� ���*���� ��� ���%� &���������*��%����! �������������%����the tensile load carrying capacity.

"� '�[�!%�<������!�������*%�%��%���!� ���������+���� ���� ����Y&���&\��%����%�the make up connection (Figure 9a).

"� '������� ����!�����������!�������*%�%��%���!� �!� ���!��������&� !&�Internal Diameter (d > d

c) in the area of the coupling (Figure 9b).

Partial Pressure of H2S, psia

DUPLEX STAINLESS 22 Cr- 5 NI - 3MoCOLD WORKED 2205

15 Cr - 60 NI - 16 Mo

21 Cr - 61 NI - 16 Mo

25 Cr - 50 NI - 16 Mo

27 Cr - 31 NI - 3.5 Mo

22 Cr - 42 NI - 3 Mo

20 Cr - 25 NI - 4 Mo

QUENCH ANNEALED

13 Cr

API J-55N-80NACE

API-80C-75-2

85 SS90 SS

1.0E-03

1.00E-03 1.00E-02 1.00E-01 1.00E+00 1.00E+01 1.00E+02 1.00E+03 1.00E+04 1.00E+05 1.00E+06

1.0E+06

1.0E+05

1.0E+04

1.0E+03

1.0E+02

1.0E+01

1.0E+00

1.0E-01

1.0E-02

Figure 9 An example of a Completion Metallurgy Selection Chart

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D

d

Dc

D

d

t

dcDc

dc

a) b)

Figure 9 � \�~'�{�'������� ��,�[�!%�����������\�'������� �;������ ��,���!����������

������ ������������!����"�%�!�������!�&��&������ ��,��,��%�*������&���$��,� � �,!�!�*%�%��&����!��%�optimum tubing internal diameter based upon the available sizes. Frequently the completion string will contain tubings of different diameter with the diameter decreasing towards the bottom of the well. The use of larger diameter tubing higher up the well ���������%���� !����[�*�$�����!� !��%�[��&�]� �&!� �&�� !��!����� �&�from solution as pressure declines up the tubing. The reduction in tubing size in the lower sections of the well may be necessary because of limited equipment availability �&��% �� ������� ����;��������&�������������!�&�&� ����

�%�&� ��&�&!����� !&�������%��%���% �� ����&�����!�Y��!���;����!�� �&���� �!\� ���������&�����%�!����!�!���&���%��!�������!��� ���������the tubing is summarised as:

Length – tubing – tubing – grade – coupling – joint of tubing OD wt/ft of steel type length

e.g. 7000' – 51/2 – 23 lb/ft – C-75 - Hydril – Range 3

Super EU

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4.3 Annular Pressure SealAn annular seal or pack-off in production wells is necessary for:

"� +����$&�[�*�!� �����,� �&����&������������

"� ?������������%��������!!������ ������!,!���Y�%����&������ !���� �&�the wellhead).

"� +!�� ��������$ ����!����!�&������!����� �����������&��������� ����!;���������!�� ���*�����&��������!�% $����&�������[��&��������!;��^�;���!!������permeability or for stimulation or pressure maintenance.

The most common method to provide an annular seal is the packer (Figure 10a). The packer is anchored in position by pushing the steel teeth of the slips into the casing wall while the pack-off is accomplished by expanding or extending the elastomer element outwards from the packer body until it seals against the casing wall (Figure 10b).

Drag Springs

Slips

Slips

Cone

Cone

Upper

Lower

Sealing Elements

Compression force movescone downwards movingslips against casing welland compressing sealingelement.The greater the compression, thegreater the sealing force and the resulting resistance to packer movement.

Lower Cone

Lower Slips

a) b)

Figure 10 a) Permanent packer. b) Schematic of setting a compression set packer.

The characteristics that determine which type of packer is most appropriate for a particular application are:

4.3.1 Ease of RetrievalThis refers to how easy it is to release the packer for retrieval to the surface. This &�����!��%�&������&������,����*��@�����$�� �*��� �&�� ,� �!�������&��limitations in of the differential pressure that the packer can withstand:

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"� A Retrievable Packer The packer can be run as an integral part of the tubing string. It is run to the setting depth where the setting mechanism is actuated. It can be easily retrieved after installation by pulling tension on the tubing and shearing a set of (weak) screws. This reverses the setting process.

"� A Permanent Packer (Figure 10a) cannot be so easily retrieved. It is usually ���� �&�!��!� � ��,;���%��*��%����*��%�����%�� ��������%��������!�������!�subsequently run and the packer engage to achieve a pressure seal within the central bore of the packer. Packer retrieval involves milling away the packer's internal sleeves to allow the rubber element to collapse.

Packer Retrieval"� '�����$ ���� @���!���$�&��,�����������!��������%����������%�!���!����

shears a series of (weak) brass screws at a predetermined value that depends on the number and strength of the screws. The packer setting action can now be reversed. The slips disengage from the casing wall and the sealing element collapses and the packer is released from the casing wall and can be pulled to the surface.

"� ����$ ����� ���� ����� @���=���!��������� * ,��%������ ��!�$;�*%�%�%��&!��%�����!���!������ ���%�!��� !!��%�� @�;�*%�%��!���*���� �&� ��be pulled from the well. The milling operation normally takes between 3-6 hours. �%������% &��!����&&�������%�� @�� �&�� ��� ��&������ ��,� ����&���&;�*%�%�� !!!��%����%;��%�� @������Y��������\���%���������������!� �!�����&�with a retrieval tool and catch sleeve which collects the remains of the packer *%���%������������ ������!������;� �&��%����������$&��

PackerMill

MillingShoe

Catch Sleeve

Catch sleeve preventspacker falling into well,allowing immediateretrieval

Packer

Figure 11 Packer milling tool illustrating one trip milling and retrieval.

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4.3.2 Setting MechanismThe compression and extrusion of the rubber element during the setting of packers can be accomplished by a number of mechanisms.

"� Mechanically set e.g. by rotation of the tubing string.

"� Compression or Tension using the suspended weight of the tubing. A cone mechanism transfers the string weight to be transferred to the packer to compresses the rubber element (Figure 10b). This setting mechanism is simple but is unidirectional in terms of the setting force and ability to withstand a differential pressure. This drawback can be avoided by installing an upper cone (see Figure 10a) which acts in the opposite direction and will withstand tensile forces.

"� Hydraulic set utilises hydraulic pressure inside the completion string. The tubing string must be isolated or plugged below the packer to prevent pressure being exerted on the formation or the annulus during setting.

"� Electrical The packer (plus tailpipe) assembly is lowered into the casing on an electrical conductor cable. A small explosive charge is detonated at the required !������&��%;� �� ������%�!�������% ��!��

4.3.3 Ability to Withstand Differential Pressure"� Compression Packers�Y����*��%��!�\�+���%� !�������� �����&�����*��!;�

higher pressure below the packer compared to above counteracts the setting mechanism. This type of packer is suitable for injection wells where the differential pressure supports the setting mechanism.

"� Tension Packer This is the opposite to the compression packer.

"� Compression and Tension Set Packers Packers that can withstand pressure from either direction.

4.3.4 Number of Packer Bores+���!��!! �,����% $� ������%����%��%�� @������ %��������!������������;�&� ��or triple bore packers are available for multiple tubing string completions.

4.4 Seal between Tubing and PackerSome completion designs anchor the tubing string mechanically to the production casing at both the packer and the tubing hanger that was landed in the wellhead. ����%�;�% ��!�����%�[�*�������� ���� �&����������!!��� �� �!����� �����or contraction of the tubing string. This may result in buckling or tensile failure of �%� ������� !��*%�� ��*�� �%� � @�� �&� *��% &� �!���$�,�� �%�!;� ! �� !!����!� ����� !!��&� ��&�������*%�%���%,� ���*������ ����$�������compensate for thermal expansion and contraction of the tubing i.e. dynamic or static seal assemblies respectively (Figure 12).

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Anchor sealassembly

Locator with sealassembly inside

polished boreof packer

Locator

Locator seal assemblywith seal bore extension

Extra LongTubing SealReceptacle

(ELTSR)

Travel joint

(a) (b) (c)

(d) (e) (f)

Polished Bore Receptacle (PBR)

Cemented production liner

Packer seals liner annulus

Figure 12 Schematic views of various tubing seal assemblies.

"� Static or Anchor Seal Assembly (no tubing movement). An external elastomer elements seal at the bottom of the tubing. Tubing movements is prevented by installing a mechanical latch assembly inside the seal bore (Figure 12a).

"� Dynamic Seal Assemblies accommodate tubing movement.

"� Locator Seal Assembly (Figure 12b) This consists of a series of standard elastomer seal elements which are run inside the smooth (polished) bore of the packer. The ����%�����%�! �!��!�!��������% ���%,��� ���*��%����%�� @��*%���%��������experiences the maximum expected amount of expansion or contraction. A greater seal contact area is provided by a seal bore extension run below the packer (Figure 12c). A locator (or shoulder) is included at the top of the seal assembly. It has an outside diameter that is greater than that of the packer base. The point at which the ����! ����������!��%�� @���!��&����&��,���!�$���� ��&����������%�string weight when the locator "hangs-up" on the packer.

"� ��������"!����"���#��� ���� (ELTSR Figure 12d) This device consists of two concentric cylinders with elastomer seals between them. The outer cylinder is attached to the tubing string by a threaded coupling. The inner cylinder is latched into the packer with an anchor seal assembly as described above. The typical ELTSR is 10 – 30 ft long.

"� Travel Joint (Figure 12e) This device is very similar to an inverted ELTSR.

"� Polished Bore Receptacle (PBR) This completion component simultaneously provides both an annular pressure seal and a locator seal which permits tubing movement. The PBR consists of a receptacle with a polished internal bore (Figure 12f) which is run on top of a production liner with packer. A seal assembly can then be run on tubing and located inside the PBR.

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4.5 Sub-Surface Safety Valves (SSSV)The Christmas Tree's production wing valve and master valves are used for well isolation or closure under normal operating conditions. The advantage of these valves �!��% ���%,� ������ ��&������� &�*��%�������&������,����%!�$ �$!� ���%�primary closure system for the well. Well security is endangered in the absence of an effective surface closure system. This can occur during:

(1) Xmas tree removal during workover preparations to pull tubing

(2) Removal of valves or valve components for servicing (3) Accidental damage to Xmas tree

Y�\�� @ �� ���%�*��% &�_�K� !����[ ���! �!

'�$ �$����!%�������[�*��!��� �&��� �%��%�*��% &� !�� �������%��������!,!�����This Sub-Surface Safety Valve or SSSV is required when the Christmas trees valves are not operational. These valves are based upon two different control philosophies:

(1) Direct Controlled SSSV which are designed to close when downhole well ��&�����!������!!��>[�*� ��$ �,��������!��&!����$ ��!���%!�$ �$!� ��often refered to as "storm chokes".

(2) Remotely or Surface Controlled SSSV (SCSSSV) whereby closure and opening of the valve is actuated using a surface control system which feeds hydraulic pressure directly to the downhole valve assembly.

Both valve systems provide a failsafe shutdown system for remote sub-surface isolation e.g. in the event of a catastrophic failure of the Xmas tree.

"� Remotely Controlled SSSV This is the more widely employed and more ��� �����%�&���%�$ �$!����� ��,���,����%,&� ������!!��;�!�����&����the downhole valve by a small 1/

4" monel control line run in the annulus and

!�� ��&�����%�������;����@���%�$ �$�������%�$ �$���!����!����� ��,���%�� �� ������ �[ �����,��Y�����!���� �&���\�&$����*��������!� �� $ �� �������deploying and retrieving the valve:

"� Tubing retrievable The valve is run as an integral part of the tubing string. It �����,�������$&��,����������%�������������%�[�*�� �%� ��% $��%�! ��&� ���� !��%���������'�!� ����[�*�&� ����*����������$ ���$ �$� ������!� ��&� ���%���������%�$ �$���%�!� ���*!�*������&���������������;��%���%���!!���,� �� ���*��� �;�����%������������$ ���$ ���� ��!�

"� Wireline retrievable The valve nipple is run as an integral part of the tubing the internal valve assembly being subsequently run and retrieved on wireline �����%�[�*�� �%�����%�$ �$�*����% $� �!� ���� � ��% ���%����&������tubing. It should always be evaluated if this will restrict production at some time in the wells life. (This is especially important for gas wells).

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Ball

Springcompressed

Shifting sleevedown

Snap ring

Sheer pin

Landingnipple Depressurised

control line

Pressurised control line

Springextended

Springcompressed

Springextended

OPEN CLOSED

Shifting sleeve up

Figure 13 Ball type Surface Controlled Sub Surface Safety Valve.

Open Closed

Springcompressed

Flapperopen

Pressurisedcontrol line

Springextended

Shifting sleeve upShiftingsleeve down

Flapperclosed

Depressurisedcontrol line

Figure 14 Flapper type Surface Controlled Sub Surface Safety Valve.

Annular safety values are installed at shallow depth for cases where it is required to minimise the volume of annular gas released if wellhead assembly is damaged. This is typically installed in offshore wells where gas lift is installed or where a downhole packer has not been installed. An example completion is illustrated in Figure 28.

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4.6 Side Pocket MandrelThe side pocket mandrel (Figure 15a and 15b) contains an off-centre pocket with ports ������%� �����!��'�$ �$;�*%�%�������!��%�[��&�[�*���*��������� �&� �����!;� ������!� ��&�����%���@���% �� ���*!�[��&�[�*���*��������� �&� �����!�

"�� Gas lift valves� ��!��������;�!%�������%�������%�� !�[�*���*���%� �����!�and the tubing at a preset pressure at valve depth. They can either respond to the pressure of gas injected into the annulus or to the tubing pressure {see also �% �����;�Y� !�����\�����%�?��&�������%�����,���&����

"�� Chemical Injection Valves� ���*��%���<�����������&������%�� �!;�!�%� !�����!������%������!;������������&��!! ��!;��;�������%����������%�$ �$��!�opened when the annular pressure exceeds a preset value.

"�� Circulation ���[��&!�������������%� �����!�������%���������!� %�$&��,���!� ������a valve with a bursting disc which can be sheared. Communication between the annulus and the tubing can only be stopped by replacing the shear valve by wireline.

The installation and recovery of the valves from the side pocket mandrel is also described in Chapter 5 (Gas Lift) of the Production Technology module.

Orienting Sleeve

Tool Discriminator

Polish Bore

Pocket Assembly

Valve body

(b) Cross section of Side Pocket Mandrelwith gas lift valve installed in pocket

Seal Element

Valve Body

Polished bore

(a)

No restriction to tubing access

Figure 15a and 15b Side Pocket Mandrel with valve installed.

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4.7 Sliding Side Door (SSD)The sliding side door (Figure 16) permits communication between tubing and annulus. +����!�!�!�����*���������!�$!;���� ������!���!����%��!;�*��%�� !������! �!�between them. The inner sleeve can move up or down by wireline or coiled tubing. This movement aligns the inner and outer openings. Its main application is to provide !!�����%���������!���������������������!� �&������� �������[��&!�����%�tubing or annulus by circulation (often for well killing).

The SSD's design features external ports through the tubing wall within which is located an inner mandrel with slots and seal rings above or below the slots (Figure ��\��`%����!&;��%������� �&������!�$��!��� �&�!�%��% ���%�����!�����%�outer tubing wall are isolated by seals above and below on the inner mandrel (Figure 16b). Movement of the inner sleeve upwards (Figure 16a) allows circulation between the tubing and annulus by aligning the slots in the inner mandrel with the ports in the outer tubing. Moving the inner sleeve in the reverse direction returns the circulation device to its closed position after completion of the circulation operation.

Movement of the inner sleeve requires the running of a shifting tool to open and close the sleeve. The shifting tool lands in the top or bottom of the inner sleeve and �,�< �����;��%�!�$� ������$&�������&�*������� ��,���$��������%�!�$�cannot be accomplished if a extremely high differential pressure exists across the sleeve. Any number of sleeves of the same size can be run in the same completion.

����&!� ��� �%� ! �� � ���� �%��������*���&$� ����� �&� �%� �!��� ��� ��������jarring can cause failure to close the sleeve. A separation sleeve can be run which will land inside the sliding sleeve and seal in the seal bores above and below the slotted section of the inner sleeve when it proves impossible to close the sliding side door as described above.

Seals

Seals

Inner ports

a) Open b) Closed

Circulationpermitted

Circulationprevented

Sliding (inner)Sleeve

Ports on SSD body

Figure 16 Wireline Operated Sliding Side Door.

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4.8 Landing Nipples'�� �&����������Y��������\��!� �!%���;�������� !��,�*��%� ������� ��������*%�%�can accommode and secure a mandrel run into its bore on wireline or coiled tubing. It provides a:

"� �!!�����% �� ��,���@��%�� �&�������� ��!���� �!�����]� �&����@,!�

"� ?�!!���! ����*���%������ ����������%������� �&��%������!��� �����%�mandrel.

�%��������%���������!� �� �&���>��@���������� �&� �! �����������*%�%��%�mandrel (a plug or other equipment) may be selectively installed.

Selective Landing Nipple

Mandrel with correct profilelocked in place

Pressure Equalising Sub allows retrievalof mandrel

SubsurfaceFlow Controlvalve

Figure 17�����!��� �[�*�������� �&������!���$�� �&�����������

Nipples are installed at various points in the string to allow:

Y�\�+!�� ����� ��� ��������� ��� �%� ������� !������ ���� *��� !%��� ��;� *��@�$�� ��� ����hydraulically setting packers.

(2) A ported device which allows communication between the tubing and the annulus.

Y�\�#����,���!�������%����������� ���� ��[�*���&�����,���������&����control.

Y�\���*�%������� ���������%�������������%�[�*�

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(5) The installation of downhole pressure and temperature recording gauges.

The landing nipple maybe selective or non-selective. A selective nipple will only allow the corresponding mandrel to lock into place e.g. seven or more different mandrels of the same size can be selectively landed in the correct nipple installed in tubing.

There are three methods of obtaining selectivity in a landing nipple system:

Y \�����$��,�� !&������ �$ �� �������� ��������

(b) Selectivity associated with the setting tool.

(c) Selectivity based upon pre-spaced magnets.

4.9 Perforated Flow Tube�%������ �&�<�����Y�������� \� ���*!�����[�*���������%�!������$������%�� !�����%�� @��� ��������!������&��,;�! ,;���!!���� ��!�

4.10 Flow Coupling� �,�����%�������� !!���!;������ �&���������!;���!� ��&�*��%��� ��������!�����;�*���� �!� ��!�����������[�*���%���$���� �&�&�$�������!� !!�� �&�with entry to and exit from the nipple system will cause increased turbulence. This turbulence can lead to substantial abrasive erosion of the tubing wall and nipple system. Flow couplings (Figure 18b) are installed above and below the nipple to �� !�[�*�!�� ��%������&$�!���%,�% $� ����� !&�* ����%�@�!!� !� ��]�� �allowance for erosion.

Flow Couplingwith increasedwall thickness

Landing Nipple

Flow Couplingwith increasedwall thickness

(a) (b)

Turbulencegeneratedby landing nipple’s profile.

Figure 18�� \�?���� �&�[�*������\����*���������

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5 MULTIPLE ZONE COMPLETIONS

$�% &��������Multiple zone completions are employed for reservoirs where more than one distinct �!�$���� � ,�� �!� ����!�&� �,� � !����� *��� �&� �%�� �!� �%� ��������;� ��� �� ���=������;�������&������������<��������%!�� ,�!�!� � ��,���# %��!�$����% !;��,�&�������;���!��*����!!�������� �&;������!��;��%����*��� !_^��_���� ��and Water-Oil-Contact.

�%��������� �%�������!��!�$����� ��,�]�!�!����� ���,���}�*$�;����&��������� ����!� �����������!�&�&�!�� ���&;� �&��%������&� �����,�&��&!�������%�]�������*%�%�$��� ��[�*����!������ ���&��!�$���!� ��� �&��,�% ��!�in depositional conditions resulting in layers having a variable degree of vertical permeability. Each of the producing layers has to be treated as a separate reservoir if a very low vertical permeability exists between the separate the layers.

5.2 Multiple-Zone Depletion Concepts"� ������������%����*������$ ����!����!����*%�%�[��&�����������% ����

�!�$���� !����� ���!�,� [�*!� ����� � !����� ������� !������ ���� �*�� ���! producing up a single tubing string.

"� Segregated, Multi Zone Depletion: multiple production conduits are installed within the same wellbore. Each tubing controls the production of one reservoir.

"� Alternate Zone Well Completion Strategy: each well is completed on more �% ������!�$�����}�*$�;����,�����!�$�����!����&�&��������������!������at any particular time. The advantages and disadvantages of each of the above techniques is discussed below.

5.2.1 Co-mingled Flow Advantages

"� �%���� �����������*��!� �&��%� ��� ����$!����;��!�������!&�!��� %�well provides a drainage point in every reservoir

"� �%� ���&������ �� � �]� ���� %� �!�$���� !%���&� �� � %&� =��@�,� !���the amount of drilling is minimised and so is the number of wells and the time required to execute the drilling programme. i.e. production should be accelerated compared to the other optional strategies

Disadvantages"� �%���]����������&�&�[��&!�����%�*������ ����&�! &$ �� ���!����[��&!�

from one or more of the reservoirs have any of the following characteristics:

1 Corrosive or potentially corrosive materials����� �&!;�}2�;��^

2.

2 Produced sand has an erosive effect. The implementation of sand control procedures may be more complicated.

3 ����������� ����������������� compositions and hence differing economic value.

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4 ��������������������������������������������%�!�*������[����%�$��� ��lift performance of the total well system.

"� Variation in individual zone pressures and permeability can lead to a back pressure effect on the less productive or lower pressure reservoirs.

"� � ����������!�����������������"��� ��������#������$�� ���%���������"���������

Only the total well production rate can be effected by choke control.

"� &�������$��"����#�������'������� �������!����� �����[��&!� ����� !��,�be diverted into individual layers without temporary isolation using sealants (diverters) or bridge plugs.

"� A change in the production characteristics of one zone e.g. water coning and the ��!=������� !����`^��*������[����%���� �����&������������%�*����+��� ,���&������������&,�*��%������!��������%�*���

5.2.2 Segregated – Multiple Zone DepletionAdvantages

"� �%����&������� �� �&�&�� ��������[�*���� %����� ������&��&���,�controlled.

"� �% ��!� ��� �%����&������% � ���!��!������� ����*���� ���� ��[��� �%�others.

"� ���� �,�!� ��� ��&� �� *��@� ��� ��&�$�&� �� ���!� �� �� �����!%&�*��%���� �* ,!� ��������%����&�������������%�����!;���������!=��;������� ����;���

"� ����$������� �������� %������!���!!����

"� ���������!�&��������������������� %������!���!!������%�!� !!�!�!����� ��� ��balance or reservoir simulation studies for reservoir management.

Disadvantages"� # %������=���!���!��*���������!���������� !�����%�����%�������&������

tubing and other completion equipment required. This requires an increase in �%� ��� ��]��&����;��%���&�$�&� ��*�����!� �� ��������� �&� ����� !����the total time required to complete the drilling programme.

"� �%� �% �� �� ����]��,� ��� �%� ��������� �!� ��� !&�� ���� ��=����equipment malfunction can be expected during installation and in the future.

"� �%��&�&��������!��!�% ����!�����������_������������!�� ,��&���%���� ��[�*� � ��,�����%�*���

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5.2.3 Alternate Zone Well Completion StrategyAdvantages

"� #����$����������� ��� !��!�����!�$����&������� �&�*�����������!����$�&&�

"� ̀��� ������ ����� �!� !��,� % ��&� ��� �%�&������� !�� ��,� �!� ���&;� ����changing a well from production to injection.

"� ?�����!�������&�������*���&�������!! ���,���[����%���������,�����%����&���������[��&��������%�����!� �&�*��!�

"� # %�*����!��% �� ��,��� ��$�,�!�����������!�����%���!@����� �����&��to complexity.

Disadvantages"� '��� ������������*��!�% $������&����&� �&������&���� %�$��%�! ��

degree of depletion control and reservoir management. The same reservoir drainage ����,�*�������,��� %�$&��,� �!��!� ��� ��,���� !&���&�&$�������cost.

"� �%���&�!�������� �&��%�!��%���������&�������!�!;�*��������� !&����!!�the number of wells is increased.

5.2.4 Selection of Development Strategy" Offshore or Onshore Development Offshore developments have a higher well cost and a reduced number of wells

compared to comparable onshore developments

' ������*����+�;�����#��������<���� The installation of complex multiple completions is problematic in high angle

*��!� �&� ��� &����!����� ���&�������!� �&���� !!�����%�&���������!�����excessive lost time while these problems are corrected.

' =�����������>�#��������#��?���@���K>�������������� �%� ������ �� ���� ����!���� ��� ��!���� �,� �%� ���&�&� [��&!� *���� ��[���

�%��,���������������+�� &&�����;��%�&������*%�%��%�&� *&�*���������������%��!����!!����&�������������%�����!�� ,���[����%�%������completion:

� +�� &&�����;��%�[�*������� ����� %��������%������� ��&���� ����!� ��� ��������!���% !������!� ��&;�� �!����� @����!� �*��%����%�*����������a multiple tubing completion.

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$�Q U��� �<���K�; �����K���"��������̀��!� �����������;��������&���� �,�������������!�*��%����%�! ��*���

bore by simply increasing the amount of completion equipment installed to provide �!�� ����� �&�[�*�������� � �����,���%�����!�����!���� �%�! ��*������ ����������������&������ ��!����� ����

The inherent advantage of the single wellbore completion are lost as the number ������!����%��%������]��,;� �&�%���%������� ������� ��������;���� !!��The optimum number of zones to be produced into any wellbore will depend on the �!�$���� Y���� �%����&������ � �\;� �%�*���&!���� Y���� �%�&$� ����� ���\� �&�the expected problems (e.g. completion component failure and expected operational problems throughout the well's life).

5.3.1 Dual Zone CompletionThere are a number of ways in which completions can be designed to produce two zones Y��������\���!�&!��_�����&�[�*� �&���&�$�&� ��*��>��������������%�� �{

Casing/Tubing FlowIn this case a single tubing string is run with a single packer installed to provide isolation between zones. The lower zone will produce up the tubing whilst the upper zone will ���&������%� !���_������� �����!���%�&������,�*��%��%�!��,���������������!��% ����&��� ��� ��[�*���&�����!����*����% $� ���$� �����!���% �!��!!�� ����� �� ���� ��! ��,�$ �$��'�!���%����&�&�[��&��!������� ��*��%��%� !���� �&����� ,��%�!� �!�& � ���,�����!������� �� !�����+�� &&�����;���!!�������� ����!����the annulus with respect to casing burst may preclude stimulation of the zone which produces via the annulus. These issues can be addressed by:

"� (""���%���� ���������� ����&�*%���%����������[��&��!����_����!�$;�non-abrasive and where casing pressure limitations do not preclude stimulation.

"� )�����%���� ��������– this design can be considered in situations where the ���������*���&�������!��� ������� ���� ��[�*���%���*������ ���� ��[�*�system requires one long and one very short tubing and two packers and a crossover �������%�!�&!����%�*$�;������!� !!�������%����!������������;������ ���������

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(c) Single String Selective

Sliding side door forupper zone production

Nipple

(d) Dual Tubing

(a) Upper Zone Annular Flow (b) Lower Zone Annular Flow

Nipple Sliding side door forupper zone production

Figure 19��^�����!�����!����� �&�&� ��!�����;��*���������������*��%��������������

' &��!����"� �%�!����������% !� �!� � ���������!���������� %������+���=���!��*��� @�!;�

one to isolate between zones and the other to isolate the upper zone from the upper casing annulus. The depletion of each zone can be accurately monitored �&��������&��+�� &&�����;��%���<��������[��&!������ %������!������&����,��,��%��������&!��������� ���%�����������!� �!������!���&�����%����������&����������������*���[��&!���%��������� ,����������� �%���% ���%�� � ���������� �����!%�*�������������&��'��������������� ���*!� ��� ��� � �����[�*�����%����&�&�[��&!�Y���� ���$�� !����!��\�������=���!� �����complex running procedure.

" Single String Selective� �%�*����!������&�����*�����!;�*��%�����������!�������% ��% !����&!���&�

to selectively allow the production of either zone or to commingle both zones. �%�����������=���!��*��� @�!;��������!�� ����*�����!� �&��%���%������!�� ���%� �����!��+�� &&�����;� �����,��������!��=���&�����[��&�������%�upper zone to enter the !��������%�!� �������&� �&���!&� !�&!��&;����� �sliding side door (SSD). Finally producing the upper zone into the tubing closure of the lower zone may be accomplished by setting a plug in a nipple at the base of the tailpipe.

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5.3.2 Completions for Three or More ZonesThe options discussed for dual completions can be extended for wells to be completed with or without some degree of zonal co-mingling on three or more zones.

Thus for Triple Zone Completions this can be accomplished with either:

"� �%���������!��������������������!����!� � ����� ��[�*� �&�% $�����%��packers for isolation.

"� �*��!��������������;�*%��,�[�*�������*�����!��!��_�����&������������the tubing strings.

"� ���������� ���� ��[�*� �&��*���������!�����!����&�����!� � ��,�������*��zones.

"� �*��!���������������*%����%��������%�����%�!�����!� �������&���� ���*�selectively production from two of the zones. This requires two tubing strings and three packers.

"� ������!�����;�����������!���$����������

5.4 Multiple Completion Equipment+�� ��� �� ���!;� =������� �=������!� ���� �������� ��������!� �� � ���,�based upon the equipment available for single string completions with the following exceptions:

"� �������% ����!,!��!"� �������� @��!,!��!"� ��� ��!&���!� �� �����=�������

Obviously the number of tubing strings will affect the completion procedure. The size of the tubing and ancillary equipment will be dictated by the limitations imposed by �%� !������!�&�&� ���;���!����� &� �&����=�� � ������!�*������������ ��,��� �!����� �������������� ��������������

5.4.1 Tubing Hanger SystemsThe simplest way of landing multiple tubings in the tubing head spool is to use a segmented hanger (Figure 20). Each tubing string requires a hanger segment. Upon � �&�������� ����%��������!�����!;��%�% ���!�!%���&������ �����!������� ��% ����which also seals the annular space in the landing seat within the tubing head spool. Normally each hanger segment is made up with a short (or pup) tubing joint above and below which is attached to the rest of the string. The tubing strings can either be run independently or simultaneously.

Provision must also be made for the control lines for each tubing string and valve system when using a surface controlled sub-surface safety valve.

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Figures 20 Split dual tubing hanger

5.4.2 Multiple Tubing Packer Systems���������������!,!��!�*�������� ��,��=�����% �;��%����������� @�!�=� �!��%�������������!���������&�&���*��� @�!�*�������=���&����� �&� �����;�&� ��tubing completion. The lower one is a single packer whilst the upper will be a dual � @�������� ��,;��%��� @�!�*�������=���&;������!���� �!����;�&� �� �&� �������� @������ ��%�����;�����������������������

Similar types of multiple string packers are available as these described for single string � @�!;������%,� ������%����� �����������$ ����+�� &&�����;��%,� ����!���!���� �%,&� ������� ��% �� ��!���������&�����%�*������!���������&��;��!���=����,��!&����!���%���*�;�!�����!������� @���

Although in most cases it is preferable to run retrievable multi-string packers since it � &!���� !�������$ ����� �� �� &,���������]�*��@��$����� ����;���� ����packers are available and may be required in high pressure wells or wells where !����� ��� ������� ��$���� �&� !��!!� �!� ����� �&�� �%� !������ ���&��� ����the packers must be such to allow pressure testing of all tubing to be carried out independently before initiating the packer setting procedure.

All multiple string packers must offer a means of connecting tubing both above and below the packer for each string. In some cases mechanical attachment exists e.g. �������!�*&�������%�� !�����%�� @��*%��!�;������%�� !!;��%�� @������!�a seal bore.

The tubing strings will have different lengths in multiple string completions in �,������������$��$������������!�����!���%,� ��&���&� !��%������!�����;��%�intermediate string and the short string. This terminology is crucial to the running procedures for the completion e.g. a packer may be run into the well on the long !������*%�%��!�� �&&����;� �&�� ,���!���!����%,&� ������!!�����%���,��%������!����������,��%�!%����!������ �������% !�������;��� �&�������%�� @��! ������ �&�landed off in the tubing hanger.

5.4.3 Blast JointsThe long string in a multiple completion is located in the casing opposite the perforated !����!������������&��������!���%�&����������[��&�[�*��%����%��%������ ����!�������%�*�������!����� ��,�����&��� ������%�*��� ]�!� �&��%�[��&�[�*!�� ����!��=��@�,�% ����%����%��������[�*�����%����������%�[��&���������%�*������

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Y����%��%�$����,�� !�[�*\�� ,�% $� �!����� ������ ����������%��������* �������%������!�����;�� &�������%,&� ������!������%���!����� ��*����&� !�� ��,���� !����! �&������%��!���&���!� ����������&�&��

'��%�@�* ��&��������!�����@��*�� !� ��� !��<����;��!����� ��,�����&&�����%������string opposite the perforated intervals of the upper production zones to compensate for the increased rate of erosion.

6 WIRELINE SERVICING OF COMPLETION ACCESSORIES

The majority of well completions with "dry" wellheads and deviation angles < 65º use wireline techniques either to operate equipment in the well or eliminate the need to pull the completion string and replace components which have failed. Typical wireline applications are the:

"� +�!� �� ����� ��� ��������� =������� ������ ��� �������� �%� ���&������ ������ e.g. a packer and a tailpipe assembly.

"� +�!� �� ����� ��� ����$ �� ��� =������� *��%��� �%� ������� !������ ���� $ �$!; ��!!���� ��!;���

"� ^�� ��������&�*�%���=������������%��&�$������!%�������[��&�[�*����������a sliding side door or install a bridge plug

"� ���$ ������ ��� �!;�*%�%�% $��������������%��������!�����;�!�%� !�* ]����sand.

"� '&<�!���������%��������������$ ����������� �����

`��������$��$!���*����� ������������%������������������ �!��������������%����������!�� ������ ������!������!�!��&&������%�� �!�����!�� �&�*�����;� ��� �&&� ����� ����� ���������%������!�����;���%���,�� �!���������*����;�*���� ��� ��� �jarring effect on the tool and activate the setting or retrieval mechanism that will carry �����%��=���&� ������'���� ��$�,;� � ���*��%� ������ ����&����������� ��an electric signal can be used to initiate the required action.

�!� ��� *������ *���;� ��� � �,� !!;� �� � =��@�;� ���� ����� �� ���� ��$�to mobilising a drilling or workover rig to pull the tubing string to replace faulty =��������}�*$�;��%�*��������� ���� ���%�!��� ��!��%,!� ��,�$�,������from the downhole location where the tool must operate. This remoteness coupled with the uncertainty of cable stretch (especially important in deviated wells) and the small scale of the tools makes wireline a technique which requires highly skilled ��!��������������$��}�*$�;�������� ��������*��������� �&�=�������������%����������!������&!�������$�&!� ����� !&�&������[]������,�������!����well operations and servicing capability. Electric line allows real time information and measurements to be conveyed to the surface operator. This means that the equipment is ��%�����]��!�$� �&��%���� ���!���!����%��%�,��� ��&��}�*$�;��%��!��������!������� ���� %����$!��%�� �����=���&��,��%���� ������� ���$��� �;�!��@;�wireline unit.

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Wireline's greatest asset is the ability to conduct operations on a "live" well i.e. one *%�������� �����]�!�!���*���%��!�$���;��%�*������ �&��%���������%�tubing. Hence pressure is present at the xmas tree during a wireline intervention and the surface wireline equipment must allow:-

"� ��*���������%������!����������%�Y&�*�%��\�*��@��� ����� �&���!�!��!=����retrieval.

"� ���������������%��������!������ �&��%� �����!����

"� } �&����� �&� ������������,!�!���% ���%������ ���� �&��%������!������ ����positioned vertically above the well prior for lowering through the Xmas tree and into the tubing string.

"� �%� �����,������!����%������!������������%���$�*��� �&������$�����!!���!&�*���[��&������! �����������%��$��������

"� '����*������$�����*%�%�*����! �������%� �����!� ����&��%� ��� �&;�����=���&;�����%�*������

The components of a conventional wireline system are shown in Figure 21.

Stuffing Box (Pressure Seal Around Wireline)

Lubricator (or Pressure Containment System)consists of one or more tubing joints

Lifting Clamp

Lubricator Pressure Release

Blow-Out Preventor

Connection to Xmas Tree

Odometermeasures lengthof wire insertedinto well

Lubricatordetermines

maximum length of toolstring

that can be inserted into well

to Wireline Drum

Load Cell Measures Wireline Tension

Xmas Tree

Pulley

Portable Hoist

Wire

Figure 21 Wireline Surface Equipment mounted on Xmas Tree

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Institute of Petroleum Engineering, Heriot-Watt University 41

6.1 The Wire���$����� ��*�����;�����!��@�*������;������!!� �!�����!�� �&����*�����%�*���is normally made from high tensile steel so that the ratio of breaking strength (lbs) to wire diameter (inches) is maximised. The minimum cable diameter is normally used to reduce the weight of wire while still achieving the required breaking strength.

The wireline is normally wound onto a reel on a self contained skid which has its own power supply for drum rotation and measurement of cable length and tension (Figure 22).

Wireline Unit

Work Platform

SC-SSV Control

BOP ControlPortable Hoist

Hydraulic Power Unit

Figure 22 Wireline Surface Equipment

6.2 Surface Monitoring EquipmentThe important parameters that the wireline operator must be aware of at all times during well operations are the tool string location (depth in the well) and the tension on the cable. The length of cable in the well gives an approximate depth for the tool string. It is measured by holding the cable without slippage against an odometer (a wheel with a device that counts the number of rotations) as the tool string is lowered into the well (Figure 21).

The cable tension is continuously monitored to ensure that the breaking strength of the cable is not exceeded. The cable tension will:

"� �&�� !��%������!�������!���*�&��%����%��!������������%��������!������&�����[��&� ��!!���� }�� ��� ��!���� ��� ���� ��,���$� �� ����]�� ��indication of tool position.

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42

"�� +�� !� !��%������!�������!���*�&�������%�*���&������%���� !����*��%�����the wire. Hence it will also decrease during recovery of the wire and tool string.

"� +�� !�Y� ��&�,\� ��� �%������!�������% ��!_������� �!�� ��%����,� �&�*�%���restriction during recovery of the wireline.

"� ���$�!�,;�&������ ��!��������� �%� ����� !������ ����� �%�*��;� �%� ��!����*����reduce when it does not fall easily down the well due to increasing friction or a downhole restriction.

The maximum well deviation angle for conventional wireline operations is 65º due to the increasing friction of the wire and tool string against the tubing and production casing or liner. Wireline servicing of such wells requires use of an electrically driven tractor that pulls the tool string into the well. Tractors allow servicing of wells with deviation angles greater than 90º; but they require substitution of the slick (solid) wire by a (more expensive) electrical cable as well as hire of the tractor itself.

7 TUTORIALS

7.1 Well Completion Designs�%�� ��������!�*������������&!���!;� !������]��&�������%�*�&�� ��������� ����� � !� �&�*����$�������!���%�$ ���,����&!���!��[�{

"� Well characteristics such as:� "� ?�!!���� "� ?��&���$��,������<��$��,���&]�� "� ����&��������!�� "� ��@��������!� �&������� ��& � �

"� Geographical factors:� "� �� ������ "� ̀���&��%�Y������!%��\�� "� ̀ �%����&�����!�� "� '!!������,�

"� Operational design constraints:� "� #�$������� ������ ����!�� "� � ��,� !��!�

"� The number of producing zones.

A number of typical completion types are presented below. These designs have been chosen to illustrate functional similarities and differences in a range of well environments. They are all based on the concepts discussed in this chapter.

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Institute of Petroleum Engineering, Heriot-Watt University 43

COMPLETION NO. 1 (Figure 23)

This completion features VAM tubing with an anchor seal assembly latched into a permanent packer. The VAM tubing is required due to the production or injection of gas with relatively high closed in surface tubing pressures. The permanent packer would have been made up with its tailpipe and run in and set on drillpipe or with an electric wireline cable. The absence of a moving seal assembly indicates that little expansion or contraction will occur or that the need for good differential pressure sealing integrity is paramount.

31/2 in 'X' Landing Nipple

Anchor

Permanent Packer Seal Assembly

Millout Extension (Required for packer retrieval)

Crossover 51/2 in x 31/2 in

31/2 Hydril EU Tubing Tailpipe

31/2 in 'X' Nipple

31/2 in 'X' Nipple

Perforated Flow Tube

Wireline Entry Guide

Wireline Operated Sliding Side Door

7" Production Casing

Surface Controlled Sub SurfaceSafety Valve

Hydraulic Control Line

3 1/2" VAM Tubing

Figure 23 Single zone completion with no provision for tubing movement.

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44

COMPLETION NO. 2 (Figure 24)

This design allows production through a tubing string with a moving seal assembly located inside a permanent packer. Additional features include two nipples located in �%�� �����;��%���������������!!����!�� ���������%��������!�������!�����$&� �&�the lower one for landing bottom hole pressure survey gauges.

Production Casing

Nipple

Nipple

Nipple

LocatorSeal AssemblyPermanent Packer

Seal Bore Protector

Surface ControlledSub Surface Safety Valve

Hydraulic Control Line

Production Tubing

Wireline Operated SlidingSlide Door

Packer Millout Extension

Cross Over to Smaller Tubing

Perforated Flow Tube

Production Liner

Wireline Entry Guide

Figure 24 Single zone completion utilising a locator seal assembly.

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Institute of Petroleum Engineering, Heriot-Watt University 45

COMPLETION NO. 3 (Figure 25)

This design allows high production rates since the large bore tubing minimises the frictional pressure drop in the tubing. The packer and tailpipe can be set on electric cable or coiled tubing and the tubing string subsequently latched into the packer with an anchor seal assembly at the base of an extra long tubing seal receptacle. The range ������������$�����!��,�� ��,������������?��&������� �!������;��������;�������>&�or more are typical for this type of completion.

9 5/8" Production Casing

7" Hydril Production Tubing

Surface Controlled Sub SurfaceSafety Valve

Mill-out Extension

4” Hydril Tailpipe

Wireline OperatedSliding Side Door

Perforated Tube

Hydraulic Control Line

Extra Long Tubing SealReceptacle with Nipple andAnchor Seals on the Slick Joint

Permanent Packer Wireline Set

Nipple

Landing Nipple

7" Production Liner

Figure 25��}��%�[�*� ���������������

with an extra long tubing seal receptacle for greater tubing movement.

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46

COMPLETION NO. 4 (Figure 26)

�%�!����������&!���� ����%��%�[�*� �����&��������� ��<����� �!� �� ���� ��$�to Figure 23. It is referred to as a Monobore� !� ���% !� �� ��;��� ��$�,���!� ���diameter from surface to the reservoir. This consistent diameter facilitates concentric access and intervention. It utilises a polished bore receptacle at the top of the 7" liner which seals against a seal assembly installed at the base of the tubing string. The seal assembly provides a moving seal area to accommodate expansion and/or contraction ����%����������%�!�&!�����%�!�����!� ���������!����^������&��������[�*�������%�*��% &�����%������ ����!��'!�!%�*��%�;��%���!����� ����,������!�� ��������*�the PBR. This can be achieved by installing a packer and small tailpipe containing a wireline nipple below the PBR. Circulation to kill the well is provided by a shear valve in a side pocket mandrel instead of a sliding side door.

9 5/8" Production Casing

7" Production Tubing

Surface Controlled SubsurfaceSafety Valve

Hydraulic Control Line

Nipple

Polished Bore ReceptacleSeal Assembly

7" Production Liner

Liner Packer and Hanger

Side Pocket Mandrel PermitsCirculation After Instalation of a Chemical Injection orShear Valve

Figure 26���������������������������������%��%�[�*� ����<����>

production using a polished bore receptacle.

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Institute of Petroleum Engineering, Heriot-Watt University 47

COMPLETION NO. 5 (Figure 27)

This completion provides gas lift to allow production to occur or to increase the production rate. The string contains several side pocket mandrels containing gas injection $ �$!� ��$ ����!�&��%!���%�&!���������!!� �����$ ���� @�;� ����� ���%���if it is suspected that a completion will require mechanical repair at frequent intervals.

9 5/8" Production Casing

7" Production Tubing

Surface Controlled SubsurfaceSafety Valve

Hydraulic Control Line

Nipple

4” Tail pipe

Nipple

Nipple

Nipple

7" Production Liner

Side Pocket Mandrels ProvideSubsequent Gas Lift Once SuitableValves are Installed

Perforated flow Tube

Retrievable Packer

Figure 27 Single zone completion with gas lift.

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48

COMPLETION NO. 6 (Figure 28)

�%�!�����]�&!���� �����&�!�[]������,� ����� �%����������!��� ��� ���*!� ����commingled production of both zones or for selective production from either of the zones. Continuous gas lift using gas injected down a separate string. Gas injection using the 2 7/

8" tubing avoids excessive gas pressures being exerted on the production

casing (which mitigates a casing burst if the casing has deteriorated). The small gas injection string and dual packer are also used in offshore situations when annular gas pressure is not allowed. In this case the dual packer is normally set at a shallow depth.

4 1/2" Production Tubing

9 5/8" Production Tubing

2 7/8" Tubing

31/2" Production Tubing

(x2) Surface Controlled SubsurfaceSafety Valve

Hydraulic Set RetrievableDual Packer

Nipple

Nipple

Gas Lift Mandrels

Blast JointUpper ZonePerforations

Travel Joint

Locator Seal Assembly

Wireline Set Permanent Packer

Permanent Packer

Sliding Side Door

Wireline Entry Guide

9 5/8" CasingLower ZonePerforations

Figure 28��������!�����;�!���$;�&� ���������&��!�*��%�� !������

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Institute of Petroleum Engineering, Heriot-Watt University 49

COMPLETION NO. 7 (Figure 29)

This design features a downhole ESP installed parallel to a bypass tubing which allows !!�����%����&������������*��%�#�?������������&��������������!��$,!;����������% �� �����$ ���%,&� ����!��� @���!��!&���%�!��&�!�Y _����\��%�&�������!�in pulling the string should the pump need replacing regularly. The run life for a large capacity ESP can be as long as several years but this depends upon installation ����,� �&��%� �� ����� ������$����������� �!���% ������Y'����� ������\�of the Production Technology module.

JunctionBox Surface

PowerCable

Wellhead IncorporatingCable Penetrator

Retrievable Hydraulic Set Packer

Downhole CableClamped to Outsideof Tubing

Production

Production Tubing(3 1/2")

Selective Nipple

Bypass Tubing (2 3/8")

Pothead Connection

Y-Tool

Pump InletPump (5.44" OD)

ESP / Bypass Tubing Clamps

Motor (5.44" OD)

Pressure Sensors

Bypass Tubing (3 1/2")

9 5/8" Casing

Figure 29 Single zone completion with Electric Submersible Pump (ESP)

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COMPLETION NO. 8 (Figure 30)

�%�!� ��������� �����!!� �*�� ������� !�����!;� ���*���� !� � �&� ���&������ ����� %�����*��%� �!����� ���&�������!�$����� � �������%���*��� @���!� �permanent packer and the longer tubing string is connected to it using a seal assembly. �%������� @���!� �����$ ��;�&� ��� @���'���=��������!�&���� �&;������*��!��_!��� �! ��,�$ �$!;��*������ �����&$�!;�����%�@�* ��&�<����!�@��*�� !�“Blast Joints” are used to combat erosion on the longer string at the point of entry of [��&�������%����������������%�*������

9 5/8" Production Casing

2 x 1/2" EU Tubing

Crossover 3 1/2" x 2 7/8"

2 7/8" EU Tubing

3 1/2" Sliding Side Door

Nipple

Nipple

Upper ZonePerforations

2 7/8" Sliding Side Door

Tubing Latch and Seal

2 7/8" Nipple

Sliding Side Door

2 7/8" Tubing2 7/8" Nipple

Nipple

2 7/8" Wireline Entry Guide

3 1/2" Blast Joint

3 1/2" Locator Tubing Seal Assembly

Permanent Packer

Crossover 3 1/2" x 2 7/8"

Perforated Tubing2 7/8" Tubing

2 7/8" Nipple

2 x Surface Controlled SubsurfaceSafety Valves

Figure 30 Dual completion with segregated production.

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Institute of Petroleum Engineering, Heriot-Watt University 51

COMPLETION NO. 9 ( Figure 31)

�%�!� �,�� ��� ��������� �!� ���%� !����� �&� �� ��$�,� % ��� }�*$�;� ��� !����!�������%�� !������� ����!�&�!�!!&� ������+��% !���� ����&����!��� � !;������%���&&��# !�� �&��%���'�*%�� �!����;�&� �� �&���������������!�% $������!� ��&���� �!���% ������Y'����� ������\�����%�?��&�������%�����,���&���

Production Casing

Nipple

Wireline Isolating Nipple

Borehole Wall

Direct Controled SurfaceControlled Subsurface Safe

Direct Controled S.S.S.V

Upper Zone Perforations

Lower Zone Perforations

Cement Sheath

Figure 31 A "Tubingless" dual completion.

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52

7.2 Completion Tutorials: Spot The Errors.Indicate the correct position of the accessories shown on the completion below (Figure ��\�������������!�����%�!������ �����$�&&�!���% ��,��� ��&� *�����%�!������and then compare it with a solution on the next page (Figure 33).

S

N

N

N

S

SPM

Tubing hanger0’

Depth

100’

600’

758’

1055’

9 ” Casing

2000’

2550’

2562’

2610’

2632’

7” Liner hanger

2774’

2992’

2784’

Sliding Side Door

Blast Joints

Landing Nipple

Landing Nipple

Wire line entry guide

HUD (Hold Up Depth)

Landing Nipple

Control Line

Surface controlledsub-surface safety valve

Side pocket mandrel

Sliding side door

Permanent packer

20’ Locator seal assembly

3 ” Production tubing12

58

Figure 32 A completion with several errors.

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Institute of Petroleum Engineering, Heriot-Watt University 53

S

N

N

N

S

SPM

Tubing hanger0’

Depth

100’

600’

758’

1055’

9 ” Casing

2000’

2550’

2562’

2610’

2632’

7” Liner hanger

2774’

2992’

2784’

Sliding Side Door

Blast Joints

Landing Nipple

Landing Nipple

Wire line entry guide

HUD (Hold Up Depth)

Landing Nipple

Control Line

Surface controlledsub-surface safety valve

Side pocket mandrel

Sliding side door

Permanent packer

20’ Locator seal assembly

3 ” Production tubing12

58

Figure 32 A completion with several errors.

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54

S

N

N

N

S

SPM

Tubing hanger0’

Depth

100’

600’

758’

1055’

9 ” Casing

2000’

2550’

2562’

2610’

2632’

7” Liner hanger

2774’

2992’

2784’

Sliding Side Door

Blast Joints

Landing Nipple

Landing Nipple

Wire line entry guide

HUD (Hold Up Depth)

Landing Nipple

Control Line

Surface controlledsub-surface safety valve

Side pocket mandrel

Sliding side door

Permanent packer

20’ Locator seal assembly

3 ” Production tubing12

58

Figure 32 A completion with several errors.

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Institute of Petroleum Engineering, Heriot-Watt University 55

S

N

S

N

N

SPM

Tubing hanger0’

Depth

500’

2400’

2488’

2520’

2550’

2562’

2610’

2580’

2570’

2632’

7” Liner

2774’

2665’

2650’

2992’2784’

Sliding Side Door

Retrievable packer

Blast Joints

Landing Nipple

Landing Nipple

Wire line entry guide

HUD (Hold Up Depth)

Landing Nipple

Cross over 5” x 3 ”

Surface controlledsub-surface safety valve

Side pocket mandrel

Sliding side door

Permanent packer

20’ Locator seal assembly

3 ” Tubing

perforated flow tube

9 ” Casing58

12

12

Figure 33 A solution.

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56

FURTHER READING

��� �?������� ̀������!����������,�#�����&!;�����;� ̀���!;������� �&�����_���� �;����?����!%&��,� ��%��`��,�¡����!���&������ �,���������!!�����TN871.2P487 1988 and ISBN 0 471 96938 9

��� � ̀��� ���������� �!����� �,� ��� ��,;� ��� ~����� ��� ��� �$������!� ���Petroleum Science. First Edition published by Elsevier in 2009. ISBN 978-0-44-53210-7 and ISSN 0376-7361

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Page 63: Chap 1 and 2.pdf

Production Technology Petroleum Engineering

9000

True

Ver

tical

Dep

th

10000

11000

13000

1000

1500

2000

2500

3000

3500 1500

1000 North (ft)

East (ft)500

0

500

1000

1500TD 15.925 ft. MD

41/2 Inch7 Inch

12000

14000

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Page 65: Chap 1 and 2.pdf

O EN T N T SC

1 INTRODUCTION

2 HORIZONTAL WELLS 2.1 Horizontal Well Trajectory and Build Radii 2.2 Extended Reach Wells 2.3 Geosteering 2.4 Horizontal Well Completion 2.4.1 Smart/Intelligent Wells 2.5 Well and Reservoir Performance 2.5.1 Flow Regimes 2.5.2 Reservoir Drainage Area 2.5.3 The Well Productivity Improvement Factor� ����� ����!����}������� �� ̀��! 2.6.1 Increased Exposure to the Reservoir 2.6.2 Connection of Laterally Discontinuous Features 2.6.3 Changing the Drainage Geometry 2.6.4 Extending Field Appraisal Laterally 2.6 Disadvantages of Horizontal Wells 2.8 The Economics of Horizontal Wells 2.8.1 Costs� ������?���� �����,�+�&� ���!

3 MULTI-LATERAL WELLS� ����� +����&������¡���������!� ����� � ���!�+�[�������%�?����� ��'���� ������� Multi-Laterals 3.2.1 Multi-Lateral Interference in the Reservoir� �����������_� �� ��+�����������%� ̀����� 3.3 Impact on Recovery and Rate 3.4 Initiation Methods for Laterals 3.5 Principal Multi-Lateral Geometries� ����� ����!���������_� �� �� ̀��!���#������¡ Technical 3.6.1 Application of Multi-Lateral Wells 3.6.2 A Multi-Lateral Well Example

Advanced Wells and Completions T W O

Production Technology Petroleum Engineering

O EN T N T SC

26/06/14

Page 66: Chap 1 and 2.pdf

LEARNING OBJECTIVES:

Having worked through this chapter the Student will be able to:

"� �!�����%��%�����,��=���&�����&�������;�!������� �&����������%������� ��wells.

"� �!�����%� ���� ��������%������� ��*��!�

"� ��&�!� �&��%�� !�!���������_� �� ���%�����,� �&���!���%��� ���� ����!�

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Institute of Petroleum Engineering, Heriot-Watt University 3

1 INTRODUCTION

#]���� ����� �&����&������������� �&�� !�% $������ �!����&��$���%�� !�����, �!��,�]��!�$�&$������!����*���!,!��!� �&��%�����,����������� �&�����������%�����,�% !�� &���!!�����*�*��� !% �!� �% ��% $� ��� !&� �%�����,�����������&��������%�&����������� &$ �&���������!����� !!!�� �,��*��%������!��% ��� ,��� ����&���&�$�&� ��,������������ ����{

"� }������� ��*��!�"� #]��&&�� %� �&����� �&��*��!�"� �����_� �� ��*��!�"� +���������Y�!� ���\�*��!�

This chapter discusses the application of advanced wells to enhance the exploitation ������� �&�� !��!�$���!����%�*��!� �� �!��@��*�� !������$����� ���*��!���;�����%� !��������]��� <����!;��%������&!������*����!�!�����!��!&�Y�������\���%,���,�����%������$&�&���������%�����,��% ��% !����� $ �� �������%�� !�����, �!���%��� ���� ����� ���*!� ����� !&������ �����,����&��� ����$!�&�����%�*�������%���&�&$����������<��$� {

9000

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tical

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th

10000

11000

13000

1000

1500

2000

2500

3000

3500 1500

1000 North (ft)

East (ft)500

0

500

1000

1500TD 15.925 ft. MD

41/2 Inch7 Inch

12000

14000

Figure 1 A "Designer" well

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4

"� '!!������%�*�!��� !!�����!�$!�

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"� �!���������!@!�*��%���!=�����������,��� �������!�!!��� ��

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"� ����� ����,���!�!�*��%���!!���� ���������!;�*��@�$�!� �&�!����� �������!��������&&�����%�!������� � �,!�!�

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"� '�� �&������ ����&����&����������&_��� �&��!�$���$�,�

"� ���������*%���&����������%��=�!�$ �� ���%��!�$�����������!� ���%���&�!�lateral limits.

#]�� �&�������!� �&�% ����!� ��!�*%���!���� &$ �&���������!�����&{

"� +�� !&�����]��,��=���!� ������������!�$ ��& �������� �%�%�!��*���design since the potential risks are greater.

"� �*���!�� ���!� �������&�&�*%����� ������%!�*��!�

"� �*�;�%��%�� ��*��!��!���!���� ����� !&������ ����� ��������*���% !������� @���������&������

�%�� ]��������������� &$ �&�����������%�����,��&!� ��������!��� ���������!!��% �������!�����%���%� ������� ���$�����@��*�&�� �&�]�����*��%��%� ����� !���������� !������ � ������'����&�& � � !���� ������ �!�$���� �&�well details in the area around the proposed well is the foundation of this planning ���!!���%��� ��!%���&��������,����!����&�������;���������� �&� ��,����&����������!%���&��$���%����������,������%�*����%����%���� � �&��������%����� ����!�����^*��!%����!%���&���������!&��,� &&�!!����� !�� �����������!��%����%�����%�*���!�����

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Institute of Petroleum Engineering, Heriot-Watt University 5

2 HORIZONTAL WELLS

Introduction}������� ��*��!�% $����� ��]����,������ ��&$��������������Y�������\���%�!�% ���������&�!��%�� !�!����&!������� �&���������� �%������� ��*����̀ ����� <���,;���!�����;��!�$����[�*�����!� �&�&� �� �� � !� ��&�!�!!&����!��%������� ��*��!��!� ��&������������� &��!�����&�!������ �%���% ���%�!%����� &��!��%��=���% �����,� ���*!� �!%����� �� ������%� �&� ������&�����������%��=��

Drilling and completion of horizontal wells�%����&������ !����Y�����5/8 ��\���� �%������� ��*����!��!� ��,�!�� �� �%��%� ����Y¢�70£\�<�!�� ��$����<�!��*��%����%��!�$���� �&� ��Y�1/2 ��\�������%���Y�������\�&����&��%����%��%��!�$�����'�������%��� ��������,&�*%���%���!������&������� ������!�$����@��*�&����%���� !&��!������%�������%��������*��%&� � ��!���%������� ���!������%������� �� �&���%����!@!�*%�%�*����������� �&�����%�������%���% !��������,�$ �� �&���%�������%����!������&� �&� � �&��&� ����$ �� ����;� �%�*��� ����&�%������� �� �&� �%�� ]��&&� �%����%� �!�$���� ��� �%��� ��&�����%� �&��� ��,��%�*�������������!���!� ��&�

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Ann

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ell C

ount

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Figure 2��+�� !����%������� ��*��������!�

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6

Long Radius

Medium RadiusProfile

Profile

Formation Top

Pilot Holeabandoned after evaluation Target Reservoir

Figure 3 A horizontal well with pilot hole.

2.1 Horizontal Well Trajectory and Build RadiiThe trajectory from surface to an entry point close to the reservoir is drilled using ���$����� ���&���������%�����,�*��%� ������� &��!�Y�£-6£>������\�����&_���!����������$��%�������! ���� ���� �&�*��� �����%�!���% ��&������!�&���&�����%�*���� ����!���&��,��%��!�$������������%�����&_���������%��!�$����!������������� !!�����&����� &��!�Y�£-20£>������\�Y� ����\���%����,�������������%��!�$�����!� ��&��%��%��� �&��%�� ���&�����%�*��� * ,��!� ��&��%������Y�������\��

Build Radius

Heel

Standoff

Toe

OilWater

Figure 4 Horizontal well nomenclature

Hole Type Build Radius for 90º turn (ft/m)Long Radius 1,000-2,000 / 300-600Medium Radius 300-800 / 100-250Short Radius 30-200 / 10-60Ultrashort Radius 1 – 6 / 0.3 - 2

Table 1 Build radii.

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Institute of Petroleum Engineering, Heriot-Watt University 7

�%�*����!���=����,�&����&�� � ������� �[��&���� ������!�$����>����_�!�$������@����� !����%�$��� ��&�!� ������% ����� ���!� ��&��%��!� �&������������� ��������� ���� ������������%�$��� ��&��������,��!������������_*%��_&����������%��=�!��% ��� !����%�&�!� ����*���%������ �&��%�[��&���� �������%��������,����� !����%�%������� ��!����� �������]!!�������������%��������!��!� ��,�!���,��!�$�����=������!;�������������*��� !!���!�&� ����!����������!� ��,������&��������&�������!��}������� ��!����!�% $�]&&���@�����!�����&!���%��������%�*��� ���������% �����@��%������� ��,�������%�!��� �*����� ���������%�%������� ��!������!������&�*��%��#]��&&�� %���%�����,����the upper section of the well.

2.2 Extended Reach Wells#]��&&�� %�*��!�% $� �%������� ��&�!�� �������Y���\�~��� ��&��%�� ������� ��� !���{���������%�������� ]�������������Y�������\���%�� ]�����$ �������%�!�� ����&��&!�����%{

"� Vertical Depth. The highest ratios are achieved in shallow reservoirs.

"� Drilling conditions�� ��� �!�$���!� *��%� &������� &�������� ��&�����!;� %��%����=�������*�� ��������� ������!������%�!�� ����

"� Equipment���%�������!��% $� �� &=� ������&��$� �&�&� *_*��@!����% �&���%���� !&�!������*��%�� �&����=��&� ��

"� Technology capabilities���%��� <���,�����%�*�����!���� �����,��������&��

#]��&&�� %�*��!� ���*� ��� ���� %� � �����!�$��������� !!&���������&�����������������] ���;��%��� �������%�� ���&!��������� �&������!����&�% $����&$���&�*��%� �!������� ������� �%���% ���%������ �� ��,���!� ��&����]��&&�� %��%�����,�% &���� $ �� �������%������!���%�� �� ������������!�� ���!� !!�� �&�*��%�]��&&�� %�*��!{

"� ������ �&���!@�&������%���� !&�����%� �&�����]��,���� %�*���

"� }��%����$!��������*���

"� ����� ����!�����%� $ �� ���&������������

"� ��������������� ����!� �!&��,��%��'�����}����&�!� ������%��!�$���� �&�the completion length with in the reservoir.

"� ���*������������ �&�����$������ �����!����&��,��%�*��������,����!!�"Smart Wells" are installed.

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8

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t

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Extended ReachDrilling Envelope

Horizontal Reach = 0.25True Vertical Depth

Figure 5 Examples of Extended Reach Drilling.

#]��&&�� %����������% !���������������� �,���&!�&!�����%!������ ����!��+��has allowed economic development with very large "step-outs" in shallow reservoirs.

2.3 GeosteeringThe successful drilling and completion of a horizontal well at the target location depends on placing the well at the correct depth within the reservoir. The lateral %�������,���� �%��!�$�����=���!� �% �� �%�*��� �� <���,� �!� ��$�,� &<�!�&��!����� �_���������� ���������!���!����% ��!�����%�*���!��� �����*��%��!��������%�� ����� �������� �[��&�������,����� !��Y�������\���%�!�!���������!!��!�known as geosteering.

Shale

Sand

Water

Figure 6 Geosteering on a shale zone.

�%�� �_���������� ����� ���������{

"� Cuttings analysis��&����!�&�������� �@�����%�����!������] ����&�������!�� ���� �%��%������!�*��%��� �� !!�$� ���� ���!�$���� �����&����&��,�examination of the microfossils. The cuttings will also differentiate reservoir ��������_�!�$��������!�� !� �&�����!%�*!�����&����,�[��&���� �!�

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Institute of Petroleum Engineering, Heriot-Watt University 9

"� "Logging-While-Drilling" (LWD)��!����&�!��,;� �!�!��$��,� �&���%�� ����!� ����&����,�� �!� �&����%����,�% ��!� !�*��� !�&�!� �������[��&���� �!��Example applications include

' �������"���������������}������� ��*��!�������������!�$���� ��!��<��to severe gas cresting if any part of the well is close to the gas-oil contact. ^��������� ��������%�*��� ���=�����% ������!���!�����&� �!���&�&�!� �� ��$��%����_* ������ ����%�!� ��������� %�$&�*��%��!�!��$��,�tools.

' �������"��������>�������+���!������&!�� ������!����%�*���<�!����&���%�!% ���% ��! �!��%��!�$������!�!��$��,;�� �� �� ,��������!��,�����!� ��������,&���%������%�!��&��&��������%�!������&�����!�

' �������"���>�"> ��;������������ }��%���� �����,�! �&!�% $� ���*��* ���! ��� ������% ����*���� �����,�! �&!�&����� ���� �,����!���%�!�� �!� ��!�!��$��,����� !����*���%!�! �&!�� ���*�����%�*�����������!��&��%����%��%�%��%���� �����,�! �&�

2.4 Horizontal Well CompletionHorizontal Well Completions are one or two orders of magnitudes longer than conventional completions.

�%��� ��,���� !&��!������%�%������� ��*��!����������% !��������!�&�&� �����*��%��%���� !&�����]��,� �&��%���%��?��&�������%�����,��=������!;������ �&��������;���� ���!�� ����;�!���$��,�����* ������� !�!%��_���� �&�!����� �������� ����!�*%�%� �����!���&����,�����]���� �����%�����,��!���*� $ �� ������ �$������� ���� �� ���� ���!� �������*������ �&� ���&� ������� !!� ���!�����*�������%������� ��*��!��̂ �� ������ !!���������_� �� ��*��!�!�������!��!� ��������

�%� *��� ���&������ � ��,� &��&!� ��� �%� �!�$����!� ��[�*� ������ �� �%�completion design and the wells production casing or liner diameter. The relationship ��*���%!�� ���!��!�!��� ��!&������������

Well Capacity

ReservoirCompletion Design Production Casing or Liner

Wellbore lengthorientation etc.

Lift considerations Mechanicalproblems

Flow capacity(diameters)

Completion type Reservoir inflowperformance

greatly increasedby horizontal well

Excessivewater/gasproduction

Sandproduction

Natural Formationdamage

Open hole Perforationproductivity

Figure 7 Well Production Capacity.

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Sketches of three type generic horizontal well completions are shown Figure 8. � �����!��� ��!!��%��� &$ �� �!� �&�&�! &$ �� �!��

System Advantages Disadvantages

Open Hole - low cost - risk of hole collapsebarefoot completions - large internal diameter - difficult to abandon(Figure 8a) - no sand control

Open-hole liner - liner provides access for - isolation andcompletions wireline or coiled tubing selectivity(Figure 8b) - maintains access if hole problematic collapses - difficult to abandon - provides sand control if wire wrapped screen installed

Cemented and cased - provides zonal isolation - higher costcompletion - allows multiple hydraulic - achieving a(Figure 8c) fracturing treatments good cement bond - can be completed as requires good a “smart” well practices

Table 2 Horizontal well completion options.

Production casing shoe set in the reservoirabove the heel of the well

Open holesection

Figure 8(a) Open hole completion.

Tubing tail pipe installedpartially along lateral moves thepoint of maximum drawdown to thecentre of the lateral

Slotted or drilled liner orwirewrapped screen

Figure 8(b) �^���%�����������������*��%�Y������ �\�]��&&��������� ������

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Institute of Petroleum Engineering, Heriot-Watt University 11

Cemented liner with internaltubuling along lateral

Total flow rate measured by Multi-phase Flow Meterinstalled near the Christmas Tree

Packer separates zonesInterval control valveadjusts zonal inflow rateinto the tubing

Figure 8(c) Selective completion divides the lateral into three zones.

2.4.1 "Smart" or "Intelligent" Wells�� ���*��!� ������ ��,;����������!! ���,;�%������� ��*��!�=����&�*��%�&�*�%�������������� �&������������� �� &��������%���� ��&�*�%���� !�����!�Y�������� ���;���!!��\��!������ $ �� ��� �&������&�*��%��%���� ��*���[�*�� ��� !��&��,� ������_�% !����*�������!� ��&�� ���%�%��!�� !������%�& � ��!� � �,!&� �&��%������� ������!&���� &<�!���%���� ��[�*��������&$�!���%�!����&����,� ���� �&�������%�!��� �����,� �*�����>���&������������$���������!%���� �!�$�����%�*�����%�&�*�%��������� ��������&����!&�&����,����� ���� ���&�*�%���[�*��������������%�!�!���% !�����,������ @��

�%�� ���&��$��� &�������!� ���*��!�% !�����%������������!�$����� � ��������%������� ��*��!���!�$����� � �����% !� �%���<��$���� �!������ �% �� �%��!�$!���� %�[�*������ ��������,�]�� �&�*��%� ��������������* ��&�[��&!�Y����* ��\���%�!��=���!� �%� �����,� �����!���������� �&� ����$ �!� �&>��������*������ �&�����$ �!���%���%�&!��������� ����� �&����!���������&������!� �&�! ������!�������&� !�����!&������$����� ��$��� ��*��!� ������&����������%������� ��*��!�������������!�$����� � ��������&����� ��&�����%�*���*��&�$�&&������ ����������!����!;� %����*%�%����&����������&� �&�controlled separately. It would also reduce the operating and processing costs as well !��&������%�*��@�$����=��,�� $��&�����%���� !&���!@!� �&��!�!� !!�� �&�*��%���$����� ��*��@�$����%�&!{

'!�;��" Waiting for $ �� �����,����=������;��*!;�&��������������

'K������ '��,�� ��!�� &&���!�� �����Y����% ��\� ��� @����������& ,!���� �� �������!�&���&������'�!��! ���� ���!�� �����*��@�$�� ������ �� ���!�����]��!�$��% �� ��� ������<�����

'#��?�� ^��������!�&$�������&�������%�*��@�$��

'K����������� ������� �%� *��� ���� ����� �� ��������� �=���!� &�������� ��� plugs etc.

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���! �Y��!!���,�&��* ��\���&�&$������!�*��%�� �_����� � �������� ��[�*�� � ���������� ���?�^�Y!�!����������� �%�!���&��\������%�� �,�������������&������� ����,��!���*���=����,��� ��!&�

2.5 Well and Reservoir Performance

2.5.1 Reservoir Flow Regimes~��� ��*��!��% �� ������,������ �&� ��!!��%�������!�$����!�����!%�*� �� &� ��[�*������*��%����$��� ��[�*�*��%����%��!�$����Y������� \������%������� ��*��!�����!�!!��� ���% ��[��&�[�*!�$��� ��,�����%��$������%�%������� ��*���Y��������\���%�well would drain oil from a horizontal layer whose thickness is the well diameter if $��� ��[�*�* !�������!!����Y����@v���\��'�%������� ��*��������&���� ���& �;�homogenous reservoir whose width is shorter than the length of the well will show ��!���$�,�� &� �;���� �;��!�&��� &� �� �&��� ��,�%��!�%�� ��[�*�����!�

Top View

Side View

Top View

Side View

Vertical Well Horizontal Well

Figure 9 Flow regimes for vertical and horizontal wells in a homogeneous reservoir.

2.5.2 Reservoir Drainage Area�%�����%����%������� ��*����% �� ����&����&��!���� � �������%�*���!� ������*�� $��� �� *��!��'� %������� �� *��� �� �%����� &� ��� �%� ! �� ���� �����$����� !�!$� ��$��� ��*��!;��,�� ��,���� ������*���*�� �&������$��� ��*��!� Y��������\���%�!�]�� ������&!�����������&��,�������������&������]��������� ���$����&;� !����&��&!�������%��!�$����!������� �&���������,��+�� �����,���&�����$�,�@��*�� ���%����������&� � �&�����;� !�*��%� ���� ���!����������%���&�!������ ���!�$!�

Field Development with5 vertical or deviated wells

Field Development with2 Horizontal Well

(a) (b)

Figure 10 Horizontal and vertical well drainage areas compared.

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2.5.3 The Well Productivity Improvement Factor�%�!� ����!&;�*������&���$��,���&]�J��!�&��&� !{

J

Q

P Phc

wf

=−( )

Where

Qhc�� �� },&�� �����?��&������� �� ���� �& �&����&�����!

_P = Average reservoir pressure in drainage volume of well

Pwf �� ������%���[�*������!!���� !��&� ��! ��& �����$�� !� P

?��&���$��,�+����$����� ����Y?+�\��!�&��&� !��%�� ��������%�%������� ��*������&���$��,���&]�YJH\����$��� ��*������&���$��,���&]�YJV\{

PIF

J

JH

V

Figure 11 shows the PIF value of a 500 m long well placed in a 15 m thick reservoir as a function of the kv/kh ratio. At low k~/kh values the horizontal well performs more poorly than a vertical well; while for k~/kh = 1 the horizontal well productivity is 4.3 times that of a vertical well.

0.001 0.01kv/kh

0.1 1

PIF

0

1

2

3

4

5

Centrally placed500 m horizontalwell in 15 m thickreservoir

Figure 11���%�?��&������+����$����� ����Y?+�\����� �%������� ��*��� !� �������������%�$��� �� �&�%������� ����� �����,�� ����Y@$>@%\�

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��[ \��������]���*����^��Horizontal well applications are summarised in Figure 12.

Increased Formation Exposure Lateral Connectivity Modified Drainage Geometry

Low permeabilty reservoirs

Viscous Oil

High permeability sands

Layered reservoirs

Natural fractures

Fault blocks /compartments

Hydraulic fractures

Reduced sand production

Enhanced gravity drainage

Vugular reservoirs Oil rim coning

Reduce surface footprint

Reduce number of wells

Figure 12 Horizontal well applications.

2.6.1 Increased Exposure to the Reservoir�%� ��� !� ��� �!�$����]��!��������!�����!� ��� �*��* ,!�� +�� �%�!%���� ����the production rate is higher and in the long term the cumulative production from a %������� ��*����!��� �����$���������!�$!����*�����%�!;��%����������*��!��=���&���� %�$� ���$���� � �����&������� �� �&���$�,�� ����*�������!!�

����!����$ ������%���� � & ���&��&� ��$�*���������% ���;����%������� ��*��!� ��� ����� �%��� ���&������ ������ �� ��� � ��,� $��� �� *��!�� �%� ?+��Y��������\�* !�����&����!%�*� ��������� ��&�!���������{

"� � ��,���¥�����%�%������� ��*��!������ �����!%�*&������� !�������&��������%���&;������!����@�,�?+�;�* !���*%����%�� �;���� $� �;�?+��* !����'�minority of wells showed a PIF greater than 20.

"� �%�%��%!��?+��!�*����!�$&�����%������� ��*��!����&�����$�!��!�Y% $,\������������ ��$�,�%��%���� �����,�! �&!� �&������*��!������*���� �����,���&!�*��%������ ��� ���� ����

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Institute of Petroleum Engineering, Heriot-Watt University 15

200

250

300

adapted from SPE 30745

150

100

50

00 4 62 8 12 1410 16 18 2220

203 Fields1,305 Wells

Num

ber

of W

ells

PIF

Mode

Mean

Log normal distribution

Figure 13��?��&������+����$����� ����&�!��������������%������� ��*��!

"� �������������!��%�*��������� ��������&�$�&� ��*��!�&����&���� �����%�� ����&���%�!�!!� ����� !����� ����&�$�&� ��*���!������� ��* !������Y���,������������&��!����&�&�*��%�����¥�����%���� !�������� �\�&!�����%��$� �����&����&��������&������&���������,����,���¥�������%���� !��������%�� �&���� ��������%�����!���!�*����� �&�*���+�

0

1,000

2,000

3,000

4,000

5,000

A B C D E F G H I J K L M

Well Number

Oil

Pro

duct

ion

b/d

Forecast

Actual

Adapted from SPE 30745

Figure 14 Performance of horizontal wells in one North Sea Field.

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A typical horizontal well initiallyproduces at 150 - 200 bbls/d andrecovers 150,000 - 200,000 bbls

A typical vertical well initiallyproduces at 40 - 60 bbls/d andrecovers 50,000 - 70,000 bbls

Pro

duct

ion

Rat

e bb

ls/d

ay

1000

100

10

1

Year 1 Year 2 Year 3 Year 4 Year 5

Horizontal Well Vertical Well

Figure 15����������;���� !&����&������� �����%������� ��*��!�&��$�!���� !&�reserves in a North American Field.

"� '!� ������ ��� !� �%� ����� �� ���&������ � �� �!� �%� ���� ��$� ��$�,;� ����!�$!;����*�����!�$����!���� ����� �&��%� ��,�*����!���!�!���!�� ����� !�����!�$!���� �&���� �$��� ��*�������_�����!� ���*���� ���¥������¥��&����������%����������*��!��=���&��^�� !�*%���%���� !&�early well production resulted in an increasing recovery is shown in Figure 15. �������� ��,;��%�!�� $��� ����!�����!����� �* ,!���!�$&������ ����+�#���%������ �;�%��%�*���� ��&�!������� �!� ���������� !&��!�$!�!�������=���!��%� �����,����� � ��Y��]��&\�]!!�$���[�]!����* ������� !� �������!� ������%�*������ !�*�����%�*���% !�������� �&;��=��������%������� �� �&��!�$������&�!�����������

2.6.2 Connection of Laterally Discontinuous Features� ��� ��,� �� ���&� �!�$���!���� ��� � ���$����!����%,&�� ����!���%�� ���]���� �����,� �!� ����� ���� ��*� ���� ����� �� ���&������ � �!�� }�*$�;� *��!�����!��������;�� ��� ���� ���!� �����&�� ��%��%�� �!�&������%���� ��� � ��������[�*���%!��� ���!� ������ ��,���!����$��� �����&����!�$���!��'�horizontal well aligned normal to the stress direction at the time of fracture creation % !� ���%������% ���������!������%��� ���!�Y�������� \�

�%�@,�� � �����!��%��� ����&�!��,��+���%��� ����&�!��,��!�!�������,�!� �!�it is unlikely that a vertical or deviated well will intersect a fracture. The horizontal *��� ����]��&&��������������!�!� �!������������������ ���!������$��%��=���&�*������&������� ��

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Figure 16(a)��~��� �� �&�%������� ��*��!������������ �������� ���!�

Fault

Reservoir 1

Reservoir 2

Figure 16(b)���!�$���!�!� � �&��,� �! ������ ���� �������&�&��,� �!�����%������� ��*���

�%�%������� ��*��� �� �!��������!�$!� ���&�������� �������@!���%��`��response while drilling the horizontal section may suddenly indicate a change from �!�$����������_�!�$����Y��������\���%�*�����!����*;�&��&��������%��,������ ���;���&���&���* �&!����&�*�* �&!���� �! �%������%��!�$��������&�=� ���,�!�!��� �&� ����&�!� �&��������%���&�!�!������ ��%�!���,� ���=���&�%����%��!�$���!�����%��*��� �������@!�� ,�% $�!����� ���,�&������������ ����!!��!�����%���!!��!�� ,�&�$���&������]����� ������� � ���������%���[�*�������%�!� � �����@!��!���� ������������*���� ,������� ��%��

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2.6.3 Changing the Drainage Geometry'�}������� ��*����!� ��,�% !� ��� ���?��&���$��,�+�&]��% �� �$��� ��*����}�;����� ���$�����&�����!�� �;��%���&� *&�*��*��������*�;�&� ,�����%���� %���������* ��&�[��&!�!�%� !�* ������� !���%�!��%��������!�����&���� !�����������vertical wells and cresting for horizontal wells. Figure 17a shows that the drawdown ��!���$�����%����, �,�����&������%�&��������&�!���!�������� �&�* ��������%�&�!����&�* ��_������� ������ %��%������������%�*���!������ �&�����$ ������ ��,;��%��� ����%�&�!� ������%�%������� ��*��� ��$��%� ̀��_^��_���� ���%��� ����%�&� *&�*�� ����*��%����* ������&��������

Water

Oil Oil

Original oil-water contact

New oil water contact

Figure 17(a) Water "coning" phenomena.

'�!���� ���%�������������*� ��&��!�����&� *!��%�� !�&�*����* �&!��%���������%������ �&�����$ ��Y���������\�

Gas Gas

Water Water

Gas

OilOil

Original gas oil contact

New Gas oil contact

Original oil - water contact

Figure 17(b) Gas "cusping" phenomena.

�%������¦!�<����!����&�&�*% ���%�!�&�!� ��!%���&�����%�!�&�!���� �������� ����� �����_�����!�$�����������%� !���� ����� $��� ����������,�� ���;�!�%� !������]�!�!����% $,������!�$���!��'�%�������!����_�����=���!��% ���%�%������� ��*������� &�� � ��������%�[��&���� �!� �� ������������!������*��%��!�������%�&���� ����!�$����&��$��% ��!��Y� !� ��]� �!������� =�������[�]\���������� � �&��������� !�!��%������,���� �* ������ �&� �* ����!����� �$��� �� �&�horizontal well respectively.

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Producing Wellbore

(a) Vertical Well (b) Horizontal Well

Water Cone

Water Crest

Figure 18��?��&��������&�&�* ���������Y$��� ��*��!\� �&��!�����Y%������� ��*��!\

2.6.4 Extending Field Appraisal Laterally�%��� &����� �� ���� %������&� ��� �! ��% !�������&�����Y�������\�$��� ��*��!� �&;��,��������� �&��!������%�;��������&���� ������� �� �&��!�$������&������!�����%���&�&$��������� ��������%�!����!!� ����]��&&�� �� ��,��!����%������� ��*��!��+�� ����!�� ��,���*��������&��� �����!�� ���� �%���� �!�*%���!�$����=� ���,�� ,�&�� &��$�� ��*�@������!��#] ���!����*%�� ��� �! ���,�%������� ��*��!������!� &$ �� �!� ���%{

"� +&���� ���������� ������*��@!�*��%� ������ �&������,�

"� ������ �������� ��� �! �� �&�&$���������<��$!�������*���

"� '��� �! ������ �,�� �������@!�*��%����*���

"� '�����,�������� �������!�$������������*��%�!��!�� ����� ��,��!����*%���%������!�$�����!�&����������� ���,�!�!���

2.7 Disadvantages of Horizontal Wells���� ���%���% !�!�% !��������%���!���$� !��!����%������� ��*��!��'!�]��&;��%�� �� �!��&�! &$ �� �!{

"� '�%��%��!��� �����&������������ �&�&�������� !!���,��!��=���&����!�!!����,�drill the horizontal well.

"� �%���!���������,&�!%���&� �!����%��%�,��� ��&���%�!� ����!�!�� ��,�to the directional drilling specialist.

"� }������� ��*��!�% $� ���*��&� *&�*�� �&�! �&�� �[��&���[�*�$����,��% ��$��� ��*��!;�%������������ ������!���*�����&���������%�!�% !���� &&�!!&��,�&$�����������&����_����[��&!��=������� ���*�&� *�&�*��for removal of the mudcake.

"� �%�������!�����*�������������;�������� �&�����$������ ������]��!�$�in a horizontal well.

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"� �%��!�>���&����&���� �%������� ��*����&�!� !��� ���%������� ��*���]������!������_������ �� ����� ����&�

�%� ��$�&�! &$ �� �!� �� ���������� �&��,����&��� ��������

2.8 The Economics of Horizontal Wells

2.8.1 CostsHorizontal wells normally take longer to drill than vertical wells in the same reservoir. �%,��=����%��%�!��� �����=������� �&�!�� ��!����!�������#]�����!%�*!��% ���%���!���*�*��!���� �%������� ��&�������� �� ���� ��$�,�]��!�$;����������!�&� ��,�% ��� !�����*��!� ��&����&����%��!������%����_%���!�����!%���&�have operating costs similar to a vertical well. The horizontal section will have additional �!�!��������$�������!��=���&��������&�������������;�!����� ���������!�� ������!�������&��������&�������!��� �������%� �&��%��&���������!��%�!�� �&�=�������

��_�������������`����������%�!� �& �&�������&������ �����,���&����!� ���!&�����*��������!����%!� �����?�!���~ ���Y�?~\;�?����_��_+�$!������ ����Y?+�\;�? ,� @����� �&��%��������!��[�*�� !&� �&�&��&� !������*!�Y�!������_� ]� ��� ����!�����!�������,\{

"� Net Present Value (NPV)

�%���������&��!�&�$�&&������ ������� ������&!� �&��%��*� !%�[�*�&�����&����� %�����&�������%����� !%����*�Y���\���������&�����Y����\��!�&��&� !��%��$�������!������% ������&�

NCFi���},&�� �����§� ����,¨?������ ��� ����!����^�� �������!�

The sum of the NCF for the period of the project is commonly referred to as Cumulative Cash Surplus or Ultimate Cash Surplus. The discount factor����� %�����&�Y&�\��!������&_, ��&�!�������� �� �&�!������ ��&¥���� ������!{

df

di i=+ −

11 100 1 2( / ) /

��!����&��?~Y&\��!��%��&��&� !{

NPV dNCF

dfNCF

dfNCF

df

NCFdf

i

i

N

( ) = + + +

= ∑

1

1

2

2

3

3

1

`%���!�����?~�����!������� ������=�������%��%�&�!������ �� �&��%������& ��Y�%�������������, ��������%� ��$�] ���\���

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Institute of Petroleum Engineering, Heriot-Watt University 21

NPV is the most direct and robust measure of value.

"� �����|��|`�����;���#����}�`#~

�%�?+���!�&��&� !{�Ultimate Cash Surplus Total Capital Expenditure

+���!���� ��,������ ������������!�&�!����&�=� �����!{

PIR d

NPV dCapex d

( )( )( )

`%��� �]Y&\��!��%���� ��� ��� ��#]��&�����&�!����&� ��&¥���� ���������%�! ��� ���� !��%��?~� ��$���

������������� �������������������������������������������������

"� Payback Time

�%�!��!��%����� ��*%�%��%����� ��$�����Y��&�!����&\���!������������� ��$�����������!���$�

���������� ������������������������������� �������������������������!���

"� Unit Cost of Production

Unit Cost-per-Barrel=Capex(d)+Opex(d)

Producttion(d)

Where Opex is the Operating Expenditure

�������������������������������������� �����������!��� �����������!�������� ���������"�����

�����!���� �&��������!�� �� ���� ���������%!�������� � ���!����%������� ��*��!�����������!%�*!��%���� !&�̀ ���?��&���$��,�+�&]��!�������������!�$������� �� %�$&��,�$��������%������� �� �&������_� �� ��*��!�����������!%�*!�%�*��%�!� ���*!� ���¥��&����������%�������!���=���&����&$��������� �����&������capacity.

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22

140

120

100

80

60

40

20

01.0 2.0 3.0 5.8 8.5 12.3

14

12

10

8

6

4

2

0

Pro

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ion

Rat

e M

BO

D

PI,

bbl/d

ay/p

si

Reservoir Contact, Km

PI, STBD/PsiRate, MBODPI, STBD/PsiRate, MBOD

Figure 19 Well Productivity Index and Production Rate increases �,�]��&&��!�$������� ����� ���&&��# !��������&�

1

1.2

1.0

0.8

0.6

0.4

0.2

0.0

2 3 4 5 6 7 8 9 10 11 12 13

Reservoir Contact, Km

Nor

mal

ized

Uni

t Cos

t($

/bbl

/day

of I

nitia

l Pro

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ion)

Figure 20���� !&������&$��������!��$!���!�$������� ����� ���&&��# !��������&�

3 MULTI-LATERAL WELLS

Q�% `������������&���������'������_�� �%�*����!�&��&� !�� �*���*%�%�% !������% �����$��� �;������&����%������� ��%���&����&������ �!�����!��� �&�����&�� @���� �!��������ª���%�¦�*�����������%�!�!��������!!���������_� �� �!�����*%�%��%��� �%!� ��%������� ��or close to horizontal in the reservoir.

The main reason for drilling a multi-lateral well is to increase the return on investment through improved reservoir drainage even though the initial well cost is higher. For example the reported reserves per multi-lateral ��� �%� '�!���� �% �@� Y�] !;� ��'\� % $� ��� �����&� ��� �� ���� ���!� �%�reserves per single lateral while the cost was 1.4 times that of a single lateral. �%��% !�����,���� �� ��&���� !�����%��!���������_� �� �!���%�!���� !�% !����&��$���,� �!����� ������������ ���� ����!� �&��%�*��!�% $�% &�$ ����!�

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Institute of Petroleum Engineering, Heriot-Watt University 23

�$�!����!��%�!�� ����� ��� �%���&!���;������!���������%���!�&�� @!� ���*��!�*%���%��� �%!����&����_���&�����!�� �&�!���$�,���%!��=������!�have encouraged the service companies to invest in new methods of drilling and completing multi-laterals. This particularly applied to the construction of the multi-lateral junction to achieve zonal isolation and allow re-entry.

The most common multi-lateral well has two or three laterals per well. They are often ����&������&!�*%��%������� ��*��!�*��!�!!���� �&�����%���!��! $���!����&���� &��,�% $�����*��*�����!����!��� ������������ ����������� �� �!������one multi-lateral well thus made sense.

Q�� @������`��������"�>���������� ���������U���|�������There are many constraints in multi-lateral well design related to the operation of !�&�� @������������%����� �,�*������ �&��%�!% ������%�� �����!�$���Y!\������] ���;��%����� �,�*������� ,����1/2�����%���*��%� ����������&� ����*%����%�!�&�� @�� ,���������%���*��%�=���� �!$������&� ����&������%�!� ���$��� ��&�!� ����*���%�<������� �&��%��!�$������%�� �� �!�� ,�% $�&�����������%!� �&�&���������������!� !� ��!�������!�%����������!�� ���!��+���%����� �,�*�������!�%��%�,�&$� �&��%���%� �����% ��!� � �������*���%�� �� �!�*�������!����&���%����!!���������_� �� ��*���&!�����������$��$!���� ����!���*��Y&������ �\�&�����!;�������!�!� �&��!�$���������!������ �! ��!� ���,�!���������!�����&�

� �,� � ���!� ��[��� �%� &�!���� ��� *%�%�� ��� &���,� � �����_� �� ��� �%,� �����!&�����*����]�!�������&!����������%���������% $�!���]��������%������� ��*��!�����%� � ��+��!��� !!;� �� �� �� ����&����&���� ��*�&���������� =����]���� ����> ��� �! ��& � � �&�&��&���������!�!�!!;���%������ ��&��������&�����>��<�������� � �&��&��

Q���%U���|������`�������������!>�#��������+���%�� �� �!� �������&����&�����%�! ���!�$���������������� ������!�$���!;���%�&� �� �� � !�*����$��� ��,��$�� ����%��!���������� ��&� �� �� � �*�������!!��% ���*���%�&� �� �� � ����� �!�����%������� ��� �� ��Y��������\��}�*$�;����� ��*� ��� �����,� �!�$���!� �%� �� �!���� ����&� � ,� � !�� ���� � ����� ���� �&�!����� ��� �� �����������&������*���� �� %�$&������ �����������!�reduce production.

No FlowBoundary

1 2

Production Time Increasing

Figure 21��+���������*��&� �� �� � �����%��*��� �� �!�

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24

Q����U���|������`�������������!>�^������%�! ���!!�!� ��!���� �$��� ��*���������_������ ������!�$���!�Y������� �!=������!� @&��!�$���!\��+�������*����� @��� �����%�*���������!!� �&� ������������!��!&�Y�������� \��+���!����������&&�����!� ������������&�������������������%��*���!�$���!� �����&���������!!���Y��!!�[�*\������reservoirs at the same pressure regime commingled production when producing dry ���� �!!��������������!!�!$��&������� ��&�������� @!��� �Y���������\����%� &$������* ���������� ,���� �!!� �� @���!!��������]����&����� ,����&������%�%��%��&�!��,�����%�[��&�����%�������� ��$�� ,����

1

2

WaterOWC

(a) (b)

1

2

Figure 22(a)�������_� �� �������������!�����%�*������� Figure 22(b) � ̀����� @�%����%� ���!��%������� ��

������%����!���� ������_�� �� ��*���

3.3 Impact on Recovery and Rate���������_� �� �!�!����,� �� �� �%����&����������&������ ��� !������ ����$�,���%�!� �������� ����� � !�*%���!�!� �&���!@!� ��%��%����*%���%�production rate from a single lateral is non-economic. Both acceleration and improved ��$�,�Y��������\��=���� ��������&�!� �&��������%�� ����!�������%�� �� �� �&�$��� ��[�*����%���!�������������%�� �� �!�����%��!�$����*���������� �� �&����� ,����!! �,�������$�&�����$��������!!�������!����� ���� ���!�$����� � �����

Multilateral

Multilateralwith early decline

Multilateral

Time

Single lateral

Single lateralor multilateralshowing early decline

Increased recovery

Pro

duct

ion

Rat

e

Cum

ulat

ive

Pro

duct

ion

or R

eser

ves

Time

Figure 23��#����������!���������_� �� �!

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Institute of Petroleum Engineering, Heriot-Watt University 25

Q�� `���������U��>�������������� �� �!� ��������� �&��,{

"� ^��%���!�&�� @!�&����&�*��%����*��%����*%��!��@�

"� ��������!�&�� @!������ � !&�*�����!�*��%� ����������*%��!��@�

"� ��������!�&�� @!��%����%��%��������*��%� �!� ���&� ����*%��!��@�

�%�� !����%�&��!��!&�������!�������� ���*��!���%����%�������;�!�&��� @���� ��������%��%������! ��� �����Y��������\��'�&�������������!������=���&�!����%�!� ����������&��,� ����&��������&�������������

Low PermeabilityHigh Oil Saturation

High PermeabilityLow Oil Saturation

Figure 24��� ������&��&$����������� ,�&��!�$���!�

Q�$������ �U���|���������;������

(a) Stacked trilateralin a multiple

layered reservoir(s)

(b) Planar trilateral ina single reservoir

(c) Planar opposed duallateral in a naturallyfractured formation

Figure 25 Multi-lateral well designs.

�%��%��� !��������!���������_� �� �!� �{

"� Stacked������� �����Y�������� \��!��!&�����&$������� ����_������ ����;�� ,�&��!�$�����+���!� �!���!������� �!������ !!�$;���*���� �����,��!�$����*%���%���!� ����������&������ �!�������&���������������������*���%�� �� �!����!�!����� ���

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26

"� Planar������� �����Y���������\��!��!&����� ��� ��,��� ���&��!�$���!�*%���%���!�!������� ���,� ������� ��������� ��������%��� �� �!� �� �� ���������«��!���!���� ���!���� �������!���������%��� ���!� �� �� !�� ��� ��������%������� ��*��;����!!��%�!� �� ��&�!��������������� ���!��!�$�,���!��&���

"� &��|� ����������� �����Y��������\�% !��%� &$ �� �������$�����%�� ��!��&� �� �� � ����� ���$������%����*������*��%� ����������������� ���%�heel of the well.

Q�[ \��������U���|������^��������;���!��>����Technical advantages of multi-laterals centre on greater reservoir exposure at a lower �!����%�����������!���������_� �� ��*��!� ��!�������%�� ���% ���%���&���������!��� �����%��!�$�������,�% !������&����&� �&� !&�����������_� �� �!� ��% $� �� <������ �����!%����,���� !�����%����&������ �&�� ,�!�����]��!������� %�!���� $ �� �������� ��]&��� ���������!��! ����� ���������_� �� �!��&���%� ��� ���!��!����%��!������� �����!� �&����� �!��!��� �&�����%����������!���!�� ���*����� ���� ����&!�������� �!����&����������� ��,�$� ���&$������!�

�%�! ������ ���������!%���&$������!��,��&������%�� &�!�������%�&���������� �����&�����% $�����*��*��!����� &�����!�!�*�������&�&�!����,��%����%�% $���� �!� �������������������!��� � �&��%��$��������*���������&��to the reduced impact of this smaller surface presence.

�%�� ��������&�! &$ �� �!��% ���&�����������!&� ���%��� ������!� ������!@��!���*����������� �&������ �!� �������������*��!���+���%������������%�� � ,� �� &&����� �� ��� ����� �!�!� &�� ��� ���� ����!� ��� �%� �!�$���� �&��% �� �������� ���^������%��� �%!�� ,�]�������� ����* ������� !��� @�%����%� �&��=���� �&�������!%��_������� �����

�����_� �� �!���� ��,��� ����� �����!@��� ̀�������$������*����������&������� �&��!�$��������������� �&�� � ������% ���=���!�!�%�����$�������!�������,������&����!�������������� �&������������������_� �� �!������&�!��*�&�������!����*���������� �&� �!�������� ������ �&�� ���������&�$�&� ���� �%!�

Q�[�%� ���������U���|������^���%�� ��������!� ���� ����!���������_� �� ��*��!��?���� ��] ���!�����&{

"� Viscous oil reservoirs�% $� ����&���$��,��% ���!;������� �;���!�� ��&��,� �������������,�� ���;�����Y?�� �����,>~�!�!��,����@>�\��!���*����%�!��!���� ��&;� �����*��%��%� !!�� �&�%��%�&� *&�*�!��,�� ]��������� �����]��!�����'%�$����������[�*� �!��=���!����%��� � �]��!��;�¬��������Y�\��� �%���% �� ����� !&����%���&� ������

"� Layered reservoirs� ����������,�]�����&��!�����%�!� @&������_� �� �������� ����� ¬������ ��Y \��� � �� ��!�� �� � @�� ��� $ �� �� �%� &��� ������� ���������%�� �� �!�����%�����������+���%���!!�������!� ��!����� ���,�&��������%������ ,����!! �,������!� ���!� � ��������!���� ��!� �������������*��%�&�*�%���[�*��������$ ��!�¬�������Y\���

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Institute of Petroleum Engineering, Heriot-Watt University 27

'+������@�����������������;�������#���������� ���%��Y��*���� �����,\� �&�� ��� ��,��� ���&��!�$���!� ����]�����&��!����

�� � �������� ����!�*��%��*���������� �� �!�������!&�¬�����!���Y�\� �&�Y��\�����������%�;����� ���&��!�$���!� ������������ �%!� ��$ ����!� ���!�*������ ������� ������� !�����%��!�$����]��!����!������$�,��������%�naturally fractured case it depends on how well the natural fracture orientation is known. If this orientation is relatively poorly known one could place laterals at &������� ���!;��!������%����&������� ����� %�� �� �����&������*%�%��!��%���!��� $��� �������� ������% ����!!!��%�� ]���������������� ���!�

' @����� and compartmentalised reservoirs are good candidates for multi-lateral ���� ����;�!�� ��,����!�������%���� �����!�% $��!�$!����*��%��$�� ��*%�%� ����&�$�&� ��*������&���<�!���&���+��&��������!�%�*��!;�@��*�&������%�� ������ ����!� �&�]��������&������������%�� ��������*������������ ���Y��������\���'�%��%_�!�������;����!�!���!��$,�*��%����&�*����������*����make well placement easier.

" Depleted or mature reservoirs� �� �&�& �!����������_� �� ��*��!;� ���� �����especially when the pace of development in the various zones is different. Figure ���!%�*!��*�����!;����*��%����&���� �����,;������*�����! ��� �����*%����%���%��% !� ���*����� �����,� �&� ��� �������! ��� ��������%�%��%���� �����,�� ,�� �����&��=����*����%����%� �$��� ��*�����������%���*���� �����,��!������!���&���� �%������� ��*��������%� ����!�������&����� � �������rates from each two lateral.

Q�[���U���|������^����; �'�� ����!����� $ �� ��� ��� �%� � !�� ����� % !� ��� ���$�&&� �,� �%� � � % &� � !���&�Y�����!���� �&���\���%�!���*���� �����,�� !���&����&�!�&�,�� !�������%��������&!�! �&!������%������ ��Y$��� �\�*�������%�!���&�* !�!����������%��*�*���&!�������@� &$ �� ������%��!�$���������,� !������*!{

"�� �%����%�;�%������� �;�*������* !��� &�����%�%��%����� �����,���! �&�<�!�� ��$��%�� !_ ̀��_���� ��Y��������\����%�!���� ���!�����]��&������$�&�������!�$����&�������&������%�!� ���!�������%� =�����

"� �%�� �� ������%���*���� �����,;��;�#� �&���! �&!��*��$� ���!���!% �&������� �������%�!�*��������� �����* !�%�!��� �!��������!� ������%��������$��� ����� �����,

"�� '�!�����<���������*���%��*��� �� �!�*��%������� ���!�� ��������&����!&� !����* !��� &�*��%����%��!�$����Y�����!���� �&���\�

"�� �%�?+������%������_� �� ��* !�¢������ �&�����%�$��� ��&�!�$�,�*���

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Zone FLateral

Horizontal Wellbore

Rot

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des

For

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ion

Top Carboniferous

Zone E

Zone D

Zone C

Zone B

-9,900

-9,800

-9,700

-9,585

GWC-9,500

-9,400

-9,300

-9,200

-9,100

Dep

th (

SS

TV

D)

Figure 26��� � % &���&��������_� �� ���� ����

41/2" Tubing

7" Liner Window 9703’

7" Liner Shoe 9900’

TD 13975’

TD 13743’

41/2" Slotted Liner

41/2" Liner Top 9800’

41/2" Slotted Liner

7" Liner

Gauge Mandrel 7150’

Casing Window 7560’

Openhole juncton high in reservoir

Openhole completion

abandoned pilot hole

Figure 27��� � % &������_� �� �������������

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