P1R8789A Well Completion & Workover Manual Volume1

WELL COMPLETION & WORKOVER MANUAL VOLUME 1 ● ● ● ● ● ● ● ● ● ● ● ●

LIST of CONTENTS (authors) Cap. 01 - Well Completion Design – M. Marangoni Cap. 02 - Material Selection - M. Marangoni Cap. 03 - Tubing Design - B. Maggioni Cap. 04 - Tubing Stress Analysis - B. Maggioni Cap. 05 - Packers - M. Marangoni Cap. 06 - Surface Wellhead - M. Marangoni Cap. 07 - Safety Valves and Miscellaneous - M. Marangoni Cap. 08 - Perforating - M. Marangoni Cap. 09 - Formation Damage - M. Viti Cap. 10 - Sand Control - M. Viti Cap. 11 - Workover - G. Treglia

ARPO

ORGANIZING DEPARTMENT

ENI S.p.A. Divisione Agip

TEAP

TYPE OF ACTIVITY'

ISSUING DEPT.

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1

DOC. TYPE

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TITLE Well Completion & Workover Manual Volume 1

DISTRIBUTION LIST TEAP STAP – Archive

LIST of CONTENTS (authors) Cap. 01 Cap. 02 Cap. 03 Cap. 04 Cap. 05 Cap. 06 Cap. 07 Cap. 08 Cap. 09 Cap. 10 Cap. 11

- Well Completion Design – M. Marangoni - Material Selection - M. Marangoni - Tubing Design - B. Maggioni - Tubing Stress Analysis - B. Maggioni - Packers - M. Marangoni - Surface Wellhead - M. Marangoni - Safety Valves and Miscellaneous - M. Marangoni - Perforating - M. Marangoni - Formation Damage - M. Viti - Sand Control - M. Viti - Workover - G. Treglia

Date of issue:

Issued by: S. Pilone Issued by

REVISIONS

10/03/99 See list 05/01/96 see list

10/03/99 M. Marangoni 05/01/96 M. Marangoni

10/03/99 A. Calderoni 05/01/96 A. Calderoni

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

ARPO

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General Index Chapter 1 - Completion Design

Teap-P-1-R-8790

1.1 General 1.2 Engineering Approach 1.2.1 Input Data 1.2.2 Output Results 1.3 Completion Configuration 1.3.1 Single Completion 1.3.2 Single Selective Completion 1.3.3 Dual Completion 1.3.4 ESP Completion 1.3.5 Gas Lift Completion 1.3.6 Beam Pump Completion 1.3.7 Slimhole 1.3.8 Intelligent Completion Chapter 2 - Material Selection

Teap-P-1-R-8791

2.1 Corrosion And Material Selection 2.1.1 Corrosion Mechanism 2.1.2 Hydrogen Sulphide (H2s) 2.1.3 Chloride Stress Corrosion 2.1.4 Dissolved Oxygen 2.1.5 Carbon Dioxide (Sweet Corrosion) 2.1.6 Corrosion/Erosion 2.1.7 Galvanic Corrosion 2.1.8 Crevice Corrosion 2.1.9 Corrosion Fatigue 2.1.10 Likelihood Of Corrosion Mechanism 2.2 Corrosion Evaluation 2.2.1 H2s Corrosion (Sulphide Stress Cracking - SSC) 2.2.2 CO2 And Cl- Corrosion 2.3 Material Selection 2.3.1 Octg Materials Tables 2.3.2 DHE Materials 2.3.4 Well Head & X-Tree Materials 2.4 Elastomers 2.4.1 Introduction 2.4.2 Definition Of Well Conditions 2.4.3 Effects Of Typical Downhole Environments 2.5 Properties Of Elastomers 2.5.1 Elastomer Types And Compounding 2.5.2 Classification Of Elastomers 2.6 Enviromental Resistance Of Elastomer Classes 2.6.1 Group 2 Elastomer (Medium Heat Resistance, Non Oil Resistant) 2.6.2 Group 4 Elastomer (General Purposes Oil Resistant) The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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2.6.3 Group 5 Elastomer (Heat And Oil Resistant) 2.6.4 Hard Polymer Material (For Back-Up Etc.) 2.7 Failure Mechanism 2.7.1 Extrusion Damage 2.7.2 Compression Set Failure 2.7.3 Explosive Decompression Damage 2.7.4 Wear 2.7.5 Chemical Degradation 2.7.6 Assembly Failure 2.8 Seal Selection 2.8.1 Completion Seals 2.8.2 Qualification 2.9 Material Selection Criteria 2.10 Practical Guidelines 2.11 References Chapter 3 - Tubing Design

Teap-P-1-R-8792

3.1 Introduction 3.2 Tubing Design Overview 3.3 Factor Influencing Well Completion Design 3.3.1 Reservoir Consideration 3.3.2 Mechanical Consideration 3.3.3 General Consideration 3.4 Literature And Reference Manuals 3.5 Tubing Sizing 3.5.1 Collection Of Fluid Properties 3.5.2 Collection Of Reservoir Data 3.5.3 Reservoir - Well System Analysis 3.5.4 Calculation Of Pressure And Temperature Gradient 3.5.5 Pressure Drop Correlation 3.5.6 Definition Of The Completion Strategy 3.5.7 Material Selection 3.5.8 Downhole Equipment Selection 3.5.9 Check Of Tubing Resistance 3.5.10 Check Of Particularly Conditions 3.6 Effect Of Variables Change On The Pressure Gradient Curves 3.7 Tubing Features 3.7.1 Tubing Characterisation 3.7.2 Tubing Steel Grades 3.7.3 Tubing Checks 3.8 Tubing Connector 3.8.1 Tubular Connections 3.8.2 Connection Descriptions 3.8.3 Threads 3.8.4 Seals 3.8.5 Connection Requirements 3.8.6 General Connection Selections 3.8.7 Agip Standard Joints Selection Criteria 3.9 Well Monitoring The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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3.10 Well Completion Design Example: Wakar Field 3.10.1 Introduction And Tubing Stress Analysis 3.10.2 Tubing Size And Material 3.11 Figures And Tables List Chapter 4 - Tubing Stress Analyses

Teap-P-1-R-8793

4.1 Tubing Stress Analysis Overview 4.2 Loading Mechanism 4.2.1 Load Case For Production & Injection Wells 4.2.2 Production Wells 4.2.3 Injection Wells 4.3 Length Variations 4.3.1 Hook’s Law 4.3.2 Buckling Effect 4.3.3 Ballooning Effect 4.3.4 Temperature Effect 4.4 Tubing Packer Connection Types 4.4.1 Slack-Off Or Pick-Up Effect 4.4.2 Packer Setting 4.5 Total Length Change 4.6 Tubing Packer & Packer Casing Force 4.6.1 Tubing To Casing Force 4.6.2 Packer To Casing Force 4.7 More About Helical Buckling 4.7.1 The Significance Of Buckling 4.8 Stress, Strain And Design Factors Definitions 4.8.1 Stress & Strain Definition 4.8.2 Axial Tension Design Factor 4.8.3 Burst Design Factor 4.8.4 Radial And Tangential Stresses 4.9 Triaxial Stress Design Factor 4.9.1 Von Mises Equivalent Stress Intensity 4.9.2 Effect Of Dimensional Tolerances Of VME Stress 4.9.3 Triaxial Load Capacity Diagram 4.10 Recommended Minimum Design Factor 4.11 Figures And Table List Chapter 5 - Packers

Teap-P-1-R-8794

5.1 General 5.2.1 Single Packer 5.2.2 Dual Packer 5.2.3 ESP Packer 5.3 Packer Setting Mechanism 5.3.1 Mechanical Set 5.3.2 Hydraulic Set 5.3.3 Hydrostatic Set 5.4 Packer Selection Criteria 5.4.1 Single Packer Selection Criteria The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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5.4.2 Single Packer 5.4.3 Packer Setting Method Selection 5.4.4 Tubing Packer Connection 5.4.5 Tubing-Packer Connection 5.5 Single Selective Completion Packer 5.5.1 Packer Type Selection 5.5.2 Packer Setting Methods Selection 5.5.3 Tubing-Packer Connection Selection Chapter 6 - Surface Wellheads

Teap-P-1-R-8795

6.1 General 6.2 Wellhead Configuration 6.2.1 Wellhead And Christmas Tree Ratings 6.2.2 Stacked Wellhead 6.2.3 Compact (Unitized) Wellheads 6.2.4 Quick Connection 6.3 Christmas Tree Configuration 6.3.1 Compact Tree 6.3.2 Splitted Tree 6.3.3 Composite Tree 6.4 Valve Configuration 6.4.1 Slab Gate 6.4.2 Expanding Gate 6.4.3 Actuators Configurations 6.4.4 Hydraulic 6.4.5 Pneumatic 6.5 Special Applications 6.6 Reference Specifications Chapter 7 - Safety Valves And Miscellaneous

Teap-P-1-R-8796

7.1 Safety System 7.1.1 General 7.2 Tubing Safety System 7.2.1 Valve Control System 7.2.2 Surface Controlled Valves 7.2.3 Flow Controlled Safety Valves 7.3 Valve Closure Mechanism 7.4 Safety Valve Configuration 7.5 Equalisation 7.6 Annular Safety System 7.7 Reference Standards 7.7.1 Standards 7.7.2 Operational Testing Frequency 7.8 Engineering Process For Selection Of The SCSSV 7.9 Downhole Safety Valves - Installation Guidelines 7.9.1 Applications 7.10 Valve Type

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Chapter 8 - Perforating

0 1 Teap-P-1-R-8797

8.1 Introduction 8.2 Gun System 8.2.1 Shaped Charge 8.2.2 Detonators 8.2.3 Previous API Test (Fourth Edition) 8.2.4 New API Tests (Fifth Edition)) 8.2.5 Gun Scallop 8.2.6 Clearance 8.2.7 Casing 8.2.8 Phasing And Spacing 8.3 Completion Techniques 8.3.1 Perforated Casing Completion 8.3.2 Factor Effecting Productivity 8.3.3 Formation Strength And Stress Conditions 8.3.4 Underbalance 8.4 Perforating Techniques 8.4.1 Through Tubing Perforating 8.4.2 Casing And High Shot Density Gun Perforating 8.4.3 Wireline And Tubing Conveyed Perforating 8.5 Safety And Operating Environment 8.5.1 Safety 8.5.2 Transportation 8.5.3 Wellsite 8.5.4 Stray Voltage Safety 8.5.5 High Temperature And Pressure 8.5.6 Fluid Chemical Properties 8.5.7 Mud Weight 8.5.8 Well Deviation 8.6 Wireline Throughout Tubing Guns 8.6.1 Gun Selection 8.6.2 Special Precautions 8.7 Wireline Casing Guns 8.7.1 Gun Selection 8.8 Operative Perforating Techniques 8.8.1 Wireline Perforating Techniques 8.8.2 TCP (Tubing Conveyed Perforating) Techniques Chapter 9 - Formation Damage

Teap-P-1-R-8798

9.1 Introduction 9.1.1 Significance Of Formation Damage 9.1.2 Basic Cause Of Damage 9.1.3 Plugging Associated With Fluid Filtrate 9.1.4 Classification Of Damage Mechanism 9.2 Damage Reduction 9.3 Formation Clays (Inherent Particles) 9.3.1 Occurrence Of Clays 9.3.2 Clay Migration The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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9.3.3 Clay Structure 9.3.4 Effect Of Water 9.4 Asphaltene Plugging 9.5 Reduced Relative Permeability 9.6 Increased Fluid Viscosity 9.7 Diagnosis Of Formation Damage 9.8 Surtfactants For Well Treatments 9.8.1 Characteristics Surfactants 9.8.2 Wettability 9.8.3 Mechanism Of Emulsion 9.8.4 Formation Damage Susceptible To Surfactant Treatment 9.8.5 Water Blocks 9.8.6 Emulsion Block 9.8.7 Particles Block 9.8.8 Susceptibility To Surfactant Related Damage 9.8.9 Preventing Or Removing Damage 9.8.10 Selection Of An Emulsion Braking Surfactant 9.8.11 Requirements For Well Treating Surfactants 9.8.12 Well Stimulation With Surfactants 9.9 Acidizing 9.9.1 Acids Used In Well Stimulation 9.9.2 Acid Additives 9.9.3 Carbonate Acidizing 9.9.4 Factors Controlling Acid Reaction Rate 9.9.5 Retardation Of Acid 9.9.6 Acidizing Techniques For Carbonate Formation 9.9.7 Matrix Acidizing Carbonate Formations 9.9.8 Fracture Etching In Homogeneous Carbonates 9.9.9 Summary Of Use Of High Strength Acid 9.9.10 Sandstone Acidizing 9.9.11 Planning HF Acid Stimulation 9.9.12 Additives For Sandstone Acidizing 9.9.13 Clay Stabilisation 9.9.14 Preflush For Sandstone Acidizing Of Oil Wells 9.9.15 HF-HCl Acid Treatment For Oil Wells 9.9.16 Stimulation Of Gas Wells, Gas Injection Wells And Water Injection Wells 9.9.17 In Situ HF Generating System (Sgma-20) 9.9.18 Clay Acid 9.9.19 Potential Safety Hazard In Acidizing 9.10 Scale Deposition, Removal And Prevention 9.10.1 Introduction 9.10.2 Loss Of Profit 9.10.3 Causes Of Scale Deposition 9.10.4 Prediction And Identification Of Scale 9.10.5 Identification Of Scale 9.10.6 Scale Removal 9.10.7 Scale Prevention 9.11 Conclusion

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Chapter 10 - Sand Control & Gravel Pack

0 1 Teap-P-1-R-8799

10.1 Introduction 10.2 Reason For Sand Control 10.3 How Or When To Decide The Sand Control Need 10.4 Sand Control Mechanism 10.5 Mechanical Method Of Sand Control 10.6 Development Of Design Criteria 10.7 Screen Slot Size 10.8 Gravel Size To Control Sand 10.9 Thickness Of The Gravel Pack 10.9.1 Fluctuating Flow Rate 10.9.2 Mixing Of Gravel With Sand 10.10 Practical Consideration In Gravel Pack Packing 10.10.1 Gravel Selection 10.11 Quality Control 10.11.1 Screens And Liner Considerations 10.11.2 Gravel Packing Fluid 10.12 Fluid Density 10.12.1 Viscous Water Fluids 10.13 Inside Casing Gravel Pack Technique 10.14 Open Hole Gravel Pack Techniques 10.15 Putting Well On Production Is A Critical Point 10.15.1 Life Of Gravel Pack 10.15.2 Use Of Screen Or Liner Without Gravel Pack 10.16 Resin Consolidation Methods Of Sand Control 10.16.1 Theory Of Resin Consolidation 10.16.2 Resin Consolidation Advantages 10.16.3 Resin Sand Pack System 10.16.4 Resin Process 10.17 Comparison Of Sand Control Method Summary Chapter 11 - Workover

Teap-P-1-R-8800

11.1 General 11.2 Conditions Requiring Workover 11.2 .1 Mechanical Problems 11.2.2 Reservoir Problems 11.2.3 Well Conversion 11.3 Workover Planning 11.3.1 Type Of Possible Workover 11.3.2 Well Analysis 11.3.3 Economics 11.4 Well Operations 11.4.1 Well Killing 11.4.2 Fluid Loss Control 11.4.3 Temporary Plugging Pills 11.4.4 X-Tree Removal 11.4.5 Completion Pull Out 11.4.6 Partialization Level Change The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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11.4.7 Fishing And Milling 11.4.8 Enclosure A - SPE 22825 - Thru Tubing Inflatable Workover System

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ENI S.p.A. Divisione Agip

ORGANIZING DEPARTMENT

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ISSUING DEPT.

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TITLE Well Completion & Workover Course

Volume 1

CHAPTER 1 -WELL COMPLETIO DESIGN DISTRIBUTION LIST TEAP STAP – Archive

LIST of CONTENTS (authors) Cap. 01 Cap. 02 Cap. 03 Cap. 04 Cap. 05 Cap. 06 Cap. 07 Cap. 08 Cap. 09 Cap. 10 Cap. 11

- Well Completion Design – M. Marangoni - Material Selection - M. Marangoni - Tubing Design - B. Maggioni - Tubing Stress Analysis - B. Maggioni - Packers - M. Marangoni - Surface Wellhead - M. Marangoni - Safety Valves and Miscellaneous - M. Marangoni - Perforating - M. Marangoni - Formation Damage - M. Viti - Sand Control - M. Viti - Workover - G. Treglia

Date of issue:

Issued by: S. Pilone Issued by

REVISIONS

10/03/1999 see list 28/01/98 see list

10/03/1999 M. Marangoni 28/01/98 M. Marangoni

10/03/1999 A. Calderoni 28/01/98 A. Calderoni

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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INDEX 1. COMPLETION DESIGN ..................................................................................................................3 1.1 GENERAL .................................................................................................................................3 1.2 ENGINEERING APPROACH .....................................................................................................3 1.2.1 INPUT DATA....................................................................................................................3 1.2.2 OUTPUT RESULTS .........................................................................................................4 1.3 COMPLETION CONFIGURATIONS ..........................................................................................4 1.3.1 SINGLE COMPLETION....................................................................................................5 1.3.2 SINGLE SELECTIVE COMPLETION ...............................................................................8 1.3.3 DUAL COMPLETION .....................................................................................................11 1.3.4 ESP COMPLETION .......................................................................................................18 1.3.5 GAS LIFT COMPLETION...............................................................................................20 1.3.6 BEAN PUMP COMPLETION..........................................................................................21 1.3.7 SLIMHOLE .....................................................................................................................24 1.3.8 (FUTURE) INTELLIGENT COMPLETION ......................................................................25

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COMPLETION DESIGN

GENERAL

Well Completion Design is a very important activity in the Upstream Engineering part of the Hydrocarbon exploitation which interfaces the ‘Sand Face’ of the reservoir with the ‘Topside Facilities’ to the ‘Production Network’. Generally speaking the activity itself is a part of the well design and sequentially follows the Drilling Engineering side of it. In real terms it is an integrated activity which deals with ‘Drilling Engineering’ from day one of well design and in most cases fixes the ‘Statement of Requirements’ for the overall well configuration setting geometrical constraints also for the Drilling Engineer.

1.2

ENGINEERING APPROACH

1.2.1

INPUT DATA

A series of ‘Input Data’ are required to perform the activity and the better the data the more detailed the design output will be. Having established the downhole interface being the Reservoir, the first set of input data required is the ‘Reservoir Development Study’ which should be completed with Individual Wells Fluid Rates(Oil, Gas, Condensate) and Water Cut versus each individual well life. Also very important is the individual well Flowing Bottom Hole Pressure, Static Bottom Hole Reservoir Pressure/Temperature versus field life and individual well Minimum Required Wellhead Flowing Pressure to verify the need of ‘Artificial Lift’ throughout the field life. The bottom hole data can sometime be substituted by Productivity Index in which case this need to be specified for the fluid it is related to. Most of above data comes from Agip Reservoir Department, while Minimum Flowing Wellhead Pressure are fixed by Agip Topside Engineering Department. The second set of data is relevant to the Reservoir Rock Mechanics and Geophysics to determine better development schemes in terms of Sand Control if necessary, of Development Scheme if formation has good porosity and permeability by its own or if the development needs to consider possible Stimulation/Fracturing to be economically done. These data generally comes from Agip Laboratories from Core Evaluation studies or from specifically required analysis; from these set of data/studies, information are derived also for better selection of drilling/completion/packer fluids. The third fundamental set of input data comes also from Agip Laboratories and is related to fluid characterisation. These data are Pressure, Volume, Temperature (PVT) Reports and are relevant to the analysis done on fluids produced and sampled according to “Agip Minimum Requirements” during exploration and appraisal well testing. Data are complemented with Fluids Composition Analysis and other specific reports (especially for Oil Wells) which identify the possible presence of Aspahltenes, Paraffin or other products (Elemental Sulphur); these products, together with the presence of Hydrogen Sulphide and Carbon Dioxide can have a heavy impact on downhole tubular and equipment metallurgy (corrosion problems) and/or configuration (injection of inhibitors, solvents, depressant).

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In particular to correctly evaluate corrosion it is fundamental to have available an accurate Formation Water Analysis. This seems quite obvious but it is generally very difficult to have since during exploration/appraisal well testing it is judged too expensive to make specific tests for sampling formation water, which instead is very important also for water flooding compatibility studies (scale formation). Corrosion evaluation is generally done as a first screening within Agip Completion department; final studies are issued by Agip Corrosion Department. The last set of data comes from Agip Drilling Department and is relevant to the well configuration; nonetheless, as already said, these data can result from an iterative process between Well Completion and Drilling to determine the best geometrical combination of casing profiles which satisfies the Safety during drilling and Safety Requirements of an economically sound completion configuration. Not coming as set of data but acting to impact on design are Local Set of Legislation and Regulations in terms of Safety and Environment, which shall be taken in due account during design.

1.2.2

OUTPUT RESULTS

The output of the Well Completion Engineering Design in its most comprehensive form is usually a report including: - Corrosive Environment Evaluation - Material Selection (C.R.A., Elastomers etc.) - Tubing Size Selection (P&T profiles Vs rates) - Downhole Completion Configuration - Tubing Stress Analysis - Perforating Methods Selection - Completion/Packer Fluids Selection - Stimulation Recommended Techniques - List of Downhole Equipment with relevant Purchase Specifications - Wellhead Selection and Specification (only Surface Installations) - Installation Procedures Depending on ‘Clients’ requirements only part of above mentioned issues can form the final report. Following chapter will deal in more details with individual topics listed in the last paragraph.

1.3

COMPLETION CONFIGURATIONS

With the objective of designing a completion which could satisfy all above requirements in an economical and safe way, different configurations can be identified and are here following illustrated based on Agip world wide experience: they will not be explained in detail at this stage but their characteristics will become clear the deeper will be the growing knowledge of the matter.

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SINGLE COMPLETION a. cased hole (Toni subsea) b. HP/HT (Bouri Field)

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Cased Hole Single Completion: Toni subsea Tubing Hanger Control Line Flow coupling

SCSSV - Surface Controlled Subsurface Safety Valve Tubing 4 1/2" 12,6 lbs/ft 25% Cr

Special clearance Pup Joint Downhole gauge mandrel

Chemical injection mandrel

Flow coupling Seating nipple X -Over Anchor 7" Straight pull shear release Production packer - 7" retrievable

Flow coupling Seating nipple

Wireline entry guide

a. cased hole (Toni subsea)

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HP/HT Single Completion: Bouri Field Tubing Hanger 7" OD Casing 29 lbs/ft ( Drift = 6.059" ) SM - 2535 Size 3 1/2" pup joint SM - 2535 Size 3 1/2" OD 9.20 lbs/ft tubing joint SM - 2535 Size 3 1/2" pup joint Flow coupling Wire line Ret. Safety Valve SCSSV Flow coupling SM - 2535 Size 3 1/2" pup joint SM - 2535 Size 3 1/2" OD 9.20 lbs/ft tubing joint SM - 2535 Size 3 1/2" pup joint CB1 Sleeding Sleeve SM - 2535 Size 3 1/2" pup joint SM - 2535 Size 3 1/2" pup joint

Polished Bore Receptacle

SM - 2535 Size 3 1/2" pup joint N22 - S Anchor Seal Assembly Retainer Hydr. Packer Mill Out Extension SM - 2535 Size 3 1/2" pup joint Seating nipple Size 3 1/2" Perforated Spacer Tube Bottom NO-GO Seating Nipple SM - 2535 Size 3 1/2" pup joint Wireline entry guide

b.

HP/HT Well: Bouri Field

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SINGLE SELECTIVE COMPLETION a. open hole (Horizontal) b. cased hole W/Wout Gravel Pack

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Tubing Hanger 9" Monel K con 2 control line Metal Seal

Control line 1/4" SS incapsulata Flow Coupling 4 1/2"

SCSSV 4 1/2"

MONTE ALPI 5 FIELD: Open Hole

Tubing 4 1/2" 12.75 lb/ft 11500 lbs Dplex 25% Cr Clampe per doppia control line incapsulata Tubing 4 1/2" 12.75 lb/ft T95 rivestiti int. con resine epossidiche TK236 Cross Over 4 1/2" PJD-CB box up x 4 1/2" PJD-CB pin down Side Pocket Mandrel Completo di injection valve H2S service 4 1/2" New Vam PJD-CB box up x 4 1/2" PJD-CB pin down

Hydraulic Set Retrievable Packer - H2S Service 5" Vam thread pin down

Millout Extension 5" Vam pin x box

Cross Over 5" box up x 4 1/2" PJD-CB pin down AR Landing Nipple H2S ser. - Utilizzabile come Equalizing Check Valve per fissaggio packer e Lock Mandrel per sospendere Tubing perf. e 2 Memory Gauges Tbg. Perf. 2 3/8" con fil. cilindrica per conn. a Lock Mandrel e chiuso sotto con attacco a Memory Gauges N° 2 Memory Gauges

Tubing 4 1/2" 12.75 lb/ft T95 rivestiti int. con resine epossidiche TK236

Horizontal Section

Liner Hanger Hydraulic flex lock 5"

Liner 4 1/2" C75 12.6 lb/ft fil. Vam con finestratura a slot sotto scarpa da 7" e con un tubo blank sopra sotto ECP per fissaggio Inflatable Packer in caso di stimolazione selettiva

a. Open Hole: Monte Alpi 5 Field The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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Gravel Pack Packer

Screen

Gravel Pack Packer

Screen

Sump Packer

b. Cased Hole With Gravel Pack

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DUAL COMPLETION a. selective Without Gravel Pack (Monte Stillo 23) b. selective With Gravel Pack (Zatchi Field) c. selective Without Gravel Pack (Zatchi Field) d. single string completion with chemical injection (BRN) e. dual string completion with chemical injection (BRN) f. HP/HT (Villafortuna)

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IDENTIFICATION CODE

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Tubing Hanger 2 3/8" EU up 2 3/8" down - BPV 2" TSB Nipples 2 3/8 " Flow Coupling 2 3/8" ipj P105 Box*Pin TRSSSV - Flapper type IPJ Flow Coupling 2 3/8" ipj P105 Box*Pin

Nipples 2 3/8 " Flow Coupling 2 3/8" ipj P105 Box*Pin TRSSSV - Flapper type IPJ Flow Coupling 2 3/8" ipj P105 Box*Pin Tubing 2 3/8" AMS N80 4.6 lbs/ft

Flow Coupling 2 3/8" ipj P105 Box*Pin Landing Nipples X 1.875 2 3/8" AMS P105

Flow Coupling 2 3/8" IPJ P105 Box*Pin Landing Nipples X 1.875 2 3/8" AMS P105 TBG/Sub size 2" 68 Fil. 2 3/8" AMS box Packer "RDH" 7" 23/29 # pin down 2 3/8" AMS Telescopic Joint SSD 1.875" AMS P105 Blast Joint 2 3/8" IPJ P105 Landing Nipples X 1.875 2 3/8" AMS P105 T/Sub W/Shear out 2" 3/8 A. box

Packer "RDH" 7" 23/29 # pin down 2 3/8" AMS

Telescopic Joint SSD 1.875" AMS P105 Blast Joint 2 3/8" IPJ P105

T/Sub W/Shear out 2" 3/8 A. box Packer "RDH" 7" 23/29 # pin down 2 3/8" AMS

Landing Nipple F AMS P105 N80 4.6 #

Tubing perforated 2 3/8" AMS N80 4.6 # Production Tube 2 3/8" AMS N80 W/L Mule/Shoe

a. Selective Without Gravel Pack (Montestillo 23) The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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IDENTIFICATION CODE

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b. selective With Gravel Pack (Zatchi Field) 1-water injection wells dual string and dual stage gravel pack

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Zatchi Field water injection dual string completion

c. selective Without Gravel Pack (Zatchi Field) The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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Single string Completion 3" 1/2 with 1.315" injection line Bir Rebaa Nord

Control Line

Tubing 3" 1/2 13% Cr

SCSSV - Surface Controlled Subsurface Safety Valve

Water injection line size 1.315"

Casing 9" 5/8

Side pocket mandrel with injection safety valve

7" retrievable dual packer

Casing 7"

Perforated Tube Seating nipple

d. single string completion with chemical injection (BRN ) The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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IDENTIFICATION CODE

Tbg Retrievable SV

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Adjustable Union Tbg Retrievable SV Tbg 7/8" Tripple string ret. packer

Side Pocket MAndrel with Inj. Safety VAlve

7" retrievable Dual Packer

Water Inj. Line 1.135"

e. dual string completion with chemical injection (BRN)

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Tbg 2 3/8" Tbg 2 3/8" Model "FVHDM" TRSCCCCV Model "FVHDM" TRSCCCCV

Parralel Flow Head

Sab Packer

Production Port Mechanism

Blast Joint

Sab Packer

f. HP/HT (Villafortuna) The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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ESP COMPLETION a. with Gas Venting, without Gas Venting, packerless b. proposed completion for Zatchi Connector

Splice

Connector

Connector

Splice

Splice

Packer with vent valve

Penetrator

Splice

Splice

Round to Flat Splice

Round to Flat Splice

Packer

ESP

ESP

ESP

VENTED

VENTED

UNVENTED

a. Gas Venting, Packer less, without Gas Venting,

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IDENTIFICATION CODE

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Tbg 2 7/8"

Packer with gas venting

Nipple

DPPT Circ. Valve

ESP with rotary gas separator

b. proposed completion for Zatchi

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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GAS LIFT COMPLETION Tubing Hanger

adjustable spacer sub 2 3/8" rotational alignment sub 5 1/2"

TRSSSV

TRSSSV

Parallel Flowhead

Gas Lift Mandrel

Gas Lift Mandrel

Gas Lift Mandrel

Gas Lift Mandrel Tie Back Packer Chemical Inj. Nipple

Sliding Sleeve

Production Packer

a. Tiffany The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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BEAN PUMP COMPLETION a. Torrente Tona • well head (1) • completion design (1)

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Polisched Rod

Polisched Rod

BOP for Polisched Rod

Riser Pup Joint

BOP for Polisched Rod

Top Adapter Top Adapter

Torrente Tona - well head (1)

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TEAP-P-1-R-8790 Dual Completion selective: Torrente Tona 17 Nipples 2 3/8 "

Tubing Hanger 3 1/2" EU Up*IPJ Down - BPV 3" TSB Nipples 3 1/2" Up*M 2 7/8" IPJ Down Tubing 2 7/8" IPJ J55 6.5 lb/ft Flow Coupling

Flow Coupling Injection Ava Injection Ava

Landning Nipple S2 Landning Nipple S2

Special Packer Anchor

Packer A5 51B 9 5/8"

Telescopic Joint Tubing 2 7/8" IPJ J55 6.5 lb/ft Circulating valve XA

Shear Out S.J.

Shear Out Safety Joint

Packer A5 51B 9 5/8"

Blast Joint Circulating valve XA

Landing Nipple F Tubing perforated Production Tube 2 7/8" NU

Packer FH 51A4 9 5/8"

Circulating valve XA

Packer FH 51A4 9 5/8"

CSG 9 5/8" 40 lb/ft J55 Landing Nipple F Production Tube 2 7/8" NU

Bean Pump Completion - Torrente Tona - completion design (1)

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1. .7

SLIMHOLE Coil Tubing single completion

CT - Single Completion

Casing 5"

Tbg 1.9"

Control Line 1/4"

Safety nipple 5"x 3.81" with SCSSV

Coiled Tbg 2"

Landing Nipple Casing 3 1/5" a.

It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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(FUTURE) INTELLIGENT COMPLETION a. Aquila

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ORGANIZING DEPARTMENT

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

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8791

TITLE Well Completion & Workover Course

Volume 1

CHAPTER 2 - MATERIAL SELECTION DISTRIBUTION LIST TEAP STAP – Archive

LIST of CONTENTS (authors) Cap. 01 Cap. 02 Cap. 03 Cap. 04 Cap. 05 Cap. 06 Cap. 07 Cap. 08 Cap. 09 Cap. 10 Cap. 11

- Well Completion Design - M. Marangoni - Material Selection - M. Marangoni - Tubing Design - B. Maggioni - Tubing Stress Analysis - B. Maggioni - Packers - M. Marangoni - Surface Wellhead - M. Marangoni - Safety Valves and Miscellaneous - M. Marangoni - Perforating - M. Marangoni - Formation Damage - M. Viti - Sand Control - M. Viti - Workover - G. Treglia

Date of issue: „ ƒ ‚ •

Issued by: S. Pilone

€

Issued by

REVISIONS

10/03/1999 See list 05/01/1996 see list

10/03/1999 M. Marangoni 05/01/1996 M. Marangoni

10/03/1999 A. Calderoni 05/01/1996 A. Calderoni

PREP'D

CHK'D

APPR'D

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INDEX 2. MATERIAL SELECTION.................................................................................................................4 2.1 CORROSION AND MATERIAL SELECTION...............................................................................4 2.1.1 CORROSION MECHANISMS..................................................................................................4 2.1.1.1 TYPE OF CORROSION ......................................................................................................4 2.1.2 HYDROGEN SULPHIDE (H2S)................................................................................................4 2.1.2.1 CORROSION OF IRON TO IRON SULPHIDE ...................................................................5 2.1.2.2 HYROGEN EMBRITTLEMENT...........................................................................................5 2.1.2.3 SULPHIDE STRESS CORROSION CRACKING ................................................................5 2.1.3 CHLORIDE STRESS CORROSION ........................................................................................6 2.1.4 DISSOLVED OXYGEN...........................................................................................................6 2.1.5 CARBON DIOXIDE (SWEET CORROSION)...........................................................................7 2.1.6 CORROSION / EROSION ......................................................................................................7 2.1.7 GALVANIC CORROSION .......................................................................................................8 2.1.8 CREVICE CORROSION.........................................................................................................8 2.1.9 CORROSION FATIGUE .........................................................................................................8 2.1.10 LIKELIHOOD OF CORROSION MECHANISM.....................................................................9 2.2 CORROSION EVALUATION.....................................................................................................10 2.2.1 H2S CORROSION (SULFIDE STRESS CRACKING - S.S.C.)..............................................10 2.2.1.1 OIL AND GAS & CONDENSATE WELLS .........................................................................10 2.2.1.2 OIL WELL..........................................................................................................................11 2.2.1.2.1 UNDER-SATURATED OIL WELLS .............................................................................11 2.2.2 CO2 E CL- CORROSION ......................................................................................................16 2.2.2.1 GAS OR GAS & CONDENSATE WELLS.........................................................................16 2.2.2.2 OIL WELLS ......................................................................................................................16 2.2.2.2.1 UNDER-SATURATED OIL WELLS .............................................................................16 2.2.2.2.2 OVERSATURATED OIL WELLS.................................................................................17 2.2.2.3 H2S , CO2 AND CL- CORROSION ...................................................................................18 2.3 MATERIAL SELECTION............................................................................................................19 2.3.1.1 O.C.T.G MATERIALS TABLES ........................................................................................19 2.3.1.1.1 OCTG MATERIALS - ONLY H2S IN OIL WELLS..........................................................19 2.3.1.1.2 OCTG MATERIALS - ONLY H2S IN GAS AND/OR GAS CONDENSATE WELLS ......20 2.3.1.1.3 OCTG MATREIALS - ONLY CO2 AND CL- WELLS ...................................................20 2.3.1.1.4 OCTG IN H2S , CO2 AND CL- WELLS .......................................................................21 2.3.1.2 DHE MATERIALS..............................................................................................................21 2.3.1.2.1 DHE MATERIALS - ONLY H2S IN OIL WELLS.............................................................22 2.3.1.2.2 DHE MATERIALS - ONLY H2S IN GAS WELLS...........................................................22 2.3.1.2.3 DHE MATERIALS - ONLY CO2 AND CL- WELLS ......................................................22 2.3.1.2.4 DHE MATERIALS - H2S, CO2 AND CL- WELLS.........................................................22 2.3.1.3 WELL HEAD & XMAS TREE MATERIALS........................................................................24 2.3.1.3.1 WELL HEAD & XMAS TREE MATERIALS - ONLY H2S IN OIL WELLS ......................24 2.3.1.3.2 WELL HEAD & XMAS TREE MATERIALS - ONLY CO2 AND CL- WELLS ................25 2.3.1.3.3 WELL HEAD & XMAS TREE MATERIALS - H2S, CO2 AND CL- ..............................26 The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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2.4 FIGURE 3. DIAGRAM MATERIAL FOR D.H.E...........................................................................30 2.4 ELASTOMERS ........................................................................................................................31 2.4.1 INTRODUCTION ...................................................................................................................31 2.4.2 DEFINITION OF WELL CONDITIONS ..................................................................................32 2.4.3 EFFECTS OF TYPICAL DOWNHOLE ENVIRONMENTS ....................................................32 2.4.3.1 PRODUCED FLUIDS .......................................................................................................32 2.4.3.2 TEMPERATURE AND PRESSURE..................................................................................33 2.4.3.3 CORROSION AND SCALE ..............................................................................................33 2.4.3.4 CONTROL LINE FLUIDS..................................................................................................33 2.4.3.5 COMPLETION FLUIDS ....................................................................................................33 2.4.3.6 ACIDS AND CHEMICALS ................................................................................................33 2.5 PROPERTIES OF ELASTOMERS.............................................................................................34 2.5.1 ELASTOMER TYPES AND COMPOUNDING ......................................................................34 2.5.2 CLASSIFICATION OF ELASTOMERS .................................................................................37 2.6 ENVIRONMENTAL RESISTANCE OF ELASTOMER CLASSES .............................................39 2.6.1 GROUP 2 ELASTOMERS (MEDIUM HEAT RESISTANCE, NON OIL RESISTANT) ............39 2.6.1.1 EPDM- ETHYLENE-PROPYLENE-DIENE (NORDEL) .....................................................39 2.6.2 GROUP 4 ELASTOMERS (GENERAL PURPOSES OIL RESISTANT) ...............................39 2.6.2.1 CR-POLYCHLOROPRENE (NEOPRENE) ........................................................................39 2.6.2.2 NBR - ACRYLONITRILE-BUTADIENE RUBBER (NITRILE RUBBER) .............................40 2.6.2.3 HNBR - HYDROGENATED NITRILE RUBBER (THERBAN)............................................41 2.6.2.4 CO AND ECO EPICHLOROHYDRIN HOMO-AND COPOLYMERS (HYDRIN) ................42 2.6.3 GROUP 5 ELASTOMERS (HEAT AND OIL RESISTANT) ...................................................42 2.6.3.1 FKM FLUOROELASTOMER (VITONS)............................................................................42 2.6.3.2 FCM TETRAFLUOROETHYLENE - PROPYLENE COPOLYMER (AFLAS).....................43 2.6.3.2.1 FFKM PERFLUOROELASTOMER (KALREZ)............................................................44 2.6.4 HARD POLYMER MATERIALS (FOR BACK-UPS ETC) ......................................................45 2.6.4.1 PEEK POLYETHERETHERKETONE (PEEK)..................................................................45 2.6.4.2 FPM FLUOROCARBON POLYMERS (TEFLON PTFE ETC)..........................................45 2.6.4.3 PPS POLYPHENYLENE SULPHIDE (RYTON}................................................................46 2.7 FAILURE MECHANISM............................................................................................................46 2.7.1 EXTRUSION DAMAGE ........................................................................................................47 2.7.2 COMPRESSION SET FAILURE...........................................................................................48 2.7.3 EXPLOSIVE DECOMPRESSION DAMAGE .........................................................................49 2.7.4 WEAR ..................................................................................................................................49 2.7.5 CHEMICAL DEGRADATION .................................................................................................50 2.7.6 ASSEMBLY FAILURE ...........................................................................................................50 2.8 SEALS SELECTION ..................................................................................................................51 2.8.1 COMPLETION SEALS .........................................................................................................51 2.8.2 QUALIFICATION ...................................................................................................................51 2.9 MATERIAL SELECTION CRITERIA ..........................................................................................52 2.10 PRACTICAL GUIDELINES .....................................................................................................55 2.11 REFERENCES.........................................................................................................................56

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MATERIAL SELECTION

2.1

CORROSION AND MATERIAL SELECTION

2.1.1

CORROSION MECHANISMS

2.1.1.1

TYPE OF CORROSION

0 1

In selecting the appropriate materials, it is important to recognise the detrimental effect of corrosive components in the well fluid. This section discusses the nature of corrosion and details the common mechanisms. All forms of corrosion, including the action of hydrogen sulphide, carbon dioxide, chlorides and dissolved oxygen, require the presence of water. The water may only be present in very small quantities, but is nevertheless necessary for the corrosion process. Corrosion in all its forms is basically a result of an electrochemical process with a source of potential voltage and a complete electrical circuit. The source of the voltage in the corrosion process is the energy stored in the metal as part of the original refining process. The electrical circuit is formed from the part of the metal surface which acts as an anode, the electrolyte (the water containing ions) and the part of the metal surface which acts as a cathode. This combination is known as a corrosion cell. Figure 1 shows a schematic of a corrosion cell. Heterogeneities in the metal and differing surface concentrations of electrolyte lead to different parts of the metal acting as anodes or cathodes. At the anodic part of the metal surface, the iron dissolves and the surface becomes corroded. The chemical reaction is as follows: Fe → Fe++ + 2 electrons The cathode is the portion of the metal surface which does not dissolve, but is the site of a complementary reaction in the corrosion process. The exact nature of the reaction is dependent on the composition of the electrolyte and, in particular, the presence of dissolved gases. Dissolved gases like H2S, CO2, and O2 in the water, drastically increase the corrosion rates. The distribution of cathodic and anodic parts of the metal surface is fundamental to the type of corrosion. The reasons why different parts of the same metal surface act are different The following paragraphs deal with the corrosion related failure mechanisms associated with the major contaminants found in wellstream fluids.

2.1.2

HYDROGEN SULPHIDE (H2S)

Hydrogen sulphide (H2S) can occur naturally in the reservoir, be produced in packer fluids or can be generated later as a result of contaminants being injected into the reservoir. The major contaminants that can sour a reservoir are sulphate reducing bacteria (SRB) and bisulphates. The source of these contaminants is fluid injected into the reservoir, e.g. waterflooding. SRB are anaerobic bacteria which produce H2S by metabolising sulphate ions. There is an increasing awareness in the industry that the introduction of bisulphates into the reservoir can also produce H2S as a result of a chemical reaction. The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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The general mechanism of this type of corrosion can be described by a simple chemical equation, although this is not the complete reaction. H2S + Fe + H2O → Hydrogen Iron Sulphide

Water

FexSy + Iron Sulphide

2H Hydrogen

FexSy indicates chemical variations. This corrosion mechanism can lead to three failure types: • Corrosion of the iron to iron sulphide. • Hydrogen embrittlement. • Sulphide stress corrosion cracking (SSC). 2.1.2.1 CORROSION OF IRON TO IRON SULPHIDE The iron sulphide produced by the above reaction usually forms as a black powder or scale on the surface of the tubing. This scale tends to cause a local acceleration of the corrosion as the iron sulphide forms a stronger corrosion cell with the remaining steel and usually results in deep pits. Unlike SSC, this corrosion reaction is only of practical importance if the concentration of H2S is in the order of mole percent rather than ppm.

2.1.2.2 HYROGEN EMBRITTLEMENT The atomic hydrogen liberated by the above reaction can be absorbed by the metal, resulting in a loss of material toughness or ductility and a potential failure. This cracking mechanism can occur whenever atomic hydrogen is liberated by a corrosion reaction, but is generally worse in sour environments. This is because H2S acts as a poison to prevent recombination of hydrogen atoms into molecules at the metal surface and aids the permeation of the atomic hydrogen into the bulk material.

2.1.2.3 SULPHIDE STRESS CORROSION CRACKING Although the mechanism of sulphide stress corrosion cracking is not completely understood, it is recognised that a combination of H2S, water and a susceptible material under a tensile stress can lead to a catastrophic brittle failure. Sulphide stress corrosion cracking is affected by a complex interaction of many parameters, including: • The chemical composition of the material, its mechanical properties, heat treatment and microstructure. • The pH of the aqueous phase. • The concentration of hydrogen sulphide (H2S) and total pressure. • The residual and applied tensile stress. The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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• The temperature. • Exposure time. 2.1.3 CHLORIDE STRESS CORROSION Stress corrosion cracking (SCC) is an interaction between chemical and mechanical forces that produces a failure that otherwise would not occur. The result of the combined effect is a catastrophic brittle failure of a normally ductile metal. Bromide and chloride ions can cause SCC of certain corrosion resistant alloys (CRA), especially austenitic stainless steels, at wellstream temperatures. These ions can be present in formation water, injection water and brines used as completion, workover and packer fluids. In general, use of high density brine containing CaCl2, CaBr2 and ZnBr2 as packer fluids should be avoided. These fluids do not prevent tubing leaks since most leaks occur near the surface where the hydrostatic pressure provided by the brine is not sufficient to overcome the shut-in pressure encountered. Furthermore, they often compromise the production casing string design if a near surface tubing leak occurs, since the internal casing pressure deep in the well will become very high. High density brines can, however, be used as completion and workover fluids. The brines should be formulated with the appropriate inhibitor and circulated out of the well after the workover or completion operations are performed.

2.1.4

DISSOLVED OXYGEN

Dissolved oxygen has the greatest corrosive effect of all the dissolved gases and can cause severe corrosion at very low concentrations (much less than 1.0 ppm). Fortunately, oxygen is not naturally present in formation waters and can only be introduced by contact with air. Oxygen is unlikely to play a major role in the corrosion of production materials. However, despite efforts to exclude oxygen from injected water, it still provides a significant contribution to the corrosion of water injection downhole materials. This process can be described in simplistic terms by the following equation, although in reality the electrochemical changes are more complex: Anode Reaction:

Fe → Fe++ + 2e-

Cathode Reaction: O2+ 2 H20 + 4e- → 40HCombining the two: 4Fe + 6H2O + 3O2 → 4Fe(OH)3 Iron + Water + Oxygen → Ferric Hydroxide

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CARBON DIOXIDE (SWEET CORROSION)

Dry CO2 is non-corrosive to metals and alloys. However, in the presence of liquid water, CO2 forms weak carbonic acid which will corrode steel by the following process: CO2

+

Carbon Dioxide

Fe

H2O

→

Water

+

Iron

H2CO3 → Carbonic Acid

H2CO3 Carbonic Acid

FeCO3 Iron Carbonate (corrosion product)

The severity of carbon dioxide corrosion is influenced by a number of factors, including: • • • • • • • •

CO2 concentration. Water content. pH Pressure. Temperature. Flow velocity. Scale and corrosion deposits. Presence of oxygen, chlorides and H2 S.

The lower the system pH, the more adverse is the CO2 corrosion. The partial pressure of CO2 can be used as a yardstick to predict the severity of potential sweet corrosion problems. Partial pressure = Total pressure x mol percent CO2. Based on the above, the following rules of thumb apply: • Partial pressure above 30 psi indicates a high potential for corrosion. • Partial pressure between 7 and 30 psi indicates corrosion may be a potential problem. • Partial pressure less than 7 psi indicates corrosion is unlikely to be a problem.

The CO2 partial pressures quoted are guidelines. There are, however, situations, e.g. carbonate in formation water, where CO2 corrosion can occur at lower levels.

2.1.6

CORROSION / EROSION

As the name suggests, erosion/corrosion is a corrosion mechanism where the corrosion damage is exacerbated by velocity effects. Velocity limits to avoid erosion in downhole tubulars and associated equipment are normally considered in terms of API Recommended Practice RP 14E*. This RP relates the maximum allowable erosional velocity to the fluid density and a constant (the C factor). The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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ENI S.p.A. Divisione Agip

IDENTIFICATION CODE

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Ve =

0 1

C ρf

where: - Ve = Max allowable Erosional critical velocity - ρf = Fluid Specific Gravity - C = Constant (material dependent)

Based on limited AGIP operating experience and some test data from manufacturers, currently recommendable C factors for various materials are as follows: • Carbon steel : • 13%Cr stainless steel : • Duplex stainless steel and over:

100. 200. 250.

The above mentioned formula should be used only as a preliminar screening on erosional velocity; it does not take into account, infact, concurrent effects due to fines production. More sensible data can be derived from field experience. 2.1.7 GALVANIC CORROSION Galvanic corrosion is the preferential corrosion damage which can occur when two dissimilar materials come into electrical contact via a conducting medium. The susceptibility towards galvanic attack is influenced by a number of factors. These include: • • • •

Conductivity of the aqueous medium Relative surface area of the materials in contact Presence of surface films Comparative positions of the metallic materials in the galvanic series.

2.1.8

CREVICE CORROSION

Crevice corrosion is the preferential localised corrosion damage which can be observed in the crevices present in hydrocarbon production and processing systems. The local environment produced within the crevice can be quite different to that in the bulk of the wellstream fluids. The resulting chemical differences in the crevice provide a concentration effect which promotes the corrosion damage. The crevice may be present at a junction between dissimilar materials, a common material or a combination of metal and non-metal.

2.1.9

CORROSION FATIGUE

Corrosion fatigue, as the name suggests, is the type of fatigue cracking which takes place when materials are subjected to cyclic stresses in a corrosive environment. The presence of this corrosive environment can reduce, or even eliminate entirely, the fatigue limit which is exhibited by many materials in air. As a result, fatigue cracks are likely to initiate at lower stresses and grow more easily in a corrosive environment.

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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2.1.10 LIKELIHOOD OF CORROSION MECHANISM Although a variety of corrosion mechanisms can occur under the fluid conditions present downhole, in practice some mechanisms are far more common than others. Some possible mechanisms are very unlikely to be observed. Corrosion resulting from water or wet gas containing carbon dioxide is probably the most frequently observed corrosion mechanism in practice. In wet gas systems, the present of CO2 corrosion even at low partial pressures has led to the extensive use of CRA materials for such conditions (e.g. 13%Cr stainless steel). Generally, corrosion resulting from the presence of hydrogen sulphide in an aqueous environment is far less common. However, sulphide stress corrosion cracking (SSC) can occur at very low concentrations of H2 S downhole because of the high total pressures which can be present. As a result, materials resistant to SSC are often specified for AGIP tubulars and completion equipment. Sulphide stress corrosion cracking resistant materials are essentially designed to meet the requirements of the NACE sour service standards MR-01-75*. Chloride induced SCC is principally a problem with austenitic stainless steels of the 18% Cr / 8% Ni type. Materials for downhole tubulars and completion equipment are usually of different generic types, and chloride is not normally a significant problem. Corrosion fatigue is not in practice a problem for production tubulars and completion equipment because the cyclic stressing necessary to produce corrosion fatigue is not normally present. Corrosion fatigue of drilling tubulars in their threaded tool joints is a significant problem which can be addressed by reducing the corrosivity of the drilling fluids, reducing working stresses and inspecting threads more thoroughly for incipient cracks before failure occurs. Galvanic corrosion is always a possibility with the mixture of materials which can be found in a downhole design, but in practice, significant problems have not been observed. Crevice corrosion is also a possibility, but again in practice, major problems have not been reported under downhole conditions.

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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CORROSION EVALUATION

This paragraph evaluates the production fluids corrosivity. Following corrosion conditions are considered: 1. 2. 3.

H2S (S.S.C.) CO2 e ClH2S, CO2, and Cl-

The effects due to ‘Ph’ and to ‘souring’, which is H2S increase in time inside the reservoir when this one is depleting, are not considered. Material selection is based on the application of engineering diagrams, supplied by Sumitomo, adequately modified and updated (Fig. 3-4). Proposed material selection is quite conservative also because materials recently available on the market, like Super 13% Cr, 15% Cr and Superduplex class of material and whose testing is still undergoing, are not taken into account. In any case this selection is intended to be a screening guideline which can be easily adopted in 90% of the actual cases; for applications which falls outside of the covered area or at the boundary of each defined area, AGIP-CORM specialized personnel shall be involved. 2.2.1

H2S CORROSION (SULFIDE STRESS CRACKING - S.S.C.)

H2S when in contact with H2O ion H+, and presence of water is essential to have S.S.C; other important factors are presence of stress (tension) and temperature. Temperature above 80°C inhibits the S.S.C.; temperature gradient can so be used for selecting materials and different materials can be selected for different depths. Problem evaluation is function of well type. In gas wells the water saturation is always sufficient to cause water condensation, so the right environment for S.S.C. In vertical oil wells it is instead necessary to analyze the water cut evolution during the well production life; the treshold water cut value generally considered for the corrosion to start is 15%. In higly deviated oil wells (deviation above 80°) the H2S corrosion risk is high because water, even if in limited quantity, for sure will wet the lower tubing generatrix; the problem can also be extended to gas wells but in this case the water cut treshold should be reduced to 1%. In the following chapters formulas will be supplied for calculating pH2S in gas wells, gas & condensate wells and oil wells; calculation of partial pressures should be done after considering the combination of well data relevant to water cut and deviation. 2.2.1.1 OIL AND GAS & CONDENSATE WELLS Partial pressure is calculated as: pH2S = SBHP x Y(H2S)/100 where: SBHP = atm. Y(H2S) = H2S molar fraction pH2S = atm

S.S.C. is present if pH2S >.0035 atm

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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ENI S.p.A. Divisione Agip

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2.2.1.2 OIL WELL Corrosion problems occurr when water is wetting or, as stated: - water cut > 15% in vertical wells, - water cut > 1% in horizontal wells, - deviation is high (> 80 deg) - GOR > 800 Nm3/m3 Partial pressure calculation is different in case of under-saturated or over-saturated oils 2.2.1.2.1

UNDER-SATURATED OIL WELLS

Well is classified ‘under-saturated’ (gas is always dissolved in the oil), when well head and bottom hole pressures are above the Bubble Point Pressure at reservoir temperature conditions. There are two methods for calculating the pH2S: - the ‘Basic Method’ - the ‘Material Balance Method’. If the gas H2S content @ bubble point conditions, Y(H2S), is not known or the value is not reliable, pH2S calculation should be done with both methods and the higher value taken. Otherwise only the ‘basic’ method should be applied. 2.2.1.2.1.1

BASIC METHOD

This method should be utilized, without the need of comparing results with the ‘material balance’ when H2S value in the separated gas @ bubble point conditions is reliable or better if Y(H2S), molar fraction measured @ bubble point (Pb) is greater than 2%. pH2S is calculated as follows: pH2S = Pb x Y(H2S)/100 where: - Pb = (bubble point pressure) @ reservoir conditions; atm - Y(H2S) = molar fraction in the separated gas @ bubble point pressure (from PVT) - pH2S = atm

2.2.1.2.1.2

MATERIAL BALANCE METHOD

The method is utilized when production test data are available, and/or when the H2S is present at very low concentrations (< 2000 ppm) and water cut value measured during production tests is less than 5%; for higher water cut values this method is not applicable. H2S measured values shall be well stabilized; infact values obtained from short production tests are always lower than stabilized values.

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IDENTIFICATION CODE

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The Algorithm used for pH2S calculation is as follows: Step1 Calculate pH2S @ separator conditions (p H2Ssep): pH2S sep = (Psep x H2S sep)/10^6 where Psep = Average absolute separator test pressure; atm H2S sep = Average ppm H2S in separator gas

Step2 Calculate molecular weight of produced oil (PM)

PM =

γ * 1000 GOR γ * 1000 + * ( d * 29 ) GOR 23.6 − PM giac 23.6

PM GIAC = Average oil molecular weight in the reservoir = ( ∑i (i=1,n) Ci x Mi)/100 Ci = molar percentage of reservoir oil i-component Mi = molecular weight of reservoir oil i-component d = gas density at separator conditions (ref. air =1)

Step3 Calculate H2S as moles/liter dissolved in separator oil: H2Soil = p H2Ssep /H(1) x (γ x 1000)/PM) where: H(1) = Henry constant for produced oil at separator temperature (atm/molar fraction). The method is applicable for separator temperature between 20 °C and 200 °C (see step 6). PM = average molecular weight of produced oil γ = produced oil specific gravity gr/lt

Step4 Calculate H2S content in the gas at equilibrium at separator conditions (per liter of oil) H2Sgas

= (GOR/23.6 x H2S sep /10^6)

where:

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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IDENTIFICATION CODE

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GOR = gas oil ratio Nm3/m3 (from production test) 23.6 = conversion factor

Step5 Calculate pH2S at reservoir conditions: pH2S = (H2Soil + H2Sgas /K) x H(2) where K = (γ x 1000/PM + GOR/23.6) total number of moles inside the iquid phase in the reservoir H(2) = Henry constant for reservoir oil at reservoir temperature (atm/molar fraction) (see step 6).

Generally speaking H2S corrosion can occur at wellhead as well as at bottom hole. S.S.C. is present if pH2S > .0035 atm e STHP >18.63 atm. Step 6 Procedure for calculating Henry constant Henry constant is dependant on temperature. Method is applicable to separator temperature between 20 °C and 200 °C. Figure 2 represents H(t) function for the three different oil types, heptane PM = 100, n-propilbenzine PM = 120 and methylnaftaline PM = 142. H1 Calculation Method Having available the average molecular weight of produced oil as per step 2 the reference curve for calculating the Henry constant is selected using following ranges of values: a) if PM ≥142 → methylnaftaline H(t) curve shall be used b) if PM = 120 → n-propilbenzine H(t) curve shall be used c) if PM ≤ 100 → heptane H(t) curve shall be used d) if 100 < PM < 120 the average value between n-propilbenzine H(t) curve and methylnaftaline H(t) curve shall be considered e) if 120 < PM < 142 the average value between n-propilbenzine H(t) curve and heptane H(t) curve shall be considered f) given FTHT, flowing tubing head temperature, H1 value is read on Y axis, drawing an horizontal line from the intersection of the considered curve/s with the vertical line parallel to Y axis intersecting X axis at FTHT (this value taken in between the immediately lower and gretaer values on the diagram. H2 Calculation Method After calculating PM GIAC

∑

PM GIAC = Average oil molecular weight in the reservoir = ( i (i=1,n) Ci x Mi)/100 and using the separator temperature calculation shall proceed like H(1).

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130

120

110

100

90

Atm/Fraz. Mol.

80

70

60

50

40

30

20

10

185

170

155

140

125

110

95

80

65

50

35

20

0 Temperature - °C Metilnaftalina P.M. 142 N _Propilbenzene P.M. 120 Eptano P.M. 100

Figura 2. H(t) reference curve.

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Over-saturated Oil Wells

Well is classified ‘oversaturated’ (gas is separated from fluid) when system pressure is below the bubble point pressure. Different situations can occurr: A case FTHP < Pb FBHP > Pb B case FTHP < Pb FBHP < Pb A case Partial Pressures Calculations 1. Partial Pressures Calculations @ Reservoir conditions pH2S is to be calculated as per paragraph 1.1.2.1. 2. Partial Pressures Calculations @ Wellhead conditions Since FTHP < Pb only ‘Basic Method’ applies. Partial pressure ( H2S ) is calculated as follows: pH2S = STHP x Y(H2S)/100 where: - STHP = Static Tubing Head Pressure; atm - Y(H2S) = molar fraction in the separated gas @ STHP and STHT - p H2S = atm

S.S.C. is present if p H2S > .0035 atm e STHP >18.63 atm B case Partial Pressures Calculations

1. Partial Pressures Calculations @ Reservoir conditions In the reservoir FBHP < Pb, gas is already separated and pH2S calculation can be done after following considerations: a. PVT data are reliable, Y(H2S) > 0.2% p H2S = Y(H2S) / 100 x FBHP

where: The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

ARPO

ENI S.p.A. Divisione Agip

IDENTIFICATION CODE

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- Y(H2S) = molar fraction in the separated gas @ FBHP and SBHT (from PVT) - p H2S = atm

b. PVT data are not reliable; ‘Material Balance Method’ can be applied as in the case of undersaturated oil; this doing means to assume ‘worse conditions’. If Pb >> FBHP error introduced can be not acceptable. 2. Partial Pressures Calculations @ Wellhead conditions. Proceed as per Acase (FTHP < Pb). 2.2.2

CO2 E CL- CORROSION

CO2 in presence of water causes different corrosion phenomena with respect to H2S. It occurs if CO2 partial pressure is above a certan treshold value. As for S.S.C. this paragraph will evaluate the possibility for the corrosion to occur as a function of well deviation and type of well. If conditions set up in paragraph 1.1 applies then pCO2 can be calculated. 2.2.2.1 GAS OR GAS & CONDENSATE WELLS Partial pressure is calculated as: pCO2 = SBHP x Y(CO2)/100 where: - SBHP = atm. - Y(CO2) = CO2 molar fraction - pCO2 = atm

Corrosion is present if pCO2 > .02 atm 2.2.2.2 OIL WELLS Corrosion problems occurr when water is wetting or, as stated: - water cut > 15% in vertical wells, - water cut > 1% in horizontal wells, - deviation is high (> 80 deg) Partial pressure calculation is different in case of undersaturated or oversaturated oils 2.2.2.2.1

UNDER-SATURATED OIL WELLS

Partial pressure ( pCO2 ) is calculated as follows: pCO2 = Pb x Y(CO2)/100 where:

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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IDENTIFICATION CODE

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- Pb = (bubble point pressure) @ reservoir conditions; atm - Y(CO2) = molar fraction in the separated gas @ bubble point pressure (from PVT) - pCO2 = atm

Corrosion is present if pCO2 > 0.2 atm. Calculated pCO2 values are to be utilized for corrosion evaluation either at bottom hole or at well head conditions; that is to say that it is assumed that well head pCO2 corresponds to the one at reservoir conditions. 2.2.2.2.2

OVERSATURATED OIL WELLS

Well is classified ‘over-saturated’ (gas is separated from fluid) when system pressure is below the bubble point pressure. Different situations can occurr: A case FTHP < Pb FBHP > Pb B case FTHP < Pb FBHP < Pb A case Partial Pressures Calculations 1. Partial Pressures Calculations @ Reservoir conditions pCO2 is to be calculated as per paragraph 1.2.2.1. Corrosion is present if pCO2 > 0.2 atm 2. Partial Pressures Calculations @ Wellhead conditions pCO2 = STHP x Y(CO2)/100 where: - STHP = Static Tubing Head Pressure; atm - Y(CO2) = molar fraction in the separated gas @ STHP and STHT - pCO2 = atm

Corrosion is present if pCO2 > 0.2 atm B case Partial Pressures Calculations 1. Partial Pressures Calculations @ Reservoir conditions: pCO2 = FBHP x Y(CO2)/100 where: - Y(CO2) = molar fraction in the separated gas @ FBHP and FBHT (from PVT) The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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- pCO2 = atm

2. Partial Pressures Calculations @ Wellhead conditions. Proceed as per A case. Corrosion is present if pCO2 > 0.2 atm. 2.2.2.3 H2S , CO2 AND CL- CORROSION It is possible to find out H2S, CO2 together with Cl- , in this case the problem is more complex and material selection much more delicate. Partial pressures are calculated as above and then usually dedicated lab test are required for material characterization in the specific environment. Next chapters will give indications on materials to chose for those conditions.

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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MATERIAL SELECTION

If H2S and CO2 partial pressures are below critical values defined in the above chapter, in this chapter recommended materials refers to Cabon Steel/Low-Alloy Steel classes; otherwise following combinations of environmental conditions can occur: 1. only H2S in oil wells 2. only H2S in gas and/or gas condensate wells 3. only CO2 and Cl4. both H2S and CO2 and ClFollowing tables will indicate the materials selections for Oil Country Tubular Goods (OCTG), Down Hole Equipment (DHE) and Well Head & Xmas Tree. Each step indicates the reference to Figure 3,4, corrosivity conditions in second column and the minimum cost recommended material in the third column while in the fourth column there is a list of recommended materials in ordered per increasing cost. Corrosivity conditions superimpose partial pressure conditions, temperatures, chlorides (Cl ), and refers to engineering diagrams estabilished threshold zones (Fig. 2,3). Corrosivity conditions are defined when all different statements (partial pressures, chloride content, temperatures )are all valid at the same time. Units used in the tables are: - atm for pH2S MAX e pCO2 MAX , - °C for temperatures, - ppm for chlorides (Cl- ). 2.3.1.1 O.C.T.G MATERIALS TABLES 2.3.1.1.1

OCTG MATERIALS - ONLY H2S IN OIL WELLS Corrosive environment

1 2 3 4

0.0035< pH2S MAX ≤ 0.1 FBHT > 80 0.0035< pH2S MAX ≤ 0.1 65 < FBHT ≤ 80 0.0035< pH2S MAX ≤ 0.1 FBHT ≤ 65 pH2S MAX > 0.1

Material First Choice J55, K55, N80-1, C95, P110-1 J55, K55, N80-1 L80

Alternative Choice L80-MOD, C90-TYPE1, T95TYPE1 L80-MOD, C90-TYPE1, T95TYPE1 L80-MOD, C90-TYPE1, T95TYPE1

L80-MOD, C90-TYPE1, T95TYPE1

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IDENTIFICATION CODE

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6

2.3.1.1.3

0.0035< pH2S FBHT > 80 0.0035< pH2S FBHT ≤ 80

8 9

then

MAX

≤ 0.1 e J55, K55, N80-2, C95

MAX

≤ 0.1 e L80

57

0 1

Alternative Choice L80-MOD, C90-TYPE1, T95TYPE1 L80-MOD, C90-TYPE1, T95TYPE1

OCTG MATREIALS - ONLY CO2 AND CL- WELLS Corrosive environment

7

OF

OCTG MATERIALS - ONLY H2S IN GAS AND/OR GAS CONDENSATE WELLS Corrosive environment

5

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REVISION TEAP-P-1-R-8791

2.3.1.1.2

PAG

0.2< pCO2 MAX ≤ 100 FBHT ≤150 e Cl- ≤ 50000 0.2< pCO2 MAX ≤ 100 150 < FBHT ≤ 200 0.2< pCO2 MAX ≤ 100 200 < FBHT ≤ 250

Material First Choice

Alternative Choice

13%-Cr 22%-Cr 25%-Cr-Solution Annealed

25%-Cr

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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OCTG IN H2S , CO2 AND CL- WELLS Corrosive environment

10

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PAG

0.2< pCO2 MAX ≤ 100 0.0035< pH2S MAX ≤ 0.005 FBHT≤ 150 Cl- ≤ 50000 0.2< pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 FBHT ≤ 200 Cl-> 50000 0.2< pCO2 MAX ≤ 100 0.0035< pH2S MAX ≤ 0.005 150< FBHT≤ 200 Cl-≤ 50000 0.2< pCO2 MAX ≤ 100 0.0035< pH2S MAX ≤ 0.005 200 50000 0.2< pCO2 MAX ≤ 100 pH2S MAX > 1

Material First Choice 13%-Cr-80Ksi-Max

Alternative Choice 22%-Cr 25%-Cr

22%-Cr-Cold Worked 25%-Cr-C.W.

22%-Cr 25%-Cr

25%-Cr

25%-Cr-C.W.

25%-Cr

25%-Cr-C.W.

28%-Cr

Incoloy-825

22%-Cr-S.A.

25%-Cr-S.A. 28%-Cr Incoloy-825

25%-Cr-S.A.

28%-Cr Incoloy-825

28%-Cr

Incoloy-825

28%-Cr

Incoloy-825

2.3.1.2 DHE MATERIALS The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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ENI S.p.A. Divisione Agip

IDENTIFICATION CODE

2 3

2.3.1.2.2

pH2S MAX ≤ 0.1 FBHT > 80 pH2S MAX ≤ 0.1 FBHT > 65 pH2S MAX ≤ 0.1 FBHT ≤ 65 or pH2S MAX > 0.1

5

2.3.1.2.3

pH2S MAX ≤ 0.1 FBHT > 80 pH2S MAX >0.1 or FBHT > 80

7

8

2.3.1.2.4

pCO2 MAX ≤ 100 FBHT ≤ 100 Cl-≤ 50000 pCO2 MAX ≤ 100 100 < FBHT ≤ 150 Cl-≤ 50000 pCO2 MAX ≤ 100 150 < FBHT ≤ 250

10

11

Material First Choice

Alternative Choice

Carbon Steel-110Ksi-Max AISI41XX Carbon Steel-80Ksi-Max AISI41XX AISI-41XX-HRC-22-Max

Material First Choice

Alternative Choice

Carbon Steel-80Ksi-Max AISI41XX AISI-41XX-HRC-22-Max

Material First Choice

Alternative Choice

9%-Cr-1-Mo

13%-Cr-80Ksi-Max

25%-Cr-C.W.

28%-Cr Inconel 718 Incoloy 825

DHE MATERIALS - H2S, CO2 AND CL- WELLS Corrosive environment

9

0 1

DHE MATERIALS - ONLY CO2 AND CL- WELLS Corrosive environment

6

57

DHE MATERIALS - ONLY H2S IN GAS WELLS Corrosive environment

4

OF

DHE MATERIALS - ONLY H2S IN OIL WELLS Corrosive environment

1

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2.3.1.2.1

PAG

pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 FBHT ≤ 100 Cl-≤ 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 100 < FBHT ≤ 150 Cl-≤ 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005

Material First Choice

Alternative Choice

9%-Cr-1-Mo

13%-Cr-80Ksi-Max

22%-Cr 25%-Cr

22%-Cr 25%-Cr Incoloy 825 Inconel718 Incoloy 825 Inconel 718

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150 < FBHT ≤ 200 Cl-≤ 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 200 < FBHT ≤ 250 Cl-≤ 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 100 < FBHT ≤ 200 Cl-> 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 0.005 200 < FBHT ≤ 250 Cl- > 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 0.1 200 < FBHT ≤ 250 Cl- 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 1 FBHT ≤ 200 Cl-≤ 50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 1 FBHT ≤ 250 Cl-≤50000 pCO2 MAX ≤ 100 pH2S MAX ≤ 1 FBHT ≤ 250 Cl-> 50000

PAG

0 1

25%-Cr

Incoloy 825 Inconel 718

22%-Cr-C.W. 25%-Cr-C.W.

Incoloy 825 Inconel 718

25%-Cr-C.W.

Incoloy 825 Inconel 718

25%-Cr

Incoloy 825 Inconel 718

28%-Cr

Incoloy 825 Inconel 718

22%-Cr-S.A.

25%-Cr-S.A 28%-Cr Incoloy 825 Inconel 718

25%-Cr-S.A.

28%-Cr Incoloy 825 Inconel 718

28%-Cr

Incoloy 825 Inconel 718

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2.3.1.3 WELL HEAD & XMAS TREE MATERIALS 2.3.1.3.1

WELL HEAD & XMAS TREE MATERIALS - ONLY H2S IN OIL WELLS

Corrosive environment 1

pH2S MAX ≥ 0.035

2

pH2S MAX 50000 or pCO2 MAX ≤ 100 pH2S MAX > 0.8

AISI-4135 & Internal-Cladding Inconel 625 Gate&Seats F6NM Inconel 718 Stem Monel K500 Manual-Master-Valve-Materials Body-Bonnet-Flanges AISI-4135 & Internal-Cladding /Inconel 625 Gate&Seats F6NM Inconel 718 Stem Monel K500 Tubing-Hanger Inconel 718

Tubing-Head-Adapter Tbg-Spool Cross

Top-Adapter

Casing-Spool Stud Nut

AISI-4135 & Internal-Cladding Inconel 625 AISI-4135-HRC-22-Max AISI-4135 & Internal-Cladding Inconel 625 Inconel 718 AISI-4135 & Internal-Cladding Inconel 625 Inconel 718 AISI-4135-HRC-22-Max Bolting-Materials Inconel 718 Inconel 718

Manual-Master-Valve-Materials Body-Bonnet-Flanges

AISI-4135 & Internal-Cladding

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Inconel 625 Inconel 718 Inconel 718 Inconel 718

Gate&Seats Stem

Automatic-Master-Valve-Materials Body-Bonnet-Flanges Gate&Seats Stem

AISI-4135 & Internal-Cladding Inconel 625 Inconel 718 Inconel 718

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100

10

7 10

15

18

16

19

17

20

11 8

12 13

9

1

21

pCO 2 (ATM)

14

10-1 1 2

10-2 C-STEEL

3

4

5 10-3

6

10-4 10-4

10-3

10-2

10-1 pH2S (ATM)

1

10

100

FIGURE 2. Diagram material OCTG

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100 6 17 7

10

11

18

12

8

16

13

pCO 2 (ATM)

1

9

28% Cr or INCOLOY 825 INCONEL 718

15

19

14

10-1 1 2

10-2 C-STEEL or AISI 41XX

3

5

4

10-3

10-4 10-4

2.4

10-3

10-2

10-1 pH2S (ATM)

1

10

100

FIGURE 3. DIAGRAM MATERIAL FOR D.H.E

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ELASTOMERS

2.4.1 INTRODUCTION Elastomers (rubbers for sealing) and polymers (engineering plastics for back-ups) are used in many fluid sealing applications in downhole and surface equipment. This section covers their use in completion equipment. A wide range of elastomers and plastics is available, and seal material selection is always a compromise resulting from consideration of the service duties and the performance needs. This section is designed to provide help and information to enable the engineer to make a basic material selection or appraise the material on offer from an equipment manufacturer. Many of the malfunctions of subsurface oil field equipment have been traced to seal failure. Seal materials and seal designs, often among the least expensive components, are often the limiting factors in equipment performance. Failures in elastomer seals downhole can result in high workover costs. In order to minimize these failures, all the contributing factors should be assessed and the correct elastomer seal material should be chosen for the intended duties. To do this, the well conditions need to be defined as fully as possible and the performance of the elastomers, their properties and environmental resistance should be understood. Working closely with the equipment supplier or Agip CORM, will ensure the optimum material selection is made. The selection process detailed in this section is as follows: Define well conditions. Select elastomer class for compatibility with: - Heat resistance. - Oil resistance. - Service liquids resistance. - Gas duties resistance. Select elastomer grade based on pressure level for required performance properties. Tables 1, 2 and 3 (pg. 6, 7, 8) provide quick guides to aid elastamer selection Elastomers (e.g. Nitrile, Viton, Aflas, etc.) possess the ability to recover from applied stress over a significant deformation range. Plastic material (e.g. PTFE, Ryton, PEEK, etc.) do not possess this quality and deform irrecoverably by plastic flow. In general, elastomers are used for the sealing elements and plastics (suitably filled to reduce deformation) are used as back up rings to prevent extrusion under high pressure service. The same environmental considerations are applied to the plastic materials as to the elastomeric material, consequently the term ‘elastomer’ is used to include both types where appropriate. The essential quality of elasticity in a rubber allows it to have an advantage over metallic counterparts in the degree of conformability to a rough or uneven sealing surface. Also, an elastomer is incompressible and has the ability to deform under constant volume to provide a seal in constrained housings, whilst still exerting a positive sealing force. Elastomers can be readily fabricated in a variety of shapes and sizes, e.g. O-Rings, T-seals, Chevrons and Lip Seals etc., depending on the application requirement, and may be assembled

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with relative easy due to their elastic nature. Unlike metals, corrosion is not a significant problem with elastomeric materials. 2.4.2 DEFINITION OF WELL CONDITIONS The information required to specify an elastomer is listed below. This data should be collated from the Statement of Requirements for the well and refined during the conceptual design phase: Bottom hole temperature Surface temperature Temperature extremes Temperature profile Reservoir pressure Wellhead pressure Pressure profile Production fluid composition - Hydrocarbons - Aromatics - Water Gas/oil ratio Injected fluids composition - Inhibitors - Control line fluids - Completion fluids - Acid and chemicals Temperature of injected downhole Produced gas composition - Hydrocarbons - Hydrogen sulfide - Carbon dioxide Differential seal pressure Seal movements Lifetime required

(closed in/flowing) (closed in/flowing) (max./min.) (static/cyclic, frequency) (closed in/flowing) (variation, frequency, rate) (and variation)

(strength, duration, frequency) (corrosion and scale)

fluids

(level, rate, frequency) (level, rate, frequency) (between workovers

In addition, the seal design in which the elastomer is incorporated should also be considered (i.e. Oring, T-seal, V-packing etc.) 2.4.3

EFFECTS OF TYPICAL DOWNHOLE ENVIRONMENTS

2.4.3.1 PRODUCED FLUIDS Crude oil with natural gas or natural gas with condensate are most typical. High aromatic content oils and chlorinated hydrocarbons can cause excessive swelling, loss of strength or even dissolution in some rubbers (e.g. natural rubber, EPDM, butyl, silicones etc.). Absorbed gases at high pressures could give rise to blistering or rupture in seals when rapidly decompressed. Formation water is frequently present, as a result of waterflood breakthrough. Seawater may cause hydrolysis degradation in some elastomers (e.g. acrylics, urethanes).

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2.4.3.2 TEMPERATURE AND PRESSURE Surface temperatures can be low when the well is shut in (sea temperatures 2° to 6°C), but downhole equipment normally functions at service temperatures between 80°F (27°C) and 400°F (204°C). Temperature is important because materials strength properties generally reduce and environments become more aggressive with increases in temperature. Two opposite effects on performance are possible as a result of temperature. Materials may soften and extrude where no chemical reaction occurs, or they could harden with age and become brittle under chemical attack. Both mechanisms can lead to failure. Differential pressures are typically a maximum of 15 000 psi. The level of pressure determines the mechanical properties required within the grade of elastomer class and whether back up rings are required. 2.4.3.3 CORROSION AND SCALE Moderately corrosive environments are typical. Wells often contain significant amounts of carbon dioxide (CO2) which readily causes blistering in some elastomers when rapidly decompressed. H2S may chemically attack the cure sites in the elastomer, which can lead to hardening and rupture by embrittlement. The selection of corrosion resistant alloys is becoming more common, but inhibitors are often added to injection water and completion fluids. Low levels of inhibitors are normally used and chemical attack on seal materials by these low levels at low temperatures is normally not a problem. However, some film forming amine based corrosion inhibitors can be aggressive, and attention should always be drawn to the assessment of their effect on the seal material (especially Nitriles and Vitons) 2.4.3.4 CONTROL LINE FLUIDS Mineral oil hydraulic fluids are common. Low viscosity ‘Arctic grades’ are frequently used where they may encounter low surface temperatures. Water based fluids with about 50% glycol are also used. Appropriate seal material selection can normally overcome any problems with control line fluids, but there may be a conflict of interests where a seal may experience water based control line fluid on one side with oily produced fluids on the other, e.g. in subsea safety valves.

2.4.3.5 COMPLETION FLUIDS Treated seawater is a typical completion fluid. The treating chemicals are normally used at low concentrations. and CaCl/CaBr systems do not usually affect seal materials. However, care must be taken when dense acidic systems (e.g. ZnBr) are used because of their very marked hardening effect on nitrile rubbers. Fluoroelastomers, like Aflas or Viton, are unaffected. Highly alkaline fluids, such as K2C03, can affect Viton elastomers through hydrolysis.

2.4.3.6 ACIDS AND CHEMICALS Consideration must be given to the effects on seals materials of future acidization and any other chemical injection additives. Normal seal exposure is limited to short term but some of the additives can be very aggressive (acids, surfactants, aromaties, iron chelating agents etc.).

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PROPERTIES OF ELASTOMERS

Elastomers are essentially long molecular chains in which the development of strength and recoverability is governed by the level of crosslinks present between the chains. These crosslinks are formed by curing the rubber using sulfur or peroxide cure systems. The extent of curing, or molecular length between crosslinks, gives rise to important variations in mechanical properties as shown in Figure 1. STATIC MODULUS EXTRUSION RESISTANCE BLISTER RESISTANCE

M E C H A N I C A N I C A L

HIGH SPEED DYNAMIC MODULUS

HARDNESS TENSILE STRENGHT

P R O P E R T I

TEAR STRENGHT FATIGUE LIFE TOUGHNESS HYSTERESIS COMPRESSION SET FRICTION COEFFICIENT

E S

ELONGATION

CROSSLINK DENSITY (DEGREE OF CURE) →

Figure 1. Effect of degree of curing on Elastomer Mechanical Properties 2.5.1

ELASTOMER TYPES AND COMPOUNDING

A wide range of elastomer material ‘types’ or ‘classes’ (e.g. EPDM, Nitrile, Fluoroelastomer etc.) is available to cope with particular service requirements. Within these classes it is possible to compound specific grades to yield individual performance characteristics. An elastomer ‘compound’ is the term used to describe the rubber ‘grade’ which is manufactured from a recipe of ingredients that comprise the base rubber class, reinforcing agents, curing agents and other additives (e.g. lubricants, anti-oxidants etc.). Some unreinforced elastomers can undergo crystallization under strain, e.g. natural rubber, chloroprene, butadiene etc., and have inherent strength as a high plateau value across a wide range of temperature and strain rate. However, many elastomers are subject to very poor mechanical strength in their unreinforced state. It is only when some degree of reinforcement is made through compounding with fillers and curing systems that the majority of elastomers can achieve serviceable strength and performance over a wide range of conditions This is why the chemist spends so much time on optimizing his compound recipes to achieve grades with enhanced performance at operating temperatures.

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Table 1 shows a typical compound recipe based on a Nitrile rubber. TYPICAL NITRILE RUBBER COMPOUNDS Additive

Part by weight

Nitrile N28C50 Zinc Oxide Stearic Acid Regal SRF (N 762)

100 5 1 50

Silica VN3 Flectol H CBS TMT Sulfur MC Dutrex 729

15 2 1.5 2.5 0.5 10

Additive Function Base rubber (28% acrynolite) Activator for sulfur Lubricant, retarder Carbon black filler (semireinforcing) Fine silica filler (for heat resistance) Anti-oxidant Fast curing accelerator Sulfur donot compound Sulfur accelerator Process aid (to give better low temperature and resilience properties

Table 1 A large number of possible ingredients are available for compounding, and this leads to an infinite number of potential compounds. The art of compounding is to optimize the properties of the compound to suit the particular performance requirements. Various compounding factors influence material properties, e.g. the molecular weight of the base rubber, the degree of cure, the filler type, its structure and loading. The effects of these factors on properties are seen in Table 2.

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CHANGE IN PHYSICAL PROPERTIES OF ELASTOMERS WITH INCREASE IN VARIOUS FACTORS RELATED TO STRUCTURE AND COMPOUNDING

Property Change for Increase in:

Mol Wt Rubber

Degree of cure

Filler Load

Filler S Area

Filler Structure

Hardness Modules Tensile Strength Elongation Compression Set Tear Strength Fatigue Life Abrasive Resistance Impact Strength Extrusion Resistance Blister Resistance

NC UP UP UP DOWN UP UP UP UP UP UP

UP UP MAX. DOWN DOWN MAX. MAX. MAX. MAX. UP UP

UP UP MAX. DOWN UP MAX. MAX. MAX. MAX. UP UP

UP UP UP NC UP UP DOWN UP UP UP UP

UP UP NC DOWN UP UP UP UP UP UP UP

NC UP DOWN MAX. Mol Wt S Area

No significant change in value Properties increases in value Properties decreases in value Properties goes through a maximum Molecular weight of rubber Surface Area of filler (inverse of particle size) Table 2

There are, of course, some compatible properties which can be achieved together in compounding (e.g. high modules and hardness with high filler load and high cure), but equally, there are properties which can only be obtained at the expense of some other characteristic (e.g. extrusion resistance cannot be achieved from low strength, soft materials). Consequently, all compounds or elastomer grades are a compromise of properties.

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CLASSIFICATION OF ELASTOMERS

Elastomer seals materials may be classified by their resistance to heat and oil as indicated in Table 3 where the standard ASTM notation system for elastomer class and examples is given. ELASTOMER CLASSIFICATION BY RESISTANCE TO HEAT AND OIL

ASTM Ref.

Elastomer Class

Example

1 NR IR BR SBR

Non Oil Resistant - General Purpose Natural Rubber Synthetic isoprene Butadiene Rubber Styrene-butadiene rubber

SMR Natsyn Cariflex

IIR EPM EPDM

Non Oil Resistant - Medium Heat Resistance Butyl rubber Ethylene-propylene (saturated) Ethylene-propylene-diene (unsaturated)

Vistanex Dutral Nordel

TR AU/EU

Oil Resistant - Low Temperature Polysulphide Plyurethane (ester/ether)

Thiokol Adiprene

CR NBR HNBR CM CSM CO ECO

Oil Resistant - General Purpose Chloroprene rubber Nitrile rubber Hydrogenated nitrile rubber Chlorinated plyethilene Chlorosulphonated polyethilene Epichlorohydrin Epichlorohydrin copolymer

Neoprene Buna-N Therban Duralon Hypalon Hydrin-100 Hydrin-200

ACM FCM FKM FFKM

Oil and Heat Resistant Polyacrilic Tetrafluoroethylene-propylene Fluoroelastomer Perfluoroelastomer

Vamac Aflas Viton Kalrez

SI FSI

Silicone Rubber Silicone rubber Fluorosilicone rubber

2

3

4

5

6

Table 3

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The elastomers indicated in Table 3 are shown graphically in Figure 4 as a function of their heat resistance (upper service temperature limit) and % volume swell in oil. In most downhole seals applications 25% to 35% is the maximum volume swell in oil that is tolerable for a static seal. Dynamic seals will only tolerate considerably less (< 15%). Only those elastomers with volume swell values of less than 35%. which lie to the right of the dotted line, will be considered as useful for seals in hydrocarbon duties.

Figure 4. Elastomer classification based on heat and oil resistances

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ENVIRONMENTAL RESISTANCE OF ELASTOMER CLASSES

This section gives a brief review of properties and environmental resistance for the commercial elastomers most commonly used in completions equipment. Some of the harder seal materials used for back-ups are also included. Under recommended service, reference is made to each elastomers resistance to aliphatic and aromatic hydrocarbons. The vast majority of produced fluids are aliphatic hydrocarbons. e.g. methane. Aromatic hydrocarbons occur less frequently and incur benzene ring type compounds. 2.6.1 GROUP 2 ELASTOMERS (MEDIUM HEAT RESISTANCE, NON OIL RESISTANT) 2.6.1.1 EPDM- ETHYLENE-PROPYLENE-DIENE (NORDEL) • Tradenames Nordel

DuPont

Service Temperature -50°C to 150°C (200°C max in steam) • Recommended Service EPDM has outstanding resistance to weathering. It is particularly resistant to superheated steam, water, glycol based control fluids, many organic and inorganic acids, cleaning agents, alkalis, phosphate ester based hydraulic fluids, silicone oils and greases. Also EPDM has resistance to many polar solvents such as alcohol’s, esters and ketones • Not Recommended EPDM has very poor resistance to hydrocarbons. • Physical Properties Appropriate compounding of EPDM could result in elastomer systems capable of performing continuously up to 175°C, although 150°C is more usual. Intermittent exposures can be tolerated up to a temperature of 200°C.

2.6.2

GROUP 4 ELASTOMERS (GENERAL PURPOSES OIL RESISTANT)

2.6.2.1 CR-POLYCHLOROPRENE (NEOPRENE) • Tradenames Neoprene Butaclor

Dupont Distugil

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(-55°C) -45°C to 100°C (130°C short term) • Recommended Service The chlorine is responsible for the general resistance to oxygen. Outdoor weathering of neoprene does not have a significant effect on its elastomeric properties. It is unaffected by aliphatic hydrocarbons, alcohols, glycols and fluorinated hydrocarbons. It has a good resistance to most inorganic chemicals including dilute acids and concentrated causties. Neoprene also displays reasonable oil resistance, although this is not as good as that noted for Nitrile rubber. Neoprene also has good resistance to silicone oils, grease and water. • Not Recommended Polychloroprene is not resistant to chlorinated hydrocarbons, organic esters, aromatic hydrocarbons, phenols and ketones. It is also severely attacked by concentrated oxidizing acids like nitric or sulphuric acids, as well as strongly oxidizing agents such as potassium dichromate. • Physical Properties Neoprene is a tough, strong, resilient rubber with good resistance to abrasion. It has lower permeability than natural rubber. 2.6.2.2 NBR - ACRYLONITRILE-BUTADIENE RUBBER (NITRILE RUBBER) Best known as Nitrile rubber or Buna-N. • Tradenames Breon Hycar Krynac Nysyn Perbunan

BP Chemicals Ltd B F Goodrich Chemical Co Polysar Ltd Copolymer Corpn Bayer AG

Copolymers of acrylonitrile (ACN) and butadiene were first used as synthetic stocks before World War II (Buna-N). In NBR the ACN content may vary from 20 to 50%, but more typically 28 to 41% by weight, and this affects the performance properties. • Service Temperature (-55°C) -30°C to 100°C (130°C short term) • Recommended Service NBRs are resistant to aliphatic hydrocarbons, vegetable and mineral oils and greases, hydraulic fluids, many dilute acids, alkalis, salt solutions and water • Not Recommended

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Nitrile rubbers are not recommended for service in hydrocarbons with a high aromatic content, chlorinated hydrocarbons, polar solvents such as ketones, acetone, acetic acid, esters, strong acids or with control fluids based on glycols. Zinc bromide brines also have a very serious hardening effect on Nitrile rubbers. • Physical Properties The properties are greatly affected by acrylonitrile content as shown below: As acrylonitrile content increases:

D e c r e a s e

Tensile strnght Resilience Oil resistance Low Temp. Flexibility Hardness and Modulus Compression Set Brittle Temperature Abrasion Resistance Heat Resistance

I n c r e a s e

Nitriles are noteworthy because of their resistance to hydrocarbons. They are relatively inexpensive and are used extensively in applications requiring oil resistance.

2.6.2.3 HNBR - HYDROGENATED NITRILE RUBBER (THERBAN) • Tradenames Therban Bayer A G Zetpol Nippon Zeon Camlast Cameron • Service Temperature -25°C to 150 • Recommended Service HNBR elastomers have better heat ageing characteristics than Nitrile rubbers, but otherwise they have many similarities on their dependence on acrylonitrile content for their physical properties. They normally have good resistance to oils, diesel, kerosene, hydraulic fluids and inorganic salts (except zinc bromide). HNBR has better resistance to sour conditions than conventional Nitrile rubbers and has very good ageing and weathering properties. • Not Recommended

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HNBR elastomers are swollen in highly aromatic oils and are not so resistant to hydrocarbons in general compared to conventional Nitrile rubbers. They can also be affected by corrosion inhibitors, zinc bromide brines and strong acids. HNBR is used in seals for valves and BOP’s. 2.6.2.4 CO AND ECO EPICHLOROHYDRIN HOMO-AND COPOLYMERS (HYDRIN) • Tradenames Hydrin B F Goodrich Co • Service Temperature -40°C to 135°C • Recommended Service Both CO and ECO epichlorohydrins are resistant to mineral oils and greases, aliphatic hydrocarbons, silicone oil, grease and water at room temperature. They are also resistant to ageing and weathering. Their low permeability to gases make them particularly appropriate for gas applications. • Not Recommended Epichlorohydrins are not resistant to aromatic and chlorinated hydrocarbons, ketones and esters, hydraulic fluids and glycol based control fluids.

2.6.3

GROUP 5 ELASTOMERS (HEAT AND OIL RESISTANT)

2.6.3.1 FKM FLUOROELASTOMER (VITONS) • Tradenames Viton Fluorel Technoflon

DuPont 3M Company Montecatini

Fluorocarbon elastomers were the most significant advance to come out of the 1950s and are noted for their high temperature capabilities and general chemical resistance. It is important to understand that there are several chemically different types of fluoroelastomers. The Viton group is divided into three main types: A, B and G. The Viton-A family consists of copolymers of vinylidene fluoride and hexafluoropropylene. This general purpose copolymer family is further subdivided into A, E and speciality series and includes for instance Viton-AHV, a high molecular weight fluoroelastomer, and Viton-E60, an extrusion resistant grade. Viton A types are cured using amines and exhibit good resistance to compression set. The Viton-B family offers improved heat and fluid resistance at some sacrifice in compression set resistance compared with the A family. The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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In general, the Viton-G family have improved steam and acid resistance compared to conventional types of Viton. Viton-GF, a newer addition to this range, has received much attention in oil field applications due to its improved resistance to hydrocarbons, volume change and property retention. • Service Temperature (-40°C) -20°C to 200°C (250°C) • Recommended Service The fluoroelastomers all have excellent chemical and solvent resistance. They are very resistant to aliphatic hydrocarbons, chlorinated solvents, animal, vegetable and mineral oils, gasoline, kerosene, dilute acids, alkaline media and aqueous inorganic salt solutions. They exhibit good weather resistance. • Physical Properties These fluoroelastomers retain their physical properties well over a wide temperature range and have low gas permeability rates and extremely low water absorption. They exhibit good tensile strength and tear resistance. Special grades are available with improved decompression resistance. • Not Recommended They have only fair general resistance to alcohols (be careful with methanol dewatering), aldehydes, ketones, esters and ethers and are not compatible with polar solvents such as acetone, methylethylketone or ethyl acetate. Certain amines may also cause problems, as will hydraulic fluids based on glycol, superheated steam and low molecular weight organic acids, e.g. formic and acetic acids. If organic amine corrosion inhibitors are to be used, then Viton and Fluorel are not recommended for seals where there is the possibility of movement. This is because amines were the first curing systems used for these elastomers, and the presence of added amine corrosion inhibitor will continue to cure the elastomer until it hardens and becomes brittle. The effect is less marked with the peroxide cured Viton-GF types.

2.6.3.2 FCM TETRAFLUOROETHYLENE - PROPYLENE COPOLYMER (AFLAS) • Tradenames Aflas Asahi Glass Co Fluoraz Greene Tweed • Service Temperature -40°C to 230°C (300°C short term) • Recommended Service

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FCM elastomers are not affected by most strong acids, bases, ketones, alcohols, high temperature lubricating oils, hydraulic fluids and glycol based control fluids. They have good resistance to sour petroleum products, steam. waters inorganic salts (including zinc bromide) and sodium hypochlorite. Some grades have better resistance to amine based corrosion inhibitors than Viton type FKM elastomers. • Not Recommended Volume swell in crude oils is somewhat high for a tetrafluoroelastomer (10 to 20%, compared with 1 to 5% for Vitons. Nitrile rubbers swell by some 10 to 35%). This can cause problems when using Aflas in a dynamic seal. Aflas is not resistant to chlorinated hydrocarbons.

2.6.3.2.1

FFKM PERFLUOROELASTOMER (KALREZ)

• Tradenames Kalrez DuPont Chemraz Greene Tweed These compounds have the chemical resistance properties of PTFE (Teflon) and the elastic properties of Vitons. The processing of both is exceptionally difficult. As a result of this, the price is much higher than fluoroelastomers. Thus, Kalrez and Chemraz (20% cheaper) are only used in applications where nothing else will survive. • Service Temperature 0°C to 260°C Kalrez -20°C to 230°C Chemraz • Recommended Service Kalrez has almost universal chemical resistance. It is resistant to sour petroleum products, acids, bases, steam and has excellent oxygen and weathering resistance. It has exceptionally low weight loss in high vacuum applications under high temperatures. Kalrez has poor strength and should be used with mechanical back up even at low temperatures. It is extremely difflcult to mould, and it is only recently that larger sections (up to 7.5 in.) have become available, e.g. for packer elements etc. Both Kalrez and Chemraz are only sold as fabricated units.

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HARD POLYMER MATERIALS (FOR BACK-UPS ETC)

The following materials cannot be used as primary seals.

2.6.4.1 PEEK POLYETHERETHERKETONE (PEEK) • Tradenames Victrex ICI Ltd Kadel Union Carbide • Service Temperature Up to 250°C continuously (315°C short term). • Recommended Service PEEK polymers are resistant to virtually all organic and aqueous chemicals. They exhibit significant chemical resistance and high performance at elevated temperatures. They are also tough and highly wear resistant. • Not Recommended Concentrated nitric or sulphuric acids at elevated temperature. • Physical Properties PEEK can be fabricated by conventional melt processing methods such as injection moulding, extrusion and melt spinning. It may be used in the virgin state or reinforced with glass or carbon fibres. • Recommended Service This unique combination of properties makes PEEK polymers attractive in a wide range of demanding applications. They are not elastomeric and are used as hard seals, back up rings, cable insulation and electrical components. In the oil industry they find uses as casings for various logging tools, support rings and anti-extrusion rings for downhole V- and O-ring seals. 2.6.4.2 FPM FLUOROCARBON POLYMERS (TEFLON PTFE ETC) These polymers are plastics rather than elastomers. The most useful of these types are listed below: • Tradenames • PTFE

Teflon Fluon Halon

DuPont Allied Chemical Co DuPont

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FEP, ETFE PFA PCTFE PVDF

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Tefzel

DuPont DuPont Kel-F 3M Co Foraflon Atochem Coflon Coflexip PVDF Furakawa Electric Co Kynar Pensalt Chemicals Teflon

• Service Temperature PTFE FEP, ETFE PFA PCTFE PVDF

-190°C

to -190°C -1 90°C to -60°C -60°C to

290°C to 200°C 280°C to 190°C 130°C (melts at 143°C)

• Recommended Service PTFE, FEP and ETFE can be regarded as chemically inert for all oilfield applications. The other compounds, although not totally inert, exhibit a high degree of resistance. Primarily used as back-up rings for elastomer seals.

2.6.4.3 PPS POLYPHENYLENE SULPHIDE (RYTON} • Tradename Ryton • Service Temperature Up to 230°C • Recommended Service Polyphenylene sulphide (Ryton) can be compounded with a variety of materials to reduce its brittle nature and to improve the sealability. It has been used for back up rings for V-packings and O-rings and, suitably compounded, it may be used as seal elements in V-packings.

2.7

FAILURE MECHANISM

This section outlines some of the failure modes that can occur in seals, how they are caused and how they can be corrected to prevent future failure.

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PAG

EXTRUSION DAMAGE

The pressure ranges given by the extrusion diagram in Figure 5 below, show allowable pressures for various degrees of elastomer hardness and indicate when to use back-up rings. 10000 8000

BASIS FOR CURVES

6000

1. No back-up rings 2. Total diametral clearance must include cylider expansion due to pressure 3. 100,000 cycles at rate of 150/1’ from zero to indiacated pressure

4000

Fluid pressure, lb/in2

3000 2000 EXTRUSION 1000 800 NO-EXTRUSION 600 400 300 hardness shore a durometer

200

70

80

90

100 0

0.08

0.16

0.16

0.24

0.32

0.40

Total diamentral clearance, in

Figure 5. Extrusion Resistance Related to Pressure and Hardness In its housing before pressurizing, an unsupported seal sits slightly deformed between the gland and sealing surface. On pressurizing (100 to 1500 psi), the seal acts like an incompressible fluid, exerting a pressure on the gland proportional to the system pressure and so forms a closure. If the system pressure exceeds the seal strength, a small volume of material will be forced into the clearance gap. This extrusion may lead to seal failure and leakage follows rapidly. Extrusion is characterised by a 'peeling' or 'nibbling' of the O-ring surface and is the most common cause of O-ring failure. This type of failure is exaggerated in dynamic applications where material is clamped in the clearance gap and sheared off completely. However, it must be remembered that in static applications, extrusion will occur at high pressures and is accentuated when pressures fluctuate and the seal housing components stretch under load.

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Resistance to extrusion for differing materials may be compared by using modulus values at 100% elongation. Alternatively, hardness may be used to select appropriate maximum pressure levels. For pressures above 1500 to 3000 psi, back up rings should be used. T-seals and V-seals always have back up rings associated with them, and extrusion is not such a problem as with unsupported O-rings. • Causes of extrusion failure: - Unnecessarily large clearances. - High pressure. - Soft seal material. - Physical or chemical changes which weaken/soften seal. - Eccentricity. - Sharp edges on seal size. - Wrong seal size. • Corrective actions: - Tighten tolerances. - Use a back up ring. - Increase seal material hardness. - Cheek medium compatibility. - Prevent eccentricity. - Strengthen machine parts to prevent ‘breathing'. - Gland radii from 0.10 to 0.40 mm. - Select T-seal or V-seal geometry with suitable back up.

2.7.2

COMPRESSION SET FAILURE

Compression set, the partial or total loss of elastic memory of an elastomer, is a common failure mode. It is characterized by a double sided flattening of a seal (radial or axial according to application) and can be clearly seen after disassembly. The problem is caused by selection of the wrong compound. The elasticity of a seal depends not only on the formulation, but also on the working temperature, type and length of deformation and ageing caused by a medium, e.g. air, steam, acid, petroleum etc. Compression set damage can be described as the loss of crosslink sites between the molecular chains or as the creation of new sites, brought about by temperature or chemical changes. Compression set damage clearly visible at low temperatures is generally reversible, and at higher temperatures, the elasticity may return to effect a seal again. The causes of high temperature compression set and loss in sealing power are connected and can be described as follows: • Causes of compression set failure: The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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- Seal compound has poor compression set. - Wrong gland dimensions. - Working temperature higher than expected. - Higher deformation through tight gland area. - Contact with non-compatible medium. (assembly grease or service fluid). - Poor seal material quality. • Corrective actions: - Select elastomer with low compression set. - Select elastomer according to working conditions. - Reduce system temperature at seal. - Cheek compatibility of seal with environment. - Use correct gland dimensions. 2.7.3 EXPLOSIVE DECOMPRESSION DAMAGE Under high pressure, gases will diffuse into elastomers. On rapid decompression, the absorbed gases expand quickly causing high levels of internal stress which may cause internal rupture and blistering to occur on the sealing surface. A seal may also swell on decompression, but with time may return to its original shape without leaving any external evidence of decompression damage. This is potentially dangerous since serious internal fissures can be present, but remain undetected, which will affect the sealing performance. • This problem may be solved or at least reduced in the following ways: - Lengthen the time for decompression. - Reduce working pressure at seal. - Design for smaller seal cross-section. - Select a seal material with higher strength, higher modulus and higher hardness. -Use specially compounded grades having known resistance to explosive decompression. Blister damage has been reported for a wide range of elastomers under hydrocarbon duties, particularly under gas alone but also in gas/oil mixtures. The presence of carbon dioxide and hydrogen sulphide is especially prone to causing problems on rapid decompression (they are both easily liquefiable gases and have solubility parameters approaching those of the elastomer seal materials). 2.7.4

WEAR

Wear is probably the most understandable form of seal failure in dynamic seals. In a static application, damage through wear is caused by pulsating pressure which induces the O-ring to abrade on relatively rough surfaces or edges of the gland. • Causes of wear failure: - Incorrect surface finish. - Poor lubrication. The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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IDENTIFICATION CODE

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- High temperature. - Too high deformation. - Impurities in system fluid. - High or pulsating pressure. • Corrective actions: - Correct surface finish. - Use a hard coated surface. - Select an improved machining process. - Change system fluid to one with better lubricity. - Select a compound with higher wear resistance. - Select a material with internal lubrication or design lubrication pockets or reservoirs. - Clean system and fllter fluid. 2.7.5 CHEMICAL DEGRADATION Chemical degradation depends on a number of factors which include temperature, concentration and duration of exposure. Mechanical properties of a seal material can be seriously changed by a chemical reaction. The timescale for the change is ultimately a function of the severity of service conditions and may be slowly progressive to catastrophically fast. Two different processes can occur when a seal is exposed to a chemical environment: • Bond scission results in chemical bonds being broken in the elastomer causing softening, weakness and a gummy seal material. • Crosslinking results in bond formation causing a harder, more brittle and often cracked seal. The elastic properties are often lost beyond a point where the seal ceases to function. Leak paths through a cracked seal can lead to failure. The effect of increased temperature will be to speed up the reaction rates, but more importantly the mechanical properties of an elastomer are normally reduced with increasing temperature. Hence, it is important to select materials with both sufficiently high chemical and thermal resistance. 2.7.6 ASSEMBLY FAILURE Even if all the above hints and rules are observed, failure can still occur due to poor workmanship practices adopted on assembly of the seal into its housing. A seal is a precision product and should be treated with respect. Careful assembly will repay the user in trouble free operation. The alternative is an expensive and possibly dangerous failure. • Causes of assembly failures: - Using undersized seal. - Twisting, cutting or shearing of seal. - Assembly without the correot tool. - Assembly without lubrication (care - compatibility). - Assembly in dirty conditions. The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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• Corrective actions: - Break all sharp edges. - Leading edge chamfer in between 15 to 20 degrees. - Cleanliness. - Cheek seal size before assembly. - Assembly as a stack of seals where possible.

2.8

SEALS SELECTION

This section gives a summary description of types of downhole seal arrangements with an example set of typical seals and notes on materials qualification. 2.8.1

COMPLETION SEALS

The three basic seal types are as follows: • Radial compression seals, e.g. O-rings and T-seals, are used in both static and dynamic applications. O-rings are typically used as static body connection seals, both with or without back up rings as dictated by the pressure and temperature. T-seals are normally used as dynamic seals to take advantage of the unique design to limit rolling in the gland. They always incorporate back-up rings. • Axial compression seals are used as packer element seals. Elements are set after the packer is run to the desired depth in the well. The large cross-section of the seals when set, bridge large extrusion gaps and seals against poor casing surface finishes. • Pressure energized seals. such as V-packing stacks. are used in both static stab and dynamic applications. such as the external seals on wireline safety valves, lock and gas lift valves. A typical set of seals for a ‘difficult well’ is given in the example below. The actual nature and hardness of the seal material chosen will depend on the application and the service duty. • O-rings • T-Seals • V-Packing

Viton 95A durometer with PEEK back-ups Viton with PEEK back-ups Aramid fibre reinforced Nitrile used in combinations with other rings of molybdenum disulphide reinforced Teflon, Ryton and PEEK Moly reinforced Teflon or 90A durometer Viton for sandy • Soft seats service Nitrile • Packer Elements Many other material and seal options are available.

2.8.2 QUALIFICATION

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Proven field history is the best qualification. Laboratory simulation tests are available. Agip TEAP or CORM can make evaluate various material performance properties after exposure to a wide range of service conditions, for candidate materials. Facilities are available to screen materials for environmental resistance to both fluids and gases up to 20 000 psi and 200°C with up to 25% H2S concentration coupled with decompression control. Equipment manufacturers should conduct pressure tests on the final products. For example. API Standard 14A requires a 10 minute pressure test at 150% of the rated pressure and two growth tests of 2 hours for stab in or dynamic seals. Repeated decompression tests may also be carried out. It is better to evaluate the material in the seal configuration wherever possible. Quality control is essential to good sealing practice. Suppliers should be approved by the Quality Assurance Department, should have a QA programme that meets industry standards and all seals should be traceable to the material batch. Routine quality control tests should be performed to assure that each shipment of seals meet the specifications. These should then be verified by the suppliers inspector who will issue certificates of compliance and actual test reports on each shipment of seals. The following information should be obtained from the equipment manufacturer for possible future reference: • Seal equipment type (Unit, maker, drawings) • Seal design (Static/dynamic, O-ring, V-ring,T-ring) Seal material (Class, grade, supplier, part no, batoh no, cure date shelf life)

2.9

MATERIAL SELECTION CRITERIA

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IDENTIFICATION CODE

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The listed physical properties are desirable in the following applications: • Dynamic seals require: - Good abrasion resistance. - Good tear resistance. - Good compression set resistance. - Good gas impermeability. - Good resilience. Static seals primarily require: • - Good compression set resistance. Packing elements require: • - Good compression set resistance. - Resistance to swelling is not most important. Indeed a small degree of swelling may be beneficial. MATERIALS SELECTIONS BASED ON HEAT AND OIL RESISTANCES Temp. ASTM Ref. Material Class Upper Lower Oil Level Code Resistance °C °F °C °F < 150 °F NR Natural rubber 65 149 -50 -58 Bad Poor -49 -45 212 100 Neoprene CR 200 °F Poor -22 -30 221 105 Polyurethane AE/AU to Good -22 -30 248 120 Nitrile Rubber NBR 250 °F Good -40 -40 275 135 Hydrin ECO/CO 250F Very Good -76 -60 284 Coflon back-up 140 PVDF to -13 Fair -25 Therban 150 302 HBNR 300 °F -50 -58 Bad 302 EPDM Nordel 150 -55 -67 Bad 347 SI Silicone 175 300 °F Good 374 -40 -40 190 to FSI Fluorosilicone Very Good -4 200 392 -20 Viton 400 °F FKM Very Good -190 -310 Tefzelback-up 200 392 ETFE 400 °F FCM Aflas 230 446 -40 -40 Good to PEEK Vyctrex back250 482 Very Good 500°F FFKM up 260 500 0 32 Very Good Karlez > 500°F PTFE Teflon back-up 290 554 -190 -310 Very Good Table 4 Any equipment which experiences temperature fluctuations of greater than 100 to 150°F should utilize elastomers with good compression set resistance over the range of temperature. Aflas, Kalrez and Viton GF are particularly prone to failures under these situations.

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ENI S.p.A. Divisione Agip

ORGANIZING DEPARTMENT

TEAP

TYPE OF ACTIVITY'

P

ISSUING DEPT.

1

DOC. TYPE

R

REF. N.

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ENVIROMENTAL RESISTANCE AND PHISICAL PROPERTIES FOR COMMON DOWNHOLE SEAL MATERIAL (ELASTOMERIC AND PLASTIC) IN COMPLETION EQUIPMENT SERVICES Material CR AE/AU NBR ECO PVDF HNBR EPDM FKM ETFE FCM PEEK FFKM PTFE Neoprene Urethane Nitrile Rubber Hydrin Coflon Therban Nordel Viton Tefzel Aflas Victrex Kalrez Teflon Upper Service Temp °C 100 105 120 135 140 150 150 200 200 230 250 260 290 Lower Service Temp °C 45 -30 -30 -40 -60 -25 -50 -20 -190 -40 0 -190 Oil Aliphatic Hydrocarbons 2 2 1 1 1 2 4 1 1 1 1 1 1 Aromatic Hydrocarbons 3 3 2 1 1 3 4 1 1 2 1 1 1 Crude Oil (120 °C) 4 4 4 4 2 3 4 2 1 2 1 1 1 Sour Crude Oil 3 3 2 3 1 2 4 2 1 2 1 2 1 Sour Natural Gas 3 3 2 3 1 2 3 2 1 2 1 2 1 Water 2 1 2 1 1 1 1 2 1 1 1 1 1 Steam 3 3 3 2 1 1 1 1 1 1 1 1 1 Inibitors Amines 3 2 2 2 1 2 2 3 1 1 1 1 1 Completion Fluids CaCl/Ca/Br 1 1 1 1 1 1 1 1 1 1 1 1 1 Completion Fluids ZnBr 1 1 4 1 1 3 1 1 1 1 1 1 1 Completion Fluids Kr2CO3 1 2 2 2 2 1 1 1 1 1 1 1 1 Brine Seawater 2 4 1 1 1 1 1 1 1 1 1 1 1 Control Fluid Mineral Oil 2 1 1 1 1 1 3 1 1 2 1 1 1 Control Fluid Glycol based 1 2 1 1 1 1 1 1 1 1 1 1 1 Alcohols Methanol 1 4 1 1 1 1 1 4 1 1 1 1 1 Acids Hcl Acid (diluted) 3 2 3 1 1 2 1 1 1 1 1 1 1 Acids Hcl Acid (concentred) 4 4 4 3 2 4 3 1 1 1 2 1 1 Acids Hcl Acid ( 5.000 ≤ 10.000 > 10.000

PISTON (DYNAMIC SEAL) NO-ELASTOMER NO-ELASTOMER

FLAPPER

STATIC SEAL

NO-ELASTOMER METAL TO METAL

METAL TO METAL METAL TO METAL

METAL TO METAL STOP SEALS NO YES

METAL SEAL

METAL TO METAL

METAL TO METAL

YES

B.2.) CORROSIVE SITUATIONS (H2S, and/or CO2) W.P. psi ≤ 5.000 > 5.000 C)

PISTON (DYNAMIC SEAL) NO-ELASTOMER METAL SEAL

FLAPPER

STATIC SEAL

NO-ELASTOMER METAL TO METAL

METAL TO METAL METAL TO METAL

METAL TO METAL STOP SEALS YES YES

EQUALIZING

Self-equalizing mechanism is generally not a benefit even in case of unattended platform because the reopening of the SCSSV can not be acted by an automatic/remote operation and needs the operator assistance. Sometimes it’s an advantage (for instance sub-sea wells); in this case, equalizing system should be qualified with a particular procedure. D)

ATTUATION SYSTEMS

Rod piston design is recommended against concentric piston for two main reasons: 1) More reliability because a metal to metal stop seals can be utilized 2) Possibility of deepset installation. Note: “Metal seal” means a composite seal mechanism, provided with a thermoplastic back-up. TAB. 1 NACE? HIGH H2S CONCENTRATION CLOSE PROXIMITY? STATIC BOTTOM HOLE PRESSURE (PSI)? 5.000 AND LESS

>5.000; ≤ 10.000 >10.000

NO NO

YES NO

YES YES

YES NO

NO NO

YES YES

NO

NO

NON

YES

YES

YES

W.P. STHP X S.F.

W.P. STHP X S.F.

W.P. STHP X S.F. SBHP SBHP

W.P. STHP X S.F. SBHP SBHP

W.P. STHP X S.F. SBHP SBHP

W.P. STHP X S.F.

SBHP

SBHP

SBHP SBHP

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ENCLOSURE 1 A5.1a, NACE? This applies to the partial pressure of hydrogen sulfide (H2S) in the produced fluid as defined by NACE Std. MR 01-75. A5.1b High H2S concentration? Use “Yes” if the 100 ppm radius of exposure (ROE) of H2S is greather than 50 feet from the wellhead. ROE is defined in section 6 of this appendix. A5.1c. Close Proximity? This proximity assessment should consider the potential impact of an uncontrolled condition on life and environment near the wellhead. The following list of items can be used for determining potential risk. Items for additional consideration should be included when necessary. (1) 100 ppm radius of exposure (ROE) of H2S is greater than 50 ft from the wellhead and includes any part of a public area except a public road. ROE is defined in Paragraph 6 of this appendix. Public area shall mean a dwelling, place of business, church, hospital, school, bus stop, government building, a public road, all or any portion of a park, city, town, village, or other similar area that one can expect to be populated. Public road shall mean any federal, state, county or municipal street or road owned or aintened for public access or use. (2) 500 ppm ROE of H2S is greater than 50 ft. from the wellhead and includes any part of a public area including a public road (3) Well is located in any environmentally sensitive area such as parks, wildlife preserve, city limits, etc. (4) Well is located within 150 ft. of an open flame or fired equipment. (5) Well is located within 50 ft. of a public road (lease road excluded). (6) Well is located in state or federal waters. (7) Well is located in or near inland navigable waters. (8) Well is located in or near surface domestic water supplies. (9) Well is located within 350 ft. of any dwelling. These conditions are recommended minimum considerations. It will be necessary to meet any local regulatory requirements. A6.1. The following information is taken from Texas Railroad Commission Rule 36: A6.1a. For determining the location of the 100 ppm radius of exposure: X = [( 1.589) (mole fraction H2S) (Q)]0.6258 A6.1b. For determining the location of the 100 ppm radius of exposure: X = [(0.4546) (mole fraction H2S) (Q)]0.6258 Where: X = Radius of exposure in feet The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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Q = Maximum volume determined to be available for escape in cubic feet per day. H2S = Mole fraction of hydrogen sulfide in the gaseous mixture available for escape. A6.1c. The volume used as the escape rate in determining the radius of exposure shall be that pecified below, s is applicable: (1) For the new wells in developed areas, the escape rate shall be determined by using the current adjusted open-flow rate of offset wells, or the field average current adjusted open low rate, whichever is larger. (2) The escape rate used in determining the radius of exposure shall be corrected to standard nditions of 14.65 psia and 60 degrees Fahrenheit. A6.1d. When a well is in an area where insufficient data exist to calculate a radius of exposure, ut where hydrogen sulfide may be expected, a 100 ppm radius of exposure equal to 3000 eet shall be assumed. ENCLOSURE 2 The following definitions are referred to safety valves. A)

WORKING PRESSURE : It’s the maximum pressure that the closure mechanism (flapper) can withstand

B)

TEST PRESSURE : It’s the test pressure the “pressure containing parts” of the valve are subjected to in order to verify the “seal integrity” of the assembly. Normally it’s 150% of the working pressure.

C)

CONTROL CHAMBER PRESSURE: It’s the fluid control pressure (piston chamber).

During the test defined in B) the flapper valve is kept open. To mantain the flapper opened, the “control Chamber” pressure is 150% of (working pressure plus the opening valve pressure). From all what has been sad, it’s evident that, during the transit opening time, the possible exceeding of valve W.P. should not cause any damage to the integrity and sealing performance of the valve.

The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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DOWNHOLE SAFETY VALVES - INSTALLATION GUIDELINES

This document, operative in Italy since one year, will be in a short period of time issued to all Agip Overseas branches. 7.9.1

APPLICATION

Safety valve installation is considered mandatory for any well, and it’s required they are always surface controlled in following cases: 1) OIL PRODUCER WELLS a. All new off-shore wells b. All new on-shore naturally producing wells c. All wells liable to workover in a and b d. All isolated wells 2) GAS PRODUCER WELLS e. All new off-shore and on-shore wells f. All wells liable to workover 3)STORAGE WELLS g. All wells 4) GAS INJECTION WELLS h. All wells 5) WATER INJECTION WELLS i. All wells where injection has done in hydrocarbon levels l. All off-shore wells 6) ARTIFICIAL LIFT WELLS m. All gas lift wells (tubing and annulus) and electrical submersible pump (always tubing; annulus only where there is gas ventingis present in the annulus) NOTE: If there is H2S in produced fluids, safety valves shall always be surface controlled.

7.10

VALVE TYPE

Following selection criteria will be adopted in the design of new development. In existing installations where the surface controlled safety valve is not in agreement with this note, the configuration will be kept untill first foreseen workover (during workover planning, the economics of the possible adjusting have to be evalued). 1) TUBING RETRIEVABLE - (FLAPPER TYPE) off-shore rig wells subsea off-shore wells H2S and/or CO2 corrosion wells wells with Flowing Tubing Head Temperature higher than 130°C wells where Max Shut In Head pressure is higher than 350 bar wells where asphaltene deposit, scales or idrate formation are foreseen sand producer wells storage wells 2) WIRELINE RETRIEVABLE - (FLAPPER TYPE) always as back-up to tubing retrievable (in an economically congruent number in the field)

3) STORM CHOKES The present document is CONFIDENTIAL and it is the property of ENI It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

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as back-up of previous systems, it’s installed on polished bore of the main valve or on a landing nipple bore foreseen deeper than the valve to be setting depth in wells where a workover for valve substitution cannot be planned in a short period of time.

4) ANNULAR SAFETY SYSTEM FOR ARTIFICIAL LIFT WELLS gas lift wells ESP LIFT wells where annulus gas venting is foreseen. lift wells with jet pumps just below it, operated by the jet pump power fluid 5) INJECTION VALVE all waste water injection wells.

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IDENTIFICATION CODE

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TEAP-P-1-R-8796 Figure.10

START HERE

STATIC BOTTOM HOLE PRESSURE > 10000 PSI

YES

HIGH H2S CONCENTRA TION ?

SBHP

YES

NO NO CLOSE PROXIMITY?

SBHP

YES

NO

SBHP > 5.000 PSI

YES NACE?

HIGH H2S CONCENTRA TION ?

YES

YES STATIC BOTTOM HOLE PRESSURE

SBHP

CLOSE PROXIMITY? NO

SBHP 5.000 PSI

5.000 PSI

STHPxS.F.

> 5.000 PSI